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As filed with the Securities and Exchange Commission on May 13, 2014

Registration No. 333-194970

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 2 to

FORM F-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Abengoa Yield plc

(Exact name of Registrant as specified in its charter)

 

 

Not Applicable

(Translation of Registrant’s name into English)

 

 

 

England and Wales		4911		Not applicable
(State or other jurisdiction of incorporation or organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification No.)

1 Park Row

Leeds, United Kingdom LS1 5AB

Tel.: +34 954 937 111

(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)

 

 

Abengoa Solar LLC

1250 Simms St., #101

Lakewood, CO 80401

Tel.: (303) 928 8500

Attn.: Christopher B. Hansmeyer

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies of all communications, including communications sent to agent for service, should be sent to:

 

Jeffrey C. Cohen Linklaters LLP 1345 Avenue of the Americas New York, New York 10105 Phone: (212) 903-9000		Michael J. Willisch Davis Polk & Wardwell LLP Paseo de la Castellana, 41 28046 Madrid Phone: + 34 91 768 9610

 

 

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after this registration statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

 

 

Calculation of Registration Fee

 

Title of Each Class of Securities to be Registered		Proposed Maximum Aggregate Offering  Price(1)(2)		Amount of Registration Fee(3)
Ordinary Shares, nominal value $0.10 per share		$600,000,000		$77,280

(1)	Estimated solely for the purpose of computing the amount of the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

(2)	Includes the aggregate offering price of additional shares that may be purchased by the underwriters.

(3)	Previously paid.

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to Section 8(a), may determine.

 

 

 

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The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

Subject to Completion, dated                 , 2014.

Preliminary Prospectus

             Ordinary Shares

 

(Incorporated in England and Wales)

Ordinary Shares

$             per share

 

 

This is the initial public offering of the ordinary shares of Abengoa Yield plc, or Abengoa Yield. We were recently formed by Abengoa, S.A., or Abengoa. We refer to this offering of ordinary shares, or the shares, as the “offering.”

We currently expect that the initial public offering price per share will be between $             and $            .

Immediately following this offering, Abengoa will indirectly hold         % of the voting power in Abengoa Yield. As a result, we will be a “controlled company” within the meaning of the corporate governance standards of the NASDAQ Global Select Market.

We have applied to list our shares on the NASDAQ Global Select Market under the symbol “ABY”.

We are an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act of 1933, as amended, and, as such, are allowed to provide in this prospectus more limited disclosures than an issuer that would not so qualify. In addition, for as long as we remain an emerging growth company, we will qualify for certain limited exceptions from the Sarbanes-Oxley Act of 2002. Please see “Risk Factors—Risks Related to Ownership of our Shares—We are an “emerging growth company” and may elect to comply with reduced public company reporting requirements, which could make our shares less attractive to investors” and “Summary—JOBS Act.”

 

 

Investing in our shares involves risks. See “Risk Factors” beginning on page 37 of this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

 

		Per Share				Total
Public Offering Price		$				$
Underwriting Discounts		$				$
Proceeds to Abengoa Yield, before expenses		$				$

The underwriters expect to deliver the shares to purchasers on or about                     , 2014 through the book-entry facilities of The Depository Trust Company.

To the extent that the underwriters sell more than              shares, the underwriters have the option to purchase up to an additional              shares from an Abengoa subsidiary at the public offering price less the underwriting discount. We will not receive any proceeds from the exercise of the underwriters’ over-allotment option.

 

Citigroup				BofA Merrill Lynch

The date of this prospectus is                     , 2014.

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TABLE OF CONTENTS

 

		Page
Enforcement of Civil Liabilities			1
Definitions			1
Presentation of Financial Information			3
Presentation of Industry and Market Data			4
Cautionary Statements Regarding Forward-Looking Statements			6
Summary			8
The Offering			30
Summary Combined Financial Information			32
Risk Factors			37
Use of Proceeds			64
Cash Dividend Policy			65
Capitalization			79
Dilution			80
Unaudited Pro Forma Combined Financial Information			82
Selected Financial Information			88
Management’s Discussion and Analysis of Financial Condition and Results of Operations			94
Industry and Market Opportunity			125
Business			134
Regulation			160
Management			185
Related Party Transactions			191
Principal and Selling Shareholder			198
Description of Share Capital			199
Shares Eligible for Future Sale			214
Taxation			216
Underwriting			222
Expenses of the Offering			228
Legal Matters			229
Experts			230
Where You Can Find More Information			231
Combined Financial Statements			F-1

We are responsible for the information contained in this prospectus and in any free-writing prospectus we prepare or authorize. We have not authorized anyone to provide you with different information, and we take no responsibility for any other information others may give you. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than its date.

 

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ENFORCEMENT OF CIVIL LIABILITIES

We are a public limited company organized under the laws of England and Wales. A majority of our directors and officers and certain other persons named in this prospectus reside outside the United States and all or a significant portion of the assets of the directors and officers and certain other persons named in this prospectus and a significant portion of our assets is located outside the United States.

As a result, it may not be possible for U.S. investors to effect service of process within the United States upon these persons or to enforce against them or against us in U.S. courts judgments predicated upon the civil liability provisions of the federal securities laws of the United States. There is doubt as to the enforceability in the United Kingdom and in Spain, either in original actions or in actions for enforcement of judgments of U.S. courts, of civil liabilities predicated on the U.S. federal securities laws.

DEFINITIONS

Unless otherwise specified or the context requires otherwise in this prospectus:

 

•

references to “we,” “us,” the “Issuer” and “our” refer to Abengoa Yield plc, including the assets and liabilities to be contributed to us by Abengoa immediately prior to the consummation of the offering, unless the context otherwise requires;

 

•

references to “Abengoa” refer to Abengoa, S.A., together with its subsidiaries, unless the context otherwise requires;

 

•

references to “Abengoa ROFO Assets” refer to all of the future contracted assets in renewable energy, conventional power, electric transmission and water of Abengoa in the United States, Canada, Mexico, Chile, Peru, Uruguay, Brazil, Colombia and the European Union, and four additional assets in other selected regions, including a pipeline of specified assets that we except to evaluate for acquisition in 2015, 2016 and beyond, for which Abengoa will provide us a right of first offer to purchase if offered for sale by Abengoa;

 

•

references to “ACBH” refer to Abengoa Concessoes Brasil Holding, a subsidiary holding company of Abengoa that is engaged in the development, construction, investment and management of contracted concessions in Brazil, comprised mostly of transmission lines;

 

•

references to “Adjusted EBITDA” have the meaning set forth in “Presentation of Financial Information”;

 

•

references to “Annual Combined Financial Statements” refer to the audited Combined Financial Statements as of and for the years ended December 31, 2013 and 2012 (which include a statement of financial position as of January 1, 2012), including the related notes thereto, prepared in accordance with IFRS as issued by the IASB (as such terms are defined herein), included in this prospectus;

 

•

references to “BOOT” refer to build-own-operate-transfer arrangements;

 

•

references to “cash available for distribution” have the meaning set forth in “Cash Dividend Policy”;

 

•

references to “COD” refer to commercial operation date of the applicable facility;

 

•

references to “CSP” refer to Concentrating Solar Power;

 

•

references to “DOE” refer to the U.S. Department of Energy;

 

•

references to “EPC” refer to engineering, procurement and construction;

 

•

references to “euro” or “€” are to the single currency of the participating member states of the European and Monetary Union of the Treaty Establishing the European Community, as amended from time to time;

 

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•

references to “Executive Services Agreement” refer to the agreement we will enter into with Abengoa pursuant to which Abengoa will arrange for a team of executives to provide executive management services to Abengoa Yield in the year following the consummation of this offering;

 

•

references to “FPA” refer to the U.S. Federal Power Act;

 

•

references to “Further Adjusted EBITDA” have the meaning set forth in “Presentation of Financial Information”;

 

•

references to “gross capacity” or “gross MW” refer to the maximum, or rated, power generation capacity, in MW, of a facility or group of facilities, without adjusting by our percentage of ownership interest in such facility as of the date of this prospectus;

 

•

references to “GW” refer to gigawatts;

 

•

references to “IFRS as issued by the IASB” refer to International Financial Reporting Standards as issued by the International Accounting Standards Board;

 

•

references to “Interim Combined Financial Statements” refer to the unaudited Interim Combined Condensed Financial Statements as of March 31, 2014 and for the three-month periods ended March 31, 2014 and 2013, prepared in accordance with IFRS as issued by the IASB (as such terms are defined herein), included in this prospectus;

 

•

references to “IPP” refer to independent power producers;

 

•

references to “ITC” refer to investment tax credits;

 

•

references to “membership interest” refer to ownership interest in the applicable entity, including such economic interest and right, if any, to participate in the management of the business and affairs of the entity, including the right, if any, to vote on, consent to or otherwise participate in any decision or action of or by the members of the entity and the right to receive information concerning the business and affairs of the entity, in each case to the extent expressly provided in the relevant operating agreement;

 

•

references to “MW” refer to megawatts;

 

•

references to “MWh” refer to megawatt hours;

 

•

references to “O&M” refer to operations and maintenance services provided at our various facilities;

 

•

references to “operation” refer to the status of projects that have reached COD (as defined above);

 

•

references to “pre-construction” refer to the status of projects for which a PPA is in place and for which financing arrangements are in the process of being implemented;

 

•

references to “PV” refer to photovoltaic;

 

•

references to “PPA” refer to the power purchase agreements through which our power generating assets have contracted to sell energy to various offtakers;

 

•

references to “ROFO Agreement” refer to our agreement with Abengoa that will provide us a right of first offer to purchase any of the Abengoa ROFO Assets offered for sale by Abengoa;

 

•

references to “RPS” refer to renewable portfolio standards adopted by 29 states and the District of Columbia that require a regulated retail electric utility to procure a specific percentage of its total electricity delivered to retail customers in the state from eligible renewable generation resources, such as solar or wind generation facilities, by a specific date;

 

•

references to “Support Services Agreement” refer to the agreement we have entered into with Abengoa pursuant to which Abengoa will provide certain administrative and support services to us and some of our subsidiaries;

 

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•

references to “total net fixed assets” refer to the sum of intangible assets and property, plant and equipment, and fixed assets and projects, net of depreciation, amortization and provisions for impairment charges; and

 

•

references to “TWh” refer to terawatt hours.

PRESENTATION OF FINANCIAL INFORMATION

The selected financial information as of March 31, 2014 and for the three-month periods ended March 31, 2014 and 2013 is derived from, and qualified in its entirety by reference to, our Interim Combined Financial Statements and our unaudited pro forma combined financial information, which are included elsewhere in this prospectus, which are prepared in accordance with IFRS as issued by the IASB.

The selected financial information as of and for the years ended December 31, 2013 and 2012 and as of January 1, 2012 is derived from, and qualified in its entirety by reference to, our Annual Combined Financial Statements and our unaudited pro forma combined financial information, which are included elsewhere in this prospectus, which are prepared in accordance with IFRS as issued by the IASB.

Our Interim Combined Financial Statements and our Annual Combined Financial Statements reflect the combination of certain of the assets and associated liabilities that Abengoa will contribute to us immediately prior to the consummation of the offering.

Certain numerical figures set out in this prospectus, including financial data presented in millions or thousands and percentages describing market shares, have been subject to rounding adjustments, and, as a result, the totals of the data in this prospectus may vary slightly from the actual arithmetic totals of such information. Percentages and amounts reflecting changes over time periods relating to financial and other data set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” are calculated using the numerical data in our Interim Combined Financial Statements and our Annual Combined Financial Statements or the tabular presentation of other data (subject to rounding) contained in this prospectus, as applicable, and not using the numerical data in the narrative description thereof.

Non-GAAP Financial Measures

This prospectus contains non-GAAP financial measures including Adjusted EBITDA, Further Adjusted EBITDA and cash available for distribution.

Adjusted EBITDA is calculated as profit for the year from continuing operations, after adding back income tax expense/(benefit), share of (loss)/profit of associates, finance expense net and depreciation, amortization and impairment charges of entities included in the Interim Combined Financial Statements and the Annual Combined Financial Statements.

Further Adjusted EBITDA is calculated as profit for the year from continuing operations, after adding back income tax expense/(benefit), share of (loss)/profit of associates, finance expense net (excluding the net income from our exchangeable preferred equity investment in ACBH) and depreciation, amortization and impairment charges of entities included in the Interim Combined Financial Statements and the Annual Combined Financial Statements.

Cash available for distribution is calculated as set forth in “Cash Dividend Policy—General—Estimate of Future Cash Available for Distribution.”

We present non-GAAP financial measures because we believe that they and other similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance and liquidity. The non-GAAP financial measures may not be comparable to other similarly titled measures of other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our operating results as reported under IFRS as issued by the IASB. Non-GAAP financial measures and ratios are not measurements of our performance or liquidity under IFRS as issued by the IASB and should not be considered as alternatives to operating profit or profit for the year or any other performance measures derived in accordance with IFRS as issued by the IASB or any other generally accepted accounting principles or as alternatives to cash flow from operating, investing or financing activities.

 

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Some of the limitations of these non-GAAP measures are:

 

•

they do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

 

•

they do not reflect changes in, or cash requirements for, our working capital needs;

 

•

they may not reflect the significant interest expense, or the cash requirements necessary, to service interest or principal payments, on our debts;

 

•

although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often need to be replaced in the future and Adjusted EBITDA, Further Adjusted EBITDA and cash available for distribution do not reflect any cash requirements that would be required for such replacements;

 

•

some of the exceptional items that we eliminate in calculating Adjusted EBITDA, Further Adjusted EBITDA and cash available for distribution reflect cash payments that were made, or will be made in the future; and

 

•

the fact that other companies in our industry may calculate Adjusted EBITDA, Further Adjusted EBITDA and cash available for distribution differently than we do, which limits their usefulness as comparative measures.

In our discussion of operating results, we have included foreign exchange impacts in our revenue by providing constant currency revenue growth. The constant currency presentation is a non-GAAP financial measure, which excludes the impact of fluctuations in foreign currency exchange rates. We believe providing constant currency information provides valuable supplemental information regarding our results of operations. We calculate constant currency amounts by converting our current period local currency revenue using the prior period foreign currency average exchange rates and comparing these adjusted amounts to our prior period reported results. This calculation may differ from similarly titled measures used by others and, accordingly, the constant currency presentation is not meant to substitute for recorded amounts presented in conformity with IFRS as issued by the IASB nor should such amounts be considered in isolation.

Pro Forma Financial Information

We present in this prospectus unaudited pro forma combined financial information consisting of the unaudited pro forma combined income statement of Abengoa Yield for the three-month period ended March 31, 2014 and for the years ended December 31, 2013 and 2012 as well as the unaudited pro forma combined statement of financial position of Abengoa Yield as of March 31, 2014 to give effect to the consolidation of Mojave, the transfer of a preferred equity investment in ACBH, the contribution of certain related party loans that have occurred or we expect to occur prior to the consummation of this offering, the repayment of debt to a related party (a third party prior to March 31, 2014) and a reduction of equity that have occurred or we expect to occur prior to the consummation of this offering and the proceeds from this offering that will be retained by us to strengthen our liquidity position.

Unaudited pro forma combined financial information has been derived from, and should be read in conjunction with, the Interim Combined Financial Statements and the Annual Combined Financial Statements prepared in accordance with IFRS as issued by the IASB, included elsewhere in this prospectus.

PRESENTATION OF INDUSTRY AND MARKET DATA

In this prospectus, we rely on, and refer to, information regarding our business and the markets in which we operate and compete. The market data and certain economic and industry data and forecasts used in this prospectus were obtained from internal surveys, market research, governmental and other publicly available

 

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information, independent industry publications and reports prepared by industry consultants. Industry publications, surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable, but that the accuracy and completeness of such information is not guaranteed. We believe that these industry publications, surveys and forecasts are reliable but we have not independently verified them, and there can be no assurance as to the accuracy or completeness of the included information.

Certain market information and other statements presented herein regarding our position relative to our competitors are not based on published statistical data or information obtained from independent third parties, but reflect our best estimates. We have based these estimates upon information obtained from our customers, trade and business organizations and associations and other contacts in the industries in which we operate.

Elsewhere in this prospectus, statements regarding our contracted concessions activities, our position in the industries and geographies in which we operate are based solely on our experience, our internal studies and estimates and our own investigation of market conditions.

All of the information set forth in this prospectus relating to the operations, financial results or market share of our competitors has been obtained from information made available to the public in such companies’ publicly available reports and independent research, as well as from our experience, internal studies, estimates and investigation of market conditions. We have not funded, nor are we affiliated with, any of the sources cited in this prospectus.

All third-party information, as outlined above, has to our knowledge been accurately reproduced and, as far as we are aware and are able to ascertain, no facts have been omitted which would render the reproduced information inaccurate or misleading, but there can be no assurance as to the accuracy or completeness of the included information.

 

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CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

This prospectus includes forward-looking statements. These forward-looking statements include, but are not limited to, all statements other than statements of historical facts contained in this prospectus, including, without limitation, those regarding our future financial position and results of operations, our strategy, plans, objectives, goals and targets, future developments in the markets in which we operate or are seeking to operate or anticipated regulatory changes in the markets in which we operate or intend to operate. In some cases, you can identify forward-looking statements by terminology such as “aim,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “guidance,” “intend,” “is likely to,” “may,” “plan,” “potential,” “predict,” “projected,” “should” or “will” or the negative of such terms or other similar expressions or terminology.

By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future. Forward-looking statements speak only as of the date of this prospectus and are not guarantees of future performance and are based on numerous assumptions. Our actual results of operations, financial condition and the development of events may differ materially from (and be more negative than) those made in, or suggested by, the forward-looking statements. Investors should read the section entitled “Risk Factors” and the description of our segments and business sectors in the section entitled “Business” for a more complete discussion of the factors that could affect us. Important risks, uncertainties and other factors that could cause these differences include, but are not limited to:

 

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Changes in general economic, political, governmental and business conditions globally and in the countries in which we do business;

 

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Difficult conditions in the global economy and in the global market and uncertainties in emerging markets where we have international operations;

 

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Decreases in government expenditure budgets, reductions in government subsidies or adverse changes in laws affecting our businesses and growth plan;

 

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Challenges in achieving growth and making acquisitions due to our dividend policy;

 

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Decline in public acceptance or support of energy from renewable sources;

 

•

Inability to identify and/or consummate future acquisitions, whether the Abengoa ROFO Assets or otherwise, on favorable terms or at all;

 

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Legal challenges to regulations, subsidies and incentives that support renewable energy sources;

 

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Extensive governmental regulation in a number of different jurisdictions, including stringent environmental regulation;

 

•

Changes in prices, including increases in the cost of energy, natural gas, oil and other operating costs;

 

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Counterparty credit risk and failures of counterparties to our offtake agreements to fulfill their obligations;

 

•

Inability to replace expiring or terminated offtake agreements with similar agreements;

 

•

Changes in interest rates and foreign currency exchange rates;

 

•

New technology or changes in industry standards;

 

•

Inability to manage exposure to credit, interest rate, exchange rate, supply and commodity price risks;

 

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Reliance on third-party contractors and suppliers;

 

•

Deviations from our investment criteria for future acquisitions and investments;

 

•

Failure to maintain safe work environments;

 

•

Effects of catastrophes, natural disasters, adverse weather conditions, climate change, unexpected geological or other physical conditions, or criminal or terrorist acts at one or more of our plants;

 

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•

Insufficient insurance coverage and increases in insurance cost;

 

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Revocation or termination of our concession agreements;

 

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Litigation and other legal proceedings;

 

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Reputational risk, including damage to the reputation of Abengoa;

 

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Inability to adjust regulated tariffs or fixed-rate arrangements as a result of fluctuations in prices of raw materials, exchange rates, labor and subcontractor costs;

 

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Lack of electric transmission capacity and potential upgrade costs to the electric transmission grid;

 

•

Variations in market electricity prices;

 

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Loss of senior management and key personnel and our reliance on Abengoa to supply administrative, financial, executive and other support services to us;

 

•

Disruptions in our operations as a result of our not owning the land on which our assets are located;

 

•

Disruption of the fuel supplies necessary to generate power at our conventional generation facilities;

 

•

Failure of our newly-constructed assets or assets under construction to perform as expected;

 

•

Failure to receive dividends from all project and investments;

 

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Variations in meteorological conditions;

 

•

Changes in our tax position and greater than expected future tax liability;

 

•

Changes to our relationship with Abengoa; and

 

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Various other factors, including those factors discussed under “Risk Factors” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition” herein.

We caution that the important factors referenced above may not be all of the factors that are important to investors. Unless required by law, we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or developments or otherwise.

 

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RISK FACTORS

Investing in our shares involves a high degree of risk. You should carefully consider the risks and uncertainties described below, together with the other information contained in this prospectus, before making any investment decision. Any of the following risks and uncertainties could have a material adverse effect on our business, prospects, results of operations and financial condition. The market price of our shares could decline due to any of these risks and uncertainties, and you could lose all or part of your investment.

Risks Related to Our Business and the Markets in Which We Operate

Difficult conditions in the global economy and in the global capital markets have caused, and may continue to cause, a sharp reduction in worldwide demand for our products and services and negatively affect our access to the levels of financing necessary for the successful refinancing of our project level indebtedness

Our results of operations have been, and continue to be, materially affected by conditions in the global economy and in the global capital markets. Concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, sovereign debt and the instability of the euro have contributed to increased volatility and diminished expectations for the economy and global capital markets going forward. These factors, combined with volatile oil and gas prices, declining global business and consumer confidence and rising unemployment, have precipitated an economic slowdown and have led to a recession and weak economic growth. Adverse events and continuing disruptions in the global economy and in the global capital markets may have a material adverse effect on our business, financial condition, results of operations and cash flows. Moreover, even in the absence of a market downturn, we are exposed to substantial risk of loss due to market volatility with certain factors, including consumer spending, business investment, government spending, inflation affecting the business and economic environment that could affect the economic and financial situation of our concession contracts counterparties and, ultimately, the profitability and growth of our business.

Generalized or localized downturns or inflationary or deflationary pressures in our key geographical areas could also have a material adverse effect on the performance of our business. A significant portion of our business activity is concentrated in the United States, Mexico, Peru and Spain, and we have significant investments in Brazil. Consequently, we are significantly affected by the general economic conditions in these countries. Spain, for instance, has recently experienced negative economic conditions, including high unemployment and significant government debt which we believe could adversely affect our operations in the future. The effects on the European and global economy of any exit of one or more member states (each a “Member State”) from the Eurozone, the dissolution of the euro and the possible redenomination of our financial instruments or other contractual obligations from euro into a different currency, or the perception that any of these events are imminent, are inherently difficult to predict and could give rise to operational disruptions or other risks of contagion to our business and have a material, adverse effect on our business, financial condition and results of operation. In addition, to the extent uncertainty regarding the European economic recovery continues to negatively affect government or regional budgets, our business, results of operations and cash flows could be materially adversely affected.

The global capital and credit markets have experienced periods of extreme volatility and disruption since the last half of 2008. Continued disruptions, uncertainty or volatility in the global capital and credit markets may limit our access to additional capital required to operate or grow our business, including our access to new equity capital to make further acquisitions or access to non-recourse project financing which we may use to fund or refinance many of our projects, even in cases where such capital has already been committed. Such market conditions may limit our ability to replace, in a timely manner, maturing liabilities and access the capital necessary to grow our business, or replace financing previously committed for a project that ceases to be available to it. As a result, we may be forced to delay raising capital, issue shorter-term securities than we prefer, or bear a higher cost of capital which could decrease our profitability and significantly reduce our financial flexibility or even require us to modify our dividend policy. In the event that we are required to replace previously committed financing to certain projects that subsequently becomes unavailable, we may have to postpone or cancel planned capital expenditures.

 

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We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties

We operate our activities in a range of international locations, including Mexico, Peru, Uruguay, Chile and Spain and have significant investments in Brazil, and we expect to expand our operations into new locations in the future. Accordingly, we face a number of risks associated with operating and investing in different countries that may have a material adverse effect on our business, financial condition, results of operations and cash flows. These risks include, but are not limited to, adapting to the regulatory requirements of such countries, compliance with changes in laws and regulations applicable to foreign corporations, the uncertainty of judicial processes, and the absence, loss or non-renewal of favorable treaties, or similar agreements, with local authorities or political, social and economic instability, all of which can place disproportionate demands on our management, as well as significant demands on our operational and financial personnel and business. As a result, we can provide no assurance that our future international operations and investments will remain successful.

A significant portion of our current and our potential future operations and investments are conducted in various emerging countries worldwide. Our activities and investments in these countries involve a number of risks that are more prevalent than in developed markets, such as economic and governmental instability, the possibility of significant amendments to, or changes in, the application of governmental regulations, the nationalization and expropriation of private property, payment collection difficulties, social problems, substantial fluctuations in interest and exchange rates, changes in the tax framework or the unpredictability of enforcement of contractual provisions, currency control measures, limits on the repatriation of funds and other unfavorable interventions or restrictions imposed by public authorities. Our dollar-denominated contracts in Peru and Mexico are payable in local currency at the exchange rate of the payment date. In the event of a rapid devaluation or implementation of exchange or currency controls, we may not be able to exchange the local currency for the agreed dollar amount, which could affect our cash available for distribution. Governments in Latin America frequently intervene in the economies of their respective countries and occasionally make significant changes in policy and regulations. Governmental actions in certain Latin American countries to control inflation and other policies and regulations have often involved, among other measures, price controls, currency devaluations, capital or exchange controls and limits on imports.

Decreases in government budgets, reductions in government subsidies and adverse changes in law may adversely affect our business and growth plan

Poor economic conditions have affected, and continue to affect, government budgets and threaten the continuation of government subsidies such as regulated revenues, cash grants, U.S. federal income tax benefits and other similar subsidies that benefit our business, particularly with respect to renewable energy. Such conditions may also lead to adverse changes in laws. For example, in the United States, due to the failure of the U.S. Congress to enact a plan by February 28, 2013 to reduce the federal budget deficit by $1.2 trillion, $85 billion of automatic budget cuts went into effect on March 1, 2013, reducing discretionary spending by all agencies of the federal government for the remainder of the federal fiscal year ending September 30, 2013. These cuts affected, among others, the U.S. Treasury program providing for cash grants in lieu of investment tax credits, or ITCs. See “Regulation—Regulation in the United States—U.S. Tax Incentives and Other Federal Considerations for Renewable Energy Generation Facilities—Section 1603 U.S. Treasury Grant Program.” In addition, a number of states and municipal authorities are experiencing severe fiscal pressures as they seek to address mounting budget deficits. The reduction or elimination of tariffs or subsidies or adverse changes in law could have a material adverse effect on the profitability of our existing projects, and the lack of availability of new projects undertaken in reliance on the continuation of such subsidies could adversely affect our growth plan.

 

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Pursuant to our cash dividend policy, we intend to distribute all or substantially all of our cash available for distribution through regular quarterly distributions and dividends, and our ability to grow and make acquisitions through cash on hand could be limited

As discussed in “Cash Dividend Policy,” our dividend policy is to distribute all or substantially all of our cash available for distribution each quarter and to rely primarily upon external financing sources, including the issuance of debt and equity securities and, if applicable, borrowings under our revolving credit line with Abengoa, to fund our acquisitions and potential growth capital expenditures. We may be precluded from pursuing otherwise attractive acquisitions if the projected short-term cash flow from the acquisition or investment is not adequate to service the capital raised to fund the acquisition or investment, after giving effect to our available cash reserves. See “Cash Dividend Policy—General—Our Ability to Grow our Business and Dividend.”

We intend to make regular quarterly cash distributions to our shareholders in an amount equal to the cash available for distribution generated during a given quarter, less reserves for the prudent conduct of our business, and subject to the stated payout ratio during that given period. As such, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional equity securities in connection with any acquisitions or growth capital expenditures, the payment of dividends on these additional equity securities may increase the risk that we will be unable to maintain or increase our per share dividend. There will be no limitations in our articles of association on our ability to issue equity securities, including securities ranking senior to our shares. The incurrence of any bank borrowings or other debt by intermediate subsidiaries or by our project-level subsidiaries to finance our growth strategy will result in increased interest expense and the imposition of additional or more restrictive covenants, which, in turn, may impact the cash distributions we receive to distribute to holders of our shares.

We may not be able to identify or consummate any future acquisitions on favorable terms, or at all

Our business strategy includes growth through the acquisitions of additional revenue-generating assets primarily from Abengoa, pursuant to the ROFO Agreement, and from third parties. This strategy depends on Abengoa’s ability to identify and develop assets and desire to sell those assets to us, as well as our ability to successfully identify and evaluate acquisition opportunities and consummate acquisitions on favorable terms. However, the number of acquisition opportunities may be limited.

Our ability to acquire future renewable facilities depends on the viability of renewable assets generally. These assets currently are largely contingent on public policy mechanisms including, among others, ITCs, cash grants, loan guarantees, accelerated depreciation, carbon trading plans, environmental tax credits and R&D incentives, as discussed in “Regulation—EU Directives—Incentives for renewable energy” and “Regulation—Regulation in the United States—U.S. Tax Incentives and other Federal Considerations for Renewable Energy Generation Facilities.” These mechanisms have been implemented at the U.S. federal and state levels and in other jurisdictions where our assets are located to support the development of renewable generation and other clean infrastructure technologies. The availability and continuation of public policy support mechanisms will drive a significant part of the economics and viability of our growth strategy and expansion into clean energy investments. For example, an ITC is crucial for the development of Concentrating Solar Power plants in the United States and the benefits of ITC for new projects might be lower beginning in 2017. See “Industry and Market Opportunity—Solar—Concentrating Solar Power Technology in the United States.”

Our ability to effectively consummate future acquisitions will also depend on our ability to arrange the required or desired financing for acquisitions. We may not have access to the capital markets to issue new equity securities or sufficient availability under our credit facilities or have access to project-level financing on commercially reasonable terms when acquisition opportunities arise. An inability to obtain the required or desired financing could significantly limit our ability to consummate future acquisitions and effectuate our growth strategy. If financing is available, utilization of our credit facilities or project-level financing for all or a portion of the purchase price of an acquisition, as applicable, could significantly increase our interest expense, impose additional or more restrictive covenants and reduce cash available for distribution. Similarly, the issuance

 

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of additional equity securities as consideration for acquisitions could cause significant shareholder dilution and reduce our per share cash available for distribution if the acquisitions are not sufficiently accretive. Our ability to consummate future acquisitions may also depend on our ability to obtain any required government or regulatory approvals for such acquisitions, including, but not limited to, the Federal Energy Regulatory Commission, or FERC, approval under Section 203 of the Federal Power Act, or FPA, in respect of acquisitions in the United States; the National Electric Energy Agency, Agencia Nacional de Energia Eletrica, or ANEEL, approval for the acquisition of transmission lines in Brazil; or any other approvals in the countries in which we may purchase assets in the future pursuant to the ROFO Agreement or otherwise. We may also be required to seek authorizations, waivers or notifications from debt and/or equity financing providers at the project or holding company level; local or regional agencies or bodies; and/or development agencies or institutions that may have a contractual right to authorize a proposed acquisition.

In addition, changes in our shareholder base as a result of future equity issuances to fund acquisitions or other equity-based capital markets transactions may trigger the requirement to seek waivers, authorizations or approvals from agencies, governments, financing providers, concession contract counterparties or any other relevant contract counterparty. Failure to secure any required waivers, authorizations or approvals may adversely affect our business.

Additionally, the acquisition of companies and assets are subject to substantial risks, including the failure to identify material problems during due diligence (for which we may not be indemnified post-closing), the risk of over-paying for assets (or not making acquisitions on an accretive basis) and the ability to retain customers. Further, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, our acquisitions may divert management’s attention from our existing business concerns, disrupt our ongoing business or not be successfully integrated. There can be no assurances that any future acquisitions will perform as expected or that the returns from such acquisitions will support the financing utilized to acquire them or maintain them. As a result, the consummation of acquisitions may have a material adverse effect on our business, financial condition, results of operations and cash flows and ability to pay dividends to holders of our shares.

Finally, while we benefit from a right of first offer with respect to the Abengoa ROFO Assets, we will compete with other companies for limited acquisition opportunities from third parties, which may increase our cost of making acquisitions or cause us to refrain from making acquisitions from third parties. Some of our competitors for acquisitions are much larger than us with substantially greater resources. These companies may be able to pay more for acquisitions due to cost of capital advantages, synergy potential or other drivers, and may be able to identify, evaluate, bid for and purchase a greater number of assets than our financial or human resources permit. If we are unable to identify and consummate future acquisitions, it will impede our ability to execute our growth strategy and limit our ability to increase the amount of dividends paid to holders of our shares.

We rely on certain regulations, subsidies and tax incentives that may be changed or legally challenged

We rely in a significant part on environmental and other regulations of industrial and local government activities, including regulations mandating, among other things, reductions in carbon or other greenhouse gas emissions and minimum biofuel content in fuel or use of energy from renewable sources. If the businesses to which such regulations relate were deregulated or if such regulations were materially changed or weakened, the profitability of our current and future projects could suffer, which could in turn have a material adverse effect on our business, financial condition and results of operations. In addition, uncertainty regarding possible changes to any such regulations has adversely affected in the past, and may adversely affect in the future, our ability to refinance a project or to satisfy other financing needs.

Subsidy regimes for renewable energy generation have been challenged in the past on constitutional and other grounds (including that such regimes constitute impermissible European Union state aid) in certain jurisdictions. In addition, certain loan guarantee programs in the United States, including those which have

 

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enabled the DOE to provide loan guarantees to support our Solana and Mojave projects, have been challenged on grounds of failure by the appropriate authorities to comply with applicable U.S. federal administrative and energy law. If all or part of the subsidy and incentive regimes for renewable energy generation in any jurisdiction in which we operate were found to be unlawful and, therefore, reduced or discontinued, we may be unable to compete effectively with conventional and other renewable forms of energy.

The production from our renewable energy facilities is the subject of various tax relief measures or tax incentives in the jurisdictions in which they operate. These tax relief and tax incentive measures play an important role in the profitability of our projects. In the future, it is possible that some or all of these tax incentives will be suspended, curtailed, not renewed or revoked. For example, our Solana and Mojave projects are reliant on the ITC Cash Grant program to repay a significant portion of their respective external debt financing and the failure to receive anticipated funds, or any funds at all, pursuant to the ITC Cash Grant would have an adverse effect on our ability to receive distributions from our Solana and Mojave projects. The occurrence of any of the above could adversely affect the profitability of our current plants and our ability to refinance projects, which could in turn have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are subject to extensive governmental regulation in a number of different jurisdictions, and our inability to comply with existing regulations or requirements or changes in applicable regulations or requirements may have a negative impact on our business, results of operations or financial condition

We are subject to extensive regulation of our business in the United States, Mexico, Spain, Peru and Brazil and in each of the other countries in which we operate. Such laws and regulations require licenses, permits and other approvals to be obtained in connection with the operations of our activities. This regulatory framework imposes significant actual, day-to-day compliance burdens, costs and risks on us. In particular, the power plants and transmission lines that we own are subject to strict international, national, state and local regulations relating to their operation and expansion (including, among other things, leasing and use of land, and corresponding building permits, landscape conservation, noise regulation, environmental protection and environmental permits and electric transmission and distribution network congestion regulations). Non-compliance with such regulations could result in the revocation of permits, sanctions, fines or even criminal penalties. Compliance with regulatory requirements, which may in the future include increased exposure to capital markets regulations, may result in substantial costs to our operations that may not be recovered. In addition, we cannot predict the timing or form of any future regulatory or law enforcement initiatives. Changes in existing energy, environmental and administrative laws and regulations may materially and adversely affect our business, margins and investments. Our business may also be affected by additional taxes imposed on our activities, reduction of regulated tariffs and other cuts or measures.

Further, similar changes in laws and regulations could increase the size and number of claims and damages asserted against us or subject us to enforcement actions, fines and even criminal penalties. In addition, changes in laws and regulations may, in certain cases, have retroactive effect and may cause the result of operations to be lower than expected. In particular, our activities in the energy sector are subject to regulations applicable to the economic regime of generation of electricity from renewable sources and to subsidies or public support in the benefit of the production of biofuels from renewable energy sources, which vary by jurisdiction, and are subject to modifications that may be more restrictive or unfavorable to us.

Our business is subject to stringent environmental regulation

We are subject to significant environmental regulation, which, among other things, requires us to obtain and maintain regulatory licenses, permits and other approvals and comply with the requirements of such licenses, permits and other approvals and perform environmental impact studies on changes to projects. There can be no assurance that:

 

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public opposition will not result in delays, modifications to or cancellation of any project or license;

 

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laws or regulations will not change or be interpreted in a manner that increases our costs of compliance or materially or adversely affects our operations or plants; or

 

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governmental authorities will approve our environmental impact studies where required to implement proposed changes to operational projects.

We believe that we are currently in material compliance with all applicable regulations, including those governing the environment. While we employ robust policies with regard to environmental regulation compliance, there are occasions where regulations are breached. On occasion, we have been found not to be in compliance with certain environmental regulations, and have incurred fines and penalties associated with such violations which, to date, have not been material in amount. We can give no assurance, however, that we will continue to be in compliance or avoid material fines, penalties, sanctions and expenses associated with compliance issues in the future. Violation of such regulations may give rise to significant liability, including fines, damages, fees and expenses, and site closures. Generally, relevant governmental authorities are empowered to clean up and remediate releases of environmental damage and to charge the costs of such remediation and cleanup to the owners or occupiers of the property, the persons responsible for the release and environmental damage, the producer of the contaminant and other parties, or to direct the responsible parties to take such action. These governmental authorities may also impose a tax or other liens on the responsible parties to secure the parties’ reimbursement obligations.

Environmental regulation has changed rapidly in recent years, and it is possible that we will be subject to even more stringent environmental standards in the future. For example, our activities are likely to be covered by increasingly strict national and international standards relating to climate change and related costs, and may be subject to potential risks associated with climate change, which may have a material adverse effect on our business, financial condition or results of operations. We cannot predict the amounts of any increased capital expenditures or any increases in operating costs or other expenses that we may incur to comply with applicable environmental, or other regulatory, requirements, or whether these costs can be passed on to our concession contract counterparties through price increases.

Increases in the cost of energy and gas could significantly increase our operating costs in some of our assets

Some of our activities (in particular, our Concentrating Solar Power plants in Spain that produce a portion of their power from natural gas) require some consumption of energy and gas, and we are vulnerable to material fluctuations in their prices. Although our energy and gas purchase contracts generally include indexing mechanisms, we cannot guarantee that these mechanisms will cover all of the additional costs generated by an increase in energy and gas prices, particularly for long-term contracts, and some of the contracts entered into by us do not include any indexing provisions. Significant increases in the cost of energy or gas, or shortages of the supply of energy and/or gas, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Counterparties to our offtake agreements may not fulfill their obligations and, as our contracts expire, we may not be able to replace them with agreements on similar terms in light of increasing competition in the markets in which we operate

A significant portion of the electric power we generate and the transmission capacity we have is sold under long-term offtake agreements with public utilities, industrial or commercial end-users or governmental entities, with a weighted average remaining duration (weighted using the relevant technical indicator by each type of asset) of approximately 26 years.

If, for any reason, any of the purchasers of power or transmission capacity under these agreements are unable or unwilling to fulfill their related contractual obligations or if they refuse to accept delivery of power delivered thereunder or if they otherwise terminate such agreements prior to the expiration thereof, our assets, liabilities, business, financial condition, results of operations and cash flow could be materially and adversely

 

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affected. Furthermore, to the extent any of our power or transmission capacity purchasers are, or are controlled by, governmental entities, our facilities may be subject to sovereign risk or legislative or other political action that may impair their contractual performance.

The power generation industry is characterized by intense competition and our electric generation assets encounter competition from utilities, industrial companies and other independent power producers, in particular with respect to uncontracted output. In recent years, there has been increasing competition among generators for offtake agreements and this has contributed to a reduction in electricity prices in certain markets characterized by excess supply above designated reserve margins. In light of these market conditions, we may not be able to replace an expiring or terminated agreement with an agreement on equivalent terms and conditions, including at prices that permit operation of the related facility on a profitable basis. In addition, we believe many of our competitors have well-established relationships with our current and potential suppliers, lenders and customers and have extensive knowledge of our target markets. As a result, these competitors may be able to respond more quickly to evolving industry standards and changing customer requirements than we will be able to. Adoption of technology more advanced than ours could reduce our competitors’ power production costs, resulting in their having a lower cost structure than is achievable with the technologies we currently employ and adversely affect our ability to compete for offtake agreement renewals. If we are unable to replace an expiring or terminated offtake agreement, the affected facility may temporarily or permanently cease operations. External events, such as a severe economic downturn, could also impair the ability of some counterparties to our offtake agreements and other customer agreements to pay for energy and/or other products and services received.

Our inability to enter into new or replacement offtake agreements or to compete successfully against current and future competitors in the markets in which we operate could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Transactions with counterparties expose us to credit risk which we must effectively manage to mitigate the effect of counterparty default

We are exposed to the credit risk profile of the counterparties to our long-term concession contracts, our suppliers and our financing providers, which could impact our business, financial condition and results of operations. Although we actively manage this credit risk through diversification, the use of non-recourse factoring contracts, credit insurance and other measures, our risk management strategy may not be successful in limiting our exposure to credit risk. This could adversely affect our business, financial condition, results of operations and cash flow.

We may be subject to increased finance expenses if we do not effectively manage our exposure to interest rate and foreign currency exchange rate risks

We are exposed to various types of market risk in the normal course of business, including the impact of interest rate changes and foreign currency exchange rate fluctuations. Some of our indebtedness (including project-level indebtedness) bears interest at variable rates, generally linked to market benchmarks such as EURIBOR and LIBOR. Any increase in interest rates would increase our finance expenses relating to our variable rate indebtedness and increase the costs of refinancing our existing indebtedness and issuing new debt (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Our Results of Operations—Interest Rates”). Although most of our long-term contracts are denominated in or indexed to U.S. dollars, we conduct our business and incur certain costs in the local currency of the countries in which we operate. As we continue expanding our business into existing markets such as South America and Europe, and into other new markets, we expect that an increasing percentage of our revenue and cost of sales will be denominated in currencies other than our reporting currency, the U.S. dollar. As a result, we will become subject to increasing currency translation risk, whereby changes in exchange rates between the U.S. dollar and the other currencies in which we do business could result in foreign exchange losses.

 

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We seek to actively manage these risks by entering into interest rate options and swaps, which according to our policies, generally cover at least 75% of the outstanding project debt, to hedge against interest rate risk. In addition, we plan to use future currency sale and purchase contracts and foreign exchange rate swaps or caps to hedge against foreign exchange rate risk when our exposure to non-U.S. dollar denominated cash flows is significantly below our 90% target. If our risk management strategies are not successful in limiting our exposure to changes in interest rates and foreign currency exchange rates, our business, financial condition and results of operations could be materially and adversely affected.

Our competitive position could be adversely affected by changes in technology, prices, industry standards and other factors

The markets in which our assets or projects operate change rapidly because of technological innovations and changes in prices, industry standards, product instructions, customer requirements and the economic environment. New technology or changes in industry and customer requirements may put pressure on the profitability of our existing projects by increasing the incentives of counterparties to our long-term contracts to seek new alternative projects or request higher service standards.

Our performance under our concession contracts may be adversely affected by problems related to our reliance on third-party contractors and suppliers

Our projects rely on the supply of services, equipment or software which we subcontract to Abengoa or other third-party suppliers in order to meet our contractual obligations under our contracted concessions. The delivery of products or services which are not in compliance with the requirements of the subcontract, or the late supply of products and services, can cause us to be in default under our contracts with our concession counterparties. To the extent we are not able to transfer all of the risk or be fully indemnified by Abengoa or other third-party contractors and suppliers, we may be subject to a claim by our customers as a result of a problem caused by a third party that could have a material adverse effect on our reputation, business, results of operations, financial condition and cash flows.

Supplier concentration may expose us to significant financial credit or performance risk

We often rely on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel, equipment, technology and/or other services required for the operation of certain of our facilities. In addition, certain of our suppliers provide long-term warranties with respect to the performance of their products or services. If any of these suppliers cannot perform under their agreements with us, or satisfy their related warranty obligations, we will need to utilize the marketplace to provide or repair these products and services. There can be no assurance that the marketplace can provide these products and services as, when and where required. We may not be able to enter into replacement agreements on favorable terms or at all. If we are unable to enter into replacement agreements to provide for fuel, equipment, technology and other required services, we would seek to purchase the related goods or services at market prices, exposing us to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price. We may also be required to make significant capital contributions to remove, replace or redesign equipment that cannot be supported or maintained by replacement suppliers, which could have a material adverse effect on our business, financial condition, results of operations, credit support terms and cash flows.

The failure of any supplier or customer to fulfill its contractual obligations to us could have a material adverse effect on our financial results. Consequently, the financial performance of our facilities is dependent on the credit quality of, and continued performance by, our suppliers and vendors.

We may be adversely affected by risks associated with acquisitions or investments

As a part of our growth strategy, we intend to make certain acquisitions and/or financial investments, and we may take on additional equity and debt to pay for such acquisitions. Moreover, we cannot guarantee that we

 

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will be able to complete all, or any, such transactions that we might contemplate in the future. To the extent we do, such transactions expose us to risks inherent in integrating acquired businesses and personnel, such as the inability to achieve projected cash flows; recognition of unexpected liabilities or costs; and regulatory complications arising from such transactions. Furthermore, the terms and conditions of financing for such acquisitions or financial investments could restrict the manner in which we conduct our business, particularly if we were to use debt financing. These risks could have a material adverse effect on our business, financial condition and results of operations.

In addition, we have made and may continue to make equity investments in certain strategic assets managed by or together with third parties, including governmental entities and private entities. In certain cases, we may only have partial or joint control over a particular asset. For example, we currently hold only economic rights in respect of our Brazilian investment through ACBH, which economic rights provide us with the right to receive a preferred dividend of $18.4 million annually, but we do not have control over ACBH. Investments in assets over which we have no, partial or joint control are subject to the risk that the other shareholders of the assets, who may have different business or investment strategies than us or with whom we may have a disagreement or dispute, may have the ability to independently make or block business, financial or management decisions, such as the decision to distribute dividends or appoint members of management, which may be crucial to the success of the project or our investment in the project, or otherwise implement initiatives which may be contrary to our interests. Additionally, the approval of other shareholders or partners may be required to sell, pledge, transfer, assign or otherwise convey our interest in such assets, or for us to acquire Abengoa’s interests in such assets as an initial matter. Alternatively, other shareholders may have rights of first refusal or rights of first offer in the event of a proposed sale or transfer of our interests in such assets or in the event of our acquisition of an interest in new assets pursuant to the ROFO Agreement or with third parties. These restrictions may limit the price or interest level for our interests in such assets, in the event we want to sell such interests.

Finally, our partners in existing or future projects may be unable, or unwilling, to fulfill their obligations under the relevant shareholder agreements or may experience financial or other difficulties that may adversely affect our investment in a particular joint venture. In certain of our joint ventures, we may also be reliant on the particular expertise of our partners and, as a result, any failure to perform our obligations in a diligent manner could also adversely affect the joint venture. If any of the foregoing were to occur, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

There are risks relating to future acquisitions and investments

Our board of directors might approve acquisitions and investments in the future. This could result in our making acquisitions or investments in assets that are different from, and possibly riskier than, those described in this prospectus. These changes could adversely affect the market price of our shares or our ability to make distributions to shareholders.

The facilities we operate are, in some cases, dangerous workplaces at which hazardous materials are handled. If we fail to maintain safe work environments, we can be exposed to significant financial losses, as well as civil and criminal liabilities

The facilities we operate often put our employees and others in close proximity with large pieces of mechanized equipment, moving vehicles, manufacturing or industrial processes, heat or liquids stored under pressure and highly regulated materials. On most projects and at most facilities, we are responsible for safety and, accordingly, must implement safe practices and safety procedures, which are also applicable to on-site subcontractors such as our O&M services providers. If we fail to design and implement such practices and procedures or if the practices and procedures we implement are ineffective or if our O&M service providers or other suppliers do not follow them, our employees and others may become injured and our and others’ property may become damaged. Unsafe work sites also have the potential to increase employee turnover, increase the cost

 

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of a project to our customers or the operation of a facility, and raise our operating costs. Any of the foregoing could result in financial losses, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, our projects and the operation of our facilities can involve the handling of hazardous and other highly regulated materials, which, if improperly handled or disposed of, could subject us to civil and criminal liabilities. We are also subject to regulations dealing with occupational health and safety. Although we maintain functional groups whose primary purpose is to ensure we implement effective health, safety and environmental work procedures throughout our organization, including construction sites and maintenance sites, the failure to comply with such regulations could subject us to liability. In addition, we may incur liability based on allegations of illness or disease resulting from exposure of employees or other persons to hazardous materials that we handle or are present in our workplaces.

Our business may be adversely affected by catastrophes, natural disasters, adverse weather conditions, climate change, unexpected geological or other physical conditions, or criminal or terrorist acts at one or more of our plants, facilities and electric transmission lines

If one or more of our plants, facilities or electric transmission lines were to be subject in the future to fire, flood or a natural disaster, adverse weather conditions, drought, terrorism, power loss or other catastrophe, or if unexpected geological or other adverse physical conditions were to develop at any of our plants, facilities or electric transmission lines, we may not be able to carry out our business activities at that location or such operations could be significantly reduced. For example, drought may affect the cooling capacity of our thermosolar projects. Any of these circumstances could result in lost revenue at these sites during the period of disruption and costly remediation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, despite security measures taken by us, it is possible that our sites and assets could be affected by criminal or terrorist acts. Any such acts could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our insurance may be insufficient to cover relevant risks and the cost of our insurance may increase

Our business is exposed to the inherent risks in the markets in which we operate. Although we seek to obtain appropriate insurance coverage in relation to the principal risks associated with our business, we cannot guarantee that such insurance coverage is, or will be, sufficient to cover all of the possible losses we may face in the future. If we were to incur a serious uninsured loss or a loss that significantly exceeded the coverage limits established in our insurance policies, the resulting costs could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, our insurance policies are subject to review by our insurers. If premiums were to increase in the future or certain types of insurance coverage were to become unavailable, we might not be able to maintain insurance coverage comparable to those that are currently in effect at comparable cost, or at all. If we were unable to pass any increase in insurance premiums on to our customers, such additional costs could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be subject to litigation and other legal proceedings

We are subject to the risk of legal claims and proceedings and regulatory enforcement actions in the ordinary course of our business and otherwise. The results of legal and regulatory proceedings cannot be predicted with certainty. We cannot guarantee that the results of current or future legal or regulatory proceedings or actions will not materially harm our business, financial condition, results of operations or operations, nor can we guarantee that we will not incur losses in connection with current or future legal or regulatory proceedings or actions that exceed any provisions we may have set aside in respect of such proceedings or actions or that exceed any available insurance coverage, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Business—Legal Proceedings.”

 

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We are subject to reputational risk, and our reputation is closely related to that of Abengoa

We rely on our reputation to do business, obtain financing, hire and retain employees and attract investors, one or more of which could be adversely affected if our reputation were damaged. Harm to our reputation could arise from real or perceived faulty or obsolete technology, failure to comply with legal and regulatory requirements, difficulties in meeting contractual obligations or standards of quality and service, ethical issues, money laundering and insolvency, among others. In addition, our reputation is closely related to that of Abengoa. If the public image or reputation of Abengoa were to be damaged as a result of adverse publicity or otherwise, we could be adversely affected due to our relationship with Abengoa. Any such perceived or real difficulties experienced by Abengoa would harm our reputation, which could have an adverse effect on our business, financial condition and results of operations.

Risks Related to Our Assets

The concession agreements under which we conduct some of our operations are subject to revocation or termination

Certain of our operations are conducted pursuant to contracted concessions granted by various governmental bodies. Generally, these contracted concessions give us rights to provide services for a limited period of time, subject to various governmental regulations. The governmental bodies or private clients responsible for regulating and monitoring these services often have broad powers to monitor our compliance with the applicable concession contracts and can require us to supply them with technical, administrative and financial information. Among other obligations, we may be required to comply with investment commitments and efficiency and safety standards established in the concession. Such commitments and standards may be amended in certain cases by the governmental bodies. Our failure to comply with the concession agreements or other regulatory requirements may result in contracted concessions being revoked, not being granted, upheld or renewed in our favor, or, if granted, upheld or renewed, may not be done on as favorable terms as currently applicable. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In some of the markets in which we are present, or in which we may own assets in the future, political instability, economic crisis or social unrest may give rise to a change in policies regarding long-term contracted assets with private companies, like us, in strategic sectors such as power generation or electric transmission. Any such changes could lead to modifications of the economic terms of our concession contracts or, in extreme scenarios, the nationalization of our assets, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Revenue from our contracted assets and concessions is significantly dependent on regulated tariffs or other long-term fixed rate arrangements that restrict our ability to increase revenue from these operations

The revenue that we generate from our contracted concessions is significantly dependent on regulated tariffs or other long-term fixed rate arrangements. Under most of our concession agreements, a tariff structure is established in such agreements, and we have limited or no possibility to independently raise tariffs beyond the established rates and indexation or adjustment mechanisms. Similarly, under a long-term power purchase agreement, we are required to deliver power at a fixed rate for the contract period, with limited escalation rights. In addition, we may be unable to adjust our tariffs or rates as a result of fluctuations in prices of raw materials, exchange rates, labor and subcontractor costs during the operating phase of these projects, or any other variations in the conditions of specific jurisdictions in which our concession-type infrastructure projects are located, which may reduce our revenue. Moreover, in some cases, if we fail to comply with certain pre-established conditions, the government or customer (as applicable) may reduce the tariffs or rates payable to us. In addition, during the life of a concession, the relevant government authority may unilaterally impose additional restrictions on our tariff rates, subject to the regulatory frameworks applicable in each jurisdiction. Governments may also postpone annual tariff increases until a new tariff structure is approved without compensating us for lost revenue. Furthermore, changes in laws and regulations may, in certain cases, have retroactive effect and expose us to

 

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additional compliance costs or interfere with our existing financial and business planning. For example, the Spanish government modified regulations applicable to renewable energy assets, including Concentrated Solar Power, in 2012 and 2013 which as a result, lowered yearly revenues of such assets. In the case that any one or more of these events occur, this could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Revenue from our renewable energy and conventional power facilities is partially exposed to market electricity prices

In addition to regulated incentives, revenue and operating costs from certain of our projects depend to a limited extent on market prices for sales of electricity. Market prices may be volatile and are affected by various factors, including the cost of raw materials, user demand, and if applicable, the price of greenhouse gas emission rights. In several of the jurisdictions in which we operate, we are exposed to remuneration schemes which contain both regulated incentive and market price components. In such jurisdictions, the regulated incentive component may not compensate for fluctuations in the market price component, and, consequently, total remuneration may be volatile. There can be no assurance that market prices will remain at levels which enable us to maintain profit margins and desired rates of return on investment. A decline in market prices below anticipated levels could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our solar and wind projects will be negatively affected if there are adverse changes to national and international laws and policies that support renewable energy sources

Recently, certain countries, such as the United States, a market that is one of our principal markets, have enacted policies of active support for renewable energy. These policies have included feed-in tariffs and renewable energy purchase obligations, mandatory quotas and/or portfolio standards imposed on utilities and certain tax incentives (such as the Investment Tax Credit in the United States). See “Regulation—Regulation in the United States—U.S. Tax Incentives and other Federal Considerations for Renewable Energy Generation Facilities—Section 1603 U.S. Treasury Grant Program.”

Although support for renewable energy sources by governments and regulatory authorities in the jurisdictions in which we operate has historically been strong, and European authorities, along with the United States government, have reaffirmed their intention to continue such support, certain policies currently in place may expire, be suspended or be phased out over time, cease upon exhaustion of the allocated funding or be subject to cancellation or non-renewal. Accordingly, we cannot guarantee that such government support will be maintained in full, in part or at all.

If the governments and regulatory authorities in the jurisdictions in which we operate or plan to operate were to further decrease or abandon their support for development of solar and wind energy due to, for example, competing funding priorities, political considerations or a desire to favor other energy sources, renewable or otherwise, the assets we plan to acquire in the future could become less profitable or cease to be economically viable. Such an outcome could have a material adverse effect on our ability to execute our growth strategy.

Our exchangeable preferred equity investment in ACBH is subject to inherent risks

Upon consummation of this offering, we will own an exchangeable preferred equity investment in ACBH which will grant us the right to receive during a five-year period commencing on July 1, 2014 a preferred dividend of $18.4 million per year and thereafter the option for us to remain as preferred equity holder with the right to receive such dividend or exchange the preferred equity for ordinary shares of specific project companies owned by ACBH, yielding at least $18.4 million of recurrent dividends. Prior to the consummation of this offering, we and Abengoa Concessions Investments Limited, which will be the Abengoa entity that holds our

 

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shares, will enter into a deed pursuant to which certain subordination measures will be implemented to protect our right to receive the preferred dividend in full. Our exchangeable preferred equity investment in ACBH is nonetheless subject to certain inherent risks, including those described below.

Despite our economic rights in respect of our preferred equity investment in ACBH, we do not have control over ACBH, and investments in assets over which we have no control are subject to certain risks (see “—Risks Related to Our Business and the Markets in Which We Operate—We may be adversely affected by risks associated with acquisitions or investments”).

We cannot guarantee that we will be able to exchange the preferred equity investment for ordinary shares of project companies owned by ACBH following the initial five-year period if we elect to do so. Any exchange of shares would be subject to relevant approvals, including from regulatory bodies, financing banks or equity partners at the project level, which ACBH may fail to secure. Furthermore, our right to exchange is exercisable in respect of project companies to be selected by ACBH and Abengoa at the time of the proposed exchange meeting in the aggregate specified dividend yield criteria, rather than specifically identified assets as of the time of the offering. Consequently, we can give no assurance regarding the identity or the specific characteristics of these projects or whether we would elect to remain as preferred equity holder or exchange the preferred equity investment.

We cannot be certain that the annual payment of the $18.4 million dividend will be made at any time. Payment of dividends following the initial five-year period by either ACBH or any project companies we acquire in exchange for the preferred equity investment, and the amount of such dividends, will depend on the completion of construction of certain of the projects, the performance of the projects and the extent of distributable profits in Brazilian reais for each relevant fiscal year.

Failure to receive the expected dividends from our exchangeable preferred equity investment in ACBH or any project companies we acquire in exchange for the preferred equity investment, as the case may be, may have a material adverse effect on our cash available for distribution, business, financial condition, results of operations and cash flows.

Lack of electric transmission capacity availability, potential upgrade costs to the electric transmission grid, and other systems constraints could significantly impact our ability to generate solar electricity power sales

We depend on electric interconnection and transmission facilities owned and operated by others to deliver the wholesale power we will sell from our electric generation assets to our customers. A failure or delay in the operation or development of these interconnection or transmission facilities or a significant increase in the cost of the development of such facilities could result in the loss of revenues. Such failures or delays could limit the amount of power our operating facilities deliver or delay the completion of our construction projects, as the case may be. Additionally, such failures, delays or increased costs could have a material adverse effect on our business, financial condition, results of operations and cash flows. If a region’s electric transmission infrastructure is inadequate, our recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have a sufficient incentive to invest in expansion of transmission infrastructure. Additionally, we cannot predict whether interconnection and transmission facilities will be expanded in specific markets to accommodate competitive access to those markets. In addition, certain of our operating facilities’ generation of electricity may be curtailed without compensation due to transmission limitations or limitations on the electricity grid’s ability to accommodate intermittent electricity generating sources, reducing our revenues and impairing our ability to capitalize fully on a particular facility’s generating potential. Such curtailments could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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We do not own all of the land on which our renewable energy, conventional power or electric transmission assets are located, which could result in disruption to our operations

We do not own all of the land on which our power generation or electric transmission assets are located and we are, therefore, subject to the possibility of less desirable terms and increased costs to retain necessary land use if we do not have valid leases or rights-of-way or if such rights-of-way lapse or terminate. Although we have obtained rights to construct and operate these assets pursuant to related lease arrangements, our rights to conduct those activities are subject to certain exceptions, including the term of the lease arrangement. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, may adversely affect our ability to operate our power generation and electric transmission assets.

Certain of our facilities are newly constructed or in the late stages of construction, and may not perform as expected

We completed the construction of Solana, ACT, Quadra 1, Quadra 2 and ATS during 2013 or the first half of 2014. Mojave has substantially finished construction and is in the startup and production testing stage as of the date hereof and expected to reach COD by October 2014. Additionally, Palmatir has completed construction and is expected to be fully operational by May 2014. Therefore, our expectations regarding the operating performance of Mojave (which we expect will be our largest source of cash available for distribution following COD), Palmatir and newly-finished assets are based on assumptions, estimates and past experience with similar assets that Abengoa has developed and built, and without the benefit of a substantial operating history. Projections contained in this prospectus regarding our ability to pay dividends to holders of our shares assume newly-constructed facilities perform to our expectations. However, the ability of these facilities to meet our performance expectations is subject to the risks inherent in newly-constructed power generation facilities and the construction of such facilities, including, but not limited to, degradation of equipment in excess of our expectations, system failures and outages. The failure of these facilities to perform as we expect could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to pay dividends to holders of our shares.

Some of our facilities will not have reached COD as of the date of this offering. Delays or a failure to achieve COD at all may reduce anticipated revenues from these assets, generate unexpected costs or, in extreme cases, trigger defaults in our concession or financing agreements

Mojave has substantially completed construction and COD is expected by October 2014. Unexpected technical difficulties, or the occurrence of unpredictable events, such as natural disasters or catastrophes, may delay COD or otherwise prevent us from meeting the contractual deadlines established in the Mojave PPA and/or our related financing contracts. Palmatir’s construction is complete, with COD expected in May 2014. Although many of the potential causes for delay are covered under the applicable engineering, procurement and construction contract we have with Abengoa subsidiaries, any delays or failure to achieve COD could have a material adverse effect on our business, financial condition, results of operations and cash flows, as well as our ability to pay dividends to holders of our shares.

The generation of electric energy from renewable energy sources depends heavily on suitable meteorological conditions, and if solar or wind conditions are unfavorable, our electricity generation, and therefore revenue from our renewable energy generation facilities using our systems, may be substantially below our expectations

The electricity produced and revenues generated by a renewable energy generation facility are highly dependent on suitable solar or wind conditions, as applicable, and associated weather conditions, which are beyond our control. Furthermore, components of our system, such as mirrors, absorber tubes or blades, could be damaged by severe weather. In addition, replacement and spare parts for key components may be difficult or costly to acquire or may be unavailable. Unfavorable weather and atmospheric conditions could impair the effectiveness of our assets or reduce their output beneath their rated capacity or require shutdown of key equipment, impeding operation of our renewable assets and our ability to achieve forecasted revenues and cash flows.

 

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We base our investment decisions with respect to each renewable generation facility on the findings of related wind and solar studies conducted on-site prior to construction or based on historical conditions at existing facilities. However, actual climatic conditions at a facility site, particularly wind conditions, may not conform to the findings of these studies and therefore, our solar and wind energy facilities may not meet anticipated production levels or the rated capacity of our generation assets, which could adversely affect our business, financial condition and results of operations and cash flows.

Our costs, results of operations, financial condition and cash flows could be adversely affected by the disruption of the fuel supplies necessary to generate power at our conventional generation facilities

Delivery of fossil fuels to fuel our conventional and some Concentrated Solar Power generation facilities is dependent upon the infrastructure, including natural gas pipelines, available to serve each such generation facility, as well as upon the continuing financial viability of contractual counterparties. As a result, we are subject to the risks of disruptions or curtailments in the production of power at these generation facilities if a counterparty fails to perform or if there is a disruption in the relevant fuel delivery infrastructure.

Risks Related to Our Indebtedness

Our indebtedness could adversely affect our ability to raise additional capital to fund our operations or pay dividends. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy or our industry as well as impact our cash available for distribution

As of March 31, 2014, we had approximately $2,830 million of total indebtedness under various project-level financing arrangements. Our indebtedness will increase as a result of the consolidation of Mojave. Concurrently with the completion of this offering, we will enter into a new $50 million revolving credit line with Abengoa. We do not intend to make borrowings under our new revolving facility in connection with this offering. All of our existing indebtedness is incurred at the project level, except certain debt facilities with Abengoa and third parties that will be cancelled with the proceeds of this offering. Our substantial debt could have important negative consequences on our financial condition, including:

 

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increasing our vulnerability to general economic and industry conditions;

 

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requiring a substantial portion of our cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our shares or to use our cash flow to fund our operations, capital expenditures and future business opportunities;

 

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limiting our ability to enter into long-term power sales or fuel purchases which require credit support;

 

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limiting our ability to fund operations or future acquisitions;

 

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restricting our ability to make certain distributions with respect to our shares and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants in our credit facilities and other financing agreements;

 

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exposing us to the risk of increased interest rates because a portion of some of our borrowings (below 10% as of the date hereof) are at variable rates of interest;

 

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limiting our ability to obtain additional financing for working capital, including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and

 

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limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who have less debt.

The agreements governing our project-level financing contain financial and other restrictive covenants that limit our project subsidiaries’ ability to make distributions to us or otherwise engage in activities that may be in

 

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our long-term best interests. The project-level financing agreements generally prohibit distributions from the project entities to us unless certain specific conditions are met, including the satisfaction of certain financial ratios. In addition, the project-level financing for Mojave prohibits distributions until such facility reaches COD and the first principal repayment is made. Our inability to satisfy certain financial covenants may prevent cash distributions by the particular project(s) to us and, our failure to comply with those and other covenants could result in an event of default which, if not cured or waived, may entitle the related lenders to demand repayment or enforce their security interests, which could have a material adverse effect on our business, results of operations, financial condition and cash flows. In addition, failure to comply with such covenants may entitle the related lenders to demand repayment and accelerate all such indebtedness. If our project-level subsidiaries are unable to make distributions, it would likely have a material adverse effect on our ability to pay dividends to holders of our shares.

Letter of credit facilities or personal guarantees to support project-level contractual obligations generally need to be renewed, at which time we will need to satisfy applicable financial ratios and covenants. If we are unable to renew our letters of credit as expected or replace them with letters of credit under different facilities on favorable terms or at all, we may experience a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, such inability may constitute a default under certain project-level financing arrangements, restrict the ability of the project-level subsidiary to make distributions to us and/or reduce the amount of cash available at such subsidiary to make distributions to us.

In addition, our ability to arrange financing, either at the corporate level or at a non-recourse project-level subsidiary, and the costs of such capital, are dependent on numerous factors, including:

 

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general economic and capital market conditions;

 

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credit availability from banks and other financial institutions;

 

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investor confidence in us, our partners and Abengoa, as our controlling shareholder;

 

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our financial performance and the financial performance of our subsidiaries;

 

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our level of indebtedness and compliance with covenants in debt agreements;

 

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maintenance of acceptable project credit ratings or credit quality;

 

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cash flow; and

 

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provisions of tax and securities laws that may impact raising capital.

We may not be successful in obtaining additional capital for these or other reasons. Furthermore, we may be unable to refinance or replace project-level financing arrangements or other credit facilities on favorable terms or at all upon the expiration or termination thereof. Our failure, or the failure of any of our projects, to obtain additional capital or enter into new or replacement financing arrangements when due may constitute a default under such existing indebtedness and may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Potential future defaults by our subsidiaries or by Abengoa could adversely affect us

All of our subsidiaries finance project assets and significant investments, including capital expenditures typically relating to contracted assets and concessions, primarily under loan agreements and related documents which, except as noted below, require the loans to be repaid solely from the revenue of the project being financed thereby, and provide that the repayment of the loans (and interest thereon) is secured solely by the shares, physical assets, contracts and cash flow of that project company. This type of financing is usually referred to herein as “non-recourse debt” or “project financing.” As of March 31, 2014, we had $2,830 million outstanding indebtedness on a combined basis.

 

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While the lenders under our non-recourse project financings do not have direct recourse to us or our subsidiaries (other than the project borrowers under those financings), defaults by the project borrowers under such financings can still have important consequences for us and our subsidiaries, including, without limitation:

 

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reducing our receipt of dividends, fees, interest payments, loans and other sources of cash, since the project company will typically be prohibited from distributing cash to us and our subsidiaries during the pendency of any default;

 

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causing us to record a loss in the event the lender forecloses on the assets of the project company; and

 

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the loss or impairment of investors’ and project finance lenders’ confidence in us.

If we were to fail to satisfy any of our debt service obligations or to breach any related financial or operating covenants, the applicable lender could declare the full amount of the relevant indebtedness to be immediately due and payable and could foreclose on any assets pledged as collateral. Further, certain of our financing arrangements contain cross-default provisions such that a default under one particular financing arrangement in Abengoa could automatically trigger defaults under some of our financing arrangements while certain technical obligations related to the construction of our assets are still outstanding (i.e., performance guarantees). As a result, a default under any indebtedness above certain thresholds in Abengoa could result in a substantial loss to us or could otherwise have a material adverse effect on our and our subsidiaries’ ability to perform our and their respective obligations in respect of any of our debt obligations.

Any of these events could have a material adverse effect on our financial condition, results of operations or cash flows.

Maintenance, expansion and refurbishment of electric generation facilities involve significant risks that could result in unplanned power outages or reduced output

Although the facilities in our portfolio are relatively new, they may require periodic upgrading and improvement in the future. Any unexpected operational or mechanical failure, including failure associated with breakdowns and forced outages, could reduce our facilities’ generating capacity below expected levels, reducing our revenues and jeopardizing our ability to pay dividends to shareholders at forecasted levels or at all. Degradation of the performance of our solar facilities above levels provided for in the related offtake agreements may also reduce our revenues. Unanticipated capital expenditures associated with maintaining, upgrading or repairing our facilities may also reduce profitability.

If we make any major modifications to our conventional or renewable power generation facilities or electric transmission lines, we may be required to comply with more stringent environmental regulations, which would likely result in substantial additional capital expenditures. We may also choose to repower, refurbish or upgrade our facilities based on our assessment that such activity will provide adequate financial returns. Such facilities require time for development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Risks Related to Our Relationship with Abengoa

Abengoa will be our controlling shareholder and will exercise substantial influence over Abengoa Yield and we are highly dependent on Abengoa

Abengoa will beneficially own and be entitled to vote a majority of our outstanding shares upon completion of this offering. As a result of this ownership, Abengoa will continue to have a substantial influence on our affairs and its ownership interest and voting power will constitute a majority of any quorum of our shareholders voting on any matter requiring the approval of our shareholders. Such matters include the election of directors,

 

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the adoption of amendments to our articles of associations and approval of mergers or sale of all or substantially all of our assets. This concentration of ownership may also have the effect of delaying or preventing a change in control of Abengoa Yield or discouraging others from making tender offers for our shares, which could prevent shareholders from receiving a premium for their shares. In addition, Abengoa will have the ability to appoint a majority of our directors. Abengoa may cause corporate actions to be taken even if its interests conflict with the interests of our other shareholders. See “Related Party Transactions—Procedures for Review, Approval and Ratification of Related Party Transactions; Conflicts of Interest.” There can be no assurance that the interests of Abengoa will coincide with the interests of purchasers of our shares or that Abengoa will act in a manner that is in our best interests.

Furthermore, we will depend on the executive services and management support provided by or under the direction of Abengoa under the Executive Services Agreement and the Support Services Agreement. We will depend on Abengoa to provide us with our revolving credit line and maintain existing guarantees and letters of credit in our favor, under the Financial Support Agreement. If Abengoa were to fail to provide the requisite financial support, we may be unable to obtain financing from a third party on comparable terms, without undue delay or at all. Any failure to effectively support our operations, implement our strategy or provide financial support could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Abengoa or Abengoa subsidiaries currently provide support and administration services as well as operating and maintenance services at most of our facilities. Any failure by Abengoa to perform its requirements under the services arrangements, or any failure by us to identify and contract with replacement service providers, if required, could adversely affect our business or the operation of our facilities and have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may not be able to consummate future acquisitions from Abengoa

Our ability to grow through acquisitions depends, in part, on Abengoa’s ability to identify and present us with acquisition opportunities. Abengoa established us to own, manage and acquire renewable energy, conventional power and electric transmission lines and other contracted revenue generating assets. Although Abengoa has agreed to grant us a right of first offer with respect to certain contracted revenue assets that Abengoa may elect to sell in the future (as described in “Related Party Transactions—Right of First Offer”), Abengoa will be under no obligation to sell or propose for consideration for acquisition any assets to us or to accept any related offer from us, and may identify other opportunities for itself and its other subsidiaries and pursue such opportunities for its or their respective accounts. Furthermore, Abengoa has no obligation to source acquisition opportunities specifically for us. There are a number of factors which could materially and adversely impact the extent to which suitable acquisition opportunities are made available from Abengoa, including:

 

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the same professionals within Abengoa’s organization that are involved in acquisitions that are suitable for us have responsibilities within Abengoa’s broader business. Limits on the availability of such individuals will likewise result in a limitation on the availability of acquisition opportunities for us; and

 

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in addition to structural limitations, the question of whether a particular asset is suitable is highly subjective and is dependent on a number of factors, including an assessment by Abengoa relating to our liquidity position at the time, the risk profile of the asset, the consistency of the asset with our investment criteria, and whether such asset is an appropriate fit given our then current operations and other factors.

If Abengoa determines that an opportunity is not suitable for us, it may still pursue such opportunity on its own behalf, or on behalf of another Abengoa affiliate. In making these determinations, Abengoa may be influenced by factors that result in a misalignment or conflict of interest. See “—Risks Related to Our Business and the Markets in Which We Operate—We may not be able to identify or consummate any future acquisitions on favorable terms, or at all” for a description of risks associated with the identifying, evaluating and consummating acquisitions generally, including acquisitions of Abengoa ROFO Assets.

 

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The departure of some or all of Abengoa’s employees could prevent us from achieving our objectives

We will depend on the diligence, skill and business contacts of Abengoa’s executives and personnel and the information and opportunities they generate during the normal course of their activities. Under the Executive Services Agreement, senior Abengoa managers will provide executive management services to us for up to one year following the consummation of this offering; thereafter, we expect that these executives will be directly employed by us. Our future success will depend on the continued service of these individuals, who are not obligated to remain employed with Abengoa and who are not obliged to accept direct employment with us. Abengoa has experienced departures of key professionals and personnel in the past and may do so in the future, and we cannot predict the impact that any such departures will have on our ability to achieve our objectives. The departure of a significant number of Abengoa’s professionals or a material portion of the Abengoa employees who work at any of our facilities for any reason, or the failure to appoint qualified or effective successors in the event of such departures, could have a material adverse effect on our ability to achieve our objectives.

Our organizational and ownership structure may create significant conflicts of interest that may be resolved in a manner that is not in our best interests or the best interests of holders of our minority shareholders and that may have a material adverse effect on our business, financial condition, results of operations and cash flows

Our organizational and ownership structure involves a number of relationships that may give rise to certain conflicts of interest between us and our minority shareholders, on the one hand, and Abengoa, on the other hand. Five of our initial directors, including our chairman who will have a tie-breaking vote, will be affiliated with Abengoa. Prior to the completion of this offering, we will enter into an Executive Services Agreement and a Support Services Agreement with Abengoa. Ten of our senior managers will be Abengoa senior managers who devote their time to both our company and Abengoa as needed to conduct the respective businesses pursuant to the Executive Services Agreement. Although our directors and executive officers owe fiduciary duties to our shareholders, these shared Abengoa executives will have fiduciary and other duties to Abengoa during the period before we directly employ them, which duties may be inconsistent with our best interests and those of our minority shareholders. In addition, Abengoa and its representatives, agents and affiliates will have access to our confidential information. Although some of these persons will be subject to confidentiality obligations pursuant to confidentiality agreements or implied duties of confidence, neither the Executive Services Agreement nor the Support Services Agreement contains general confidentiality provisions.

Following the completion of this offering, Abengoa will be a related party under the applicable securities laws governing related party transactions and may have interests which differ from our interests or those of our other minority shareholders, including with respect to the types of acquisitions made, the timing and amount of dividends made by Abengoa Yield, the reinvestment of returns generated by our operations, the use of leverage when making acquisitions and the appointment of outside advisors and service providers. Any material transaction between us and Abengoa (including the proposed acquisition of any Abengoa ROFO Asset) will be subject to our related party transaction policy, which will require prior approval of such transaction by a majority of the independent members of our board of directors (as discussed in “Related Party Transactions—Procedures for Review, Approval and Ratification of Related Party Transactions; Conflicts of Interest”). The creation of our related party transaction approval policy may not insulate us from derivative claims related to related party transactions and the conflicts of interest described in this risk factor. Regardless of the merits of such claims, we may be required to spend significant management time and financial resources in the defense thereof. Additionally, to the extent we fail to appropriately deal with any such conflicts, it could negatively impact our reputation and ability to raise additional funds and the willingness of counterparties to do business with us, all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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If Abengoa terminates the Executive Services Agreement or the Support Services Agreement, or defaults in the performance of its obligations under the agreement, we may be unable to contract with a substitute service provider on similar terms, or at all

We will rely on Abengoa to provide us with executive management for up to one year following the consummation of this offering under the Executive Services Agreement and support services on an ongoing basis under the Support Services Agreement, and we will not have independent executive management or support personnel for that interim period. Our future success depends significantly on the involvement of certain of Abengoa’s senior managers and employees, who have valuable expertise in all areas of our business. Abengoa’s ability to retain and motivate the senior managers and employees involved in the management of our business, as well as attract highly skilled employees, will significantly affect our ability to run our business successfully and to execute our growth strategy. If we were to lose access to one or more of the ten senior managers provided for under the Executive Services Agreement or, for example, valuable local managers with significant experience in the markets in which we operate, it might be difficult to appoint replacements. This could have an adverse impact on our business, financial condition, results of operations and cash flows.

The Executive Services Agreement will provide that Abengoa cannot terminate the agreement unilaterally; however, the Support Services Agreement will provide that Abengoa may terminate the agreement upon 180 days’ prior written notice of termination to us if we default in the performance or observance of any material term, condition or covenant contained in the agreement in a manner that results in material harm and the default continues unremedied for a period of 60 days after written notice of the breach is given to us. If Abengoa terminates the Support Services Agreement or defaults in the performance of its obligations under the Executive Services Agreement or Support Services Agreement, we may be unable to contract with a substitute service provider on similar terms or at all, and the costs of substituting service providers may be substantial. In addition, in light of Abengoa’s familiarity with our assets, a substitute service provider may not be able to provide the same level of service due to lack of pre-existing synergies. If we cannot locate a service provider that is able to provide us with services substantially similar to those provided by Abengoa under the Executive Services Agreement or Support Services Agreement on similar terms, it would likely have a material adverse effect on our business, financial condition, results of operation and cash flows.

Risks Related to Ownership of our Shares

We may not be able to pay a specific or increasing level of cash dividends to holders of our shares in the future

The amount of our cash available for distribution principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

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the level and timing of capital expenditures we make;

 

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the level of our operating and general and administrative expenses, including reimbursements to Abengoa for services provided to us in accordance with the Support Services Agreement;

 

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seasonal variations in revenues generated by the business;

 

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our debt service requirements and other liabilities;

 

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fluctuations in our working capital needs;

 

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our ability to borrow funds;

 

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restrictions contained in our debt agreements (including our project-level financing); and

 

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other business risks affecting our cash levels.

As a result of all these factors, we cannot guarantee that we will have sufficient cash generated from operations to pay a specific or increasing level of cash dividends to holders of our shares. Furthermore, holders of

 

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our shares should be aware that the amount of cash available for distribution depends primarily on our cash flow, and is not solely a function of profitability, which is affected by non-cash items. We may incur other expenses or liabilities during a period that could significantly reduce or eliminate our cash available for distribution and, in turn, impair our ability to pay dividends to shareholders during the period. Because we are a holding company, our ability to pay dividends on our shares is limited by restrictions or limitations on the ability of our subsidiaries to pay dividends or make other distributions, such as pursuant to shareholder loans, capital reductions or other means, to us, including restrictions under the terms of the agreements governing project-level financing or legal, regulatory or other restrictions or limitations applicable in the various jurisdictions in which we operate, such as exchange controls or similar matters or corporate law limitations, any of which could change from time to time and thereby limit our subsidiaries’ ability to pay dividends or make other distributions to us. Our project-level financing agreements generally prohibit distributions to us unless certain specific conditions are met, including the satisfaction of financial ratios.

Our cash available for distribution will likely fluctuate from quarter to quarter, in some cases significantly, due to seasonality. See “Business—Seasonality.” As result, we may reduce the amount of cash we distribute in a particular quarter to establish reserves to fund distributions to shareholders in future periods for which the cash distributions we would otherwise receive from our subsidiary project companies would otherwise be insufficient to fund our quarterly dividend. If we fail to establish sufficient reserves, we may not be able to maintain our quarterly dividend with a respect to a quarter adversely affected by seasonality.

Dividends to holders of our shares will be paid at the discretion of our board of directors. Our board of directors may decrease the level of or entirely discontinue payment of dividends. For a description of additional restrictions and factors that may affect our ability to pay cash dividends, please see “Cash Dividend Policy.”

The assumptions underlying the forecasts presented elsewhere in this prospectus are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks that could cause our actual cash available for distribution to differ materially from our forecasts

The forecasts presented elsewhere in this prospectus are based on our current portfolio of assets and were prepared using assumptions that our management believes are reasonable. See “Cash Dividend Policy—Assumptions and Considerations.” These include assumptions regarding the future operating costs of our facilities, our facilities’ future level of power generation, interest rates, administrative expenses, tax treatment of income, future capital expenditure requirements, if any, the COD of Mojave and Palmatir on schedule and to budget and the absence of material adverse changes in economic conditions or government regulations. They also include assumptions based on wind and solar resource studies that take into account meteorological conditions and on the availability of our facilities and transmission lines. The forecasts assume that no unexpected risks materialize during the forecast periods. Any one or more than one of these assumptions may prove to be incorrect, in which case our actual results of operations will be different from, and possibly materially worse than, those contemplated by the forecasts. There can be no assurance that the assumptions underlying the forecasts presented elsewhere in this prospectus will prove to be accurate. Actual results for the forecast periods will likely vary from the forecast results and those variations may be material. We make no representation that actual results achieved in the forecast periods will be the same, in whole or in part, as those forecasted herein.

We are a holding company and our only material assets after completion of this offering will be our interest in our subsidiaries, upon whom we are dependent for distributions to pay dividends, taxes and other expenses

We are a holding company whose sole material assets are the ones contributed to it by Abengoa in the Asset Transfer. We do not have any independent means of generating revenue. We intend to cause our operating subsidiaries to make distributions to us in an amount sufficient to cover all applicable taxes payable and dividends, if any, declared by us. To the extent that we need funds for a quarterly cash dividend to holders of our shares or otherwise, and one or more of our operating subsidiaries is restricted from making such distributions

 

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under the terms of its financing or other agreements or applicable law and regulations or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition and limit our ability to pay dividends to shareholders.

We have a limited operating history and as a result there is no assurance we can operate on a profitable basis

We have a limited operating history on which to base an evaluation of our business and prospects. Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stages of operation. We cannot assure you that we will be successful in addressing the risks we may encounter, and our failure to do so could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Market interest rates may have an effect on the value of our shares

One of the factors that will influence the price of our shares will be the effective dividend yield of our shares (i.e., the yield as a percentage of the then-market price of our shares) relative to market interest rates. An increase in market interest rates, which are currently at low levels relative to historical rates, may lead prospective purchasers of our shares to expect a higher dividend yield. Our inability to increase our dividend as a result of an increase in borrowing costs, insufficient cash available for distribution or otherwise could result in selling pressure on, and a decrease in, the market price of our shares as investors seek alternative investments with higher yield.

If you purchase shares sold in this offering, you will incur immediate and substantial dilution

If you purchase shares in this offering, you will incur immediate and substantial dilution, because the assumed initial public offering price of $             per share is substantially higher than the as adjusted net tangible book value per share on an as adjusted basis to give effect to the Asset Transfer. The as adjusted net tangible book value of our shares is $             per share. For additional information, see “Dilution.”

Market volatility may affect the price of our shares and the value of your investment

Following the completion of this offering, the market price for our shares is likely to be volatile, in part because our shares have not been previously publicly traded. We cannot predict the extent to which a trading market will develop or how liquid that market may become. If you purchase shares in this offering, you will pay a price that was not established in the public trading markets. The initial public offering price will be determined by negotiations between the underwriters and us. You may not be able to resell your shares above the initial public offering price and may suffer a loss on your investment. In addition, the market price of our shares may fluctuate due to the termination of the ROFO Agreement, the Executive Services Agreement, the Support Services Agreement or additions or departures of Abengoa’s key personnel, changes in market valuations of similar companies and/or speculation in the press or investment community regarding us or Abengoa. Securities markets in general may experience extreme volatility that is unrelated to the operating performance of particular companies. Any broad market fluctuations may adversely affect the trading price of our shares.

You may experience dilution of your ownership interest due to the future issuance of additional shares

We are in a capital intensive business, and may not have sufficient funds to finance the growth of our business through future acquisitions. As a result, we may require additional funds from further equity or debt financings, including tax equity financing transactions or sales of preferred shares or convertible debt, to complete future acquisitions, expansions and capital expenditures and pay the general and administrative costs of our business. In the future, we may issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of purchasers of our shares offered hereby. The potential issuance of additional shares or preferred stock or convertible debt may create downward pressure on the trading price of our

 

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shares. We may also issue additional shares or other securities that are convertible into or exercisable for our shares in future public offerings or private placements for capital-raising purposes or for other business purposes, potentially at an offering price, conversion price or exercise price that is below the offering price for our shares in this offering.

If securities or industry analysts do not publish or cease to publish research or reports about us, our business or our market, or if they change their recommendations regarding our shares adversely, the price and trading volume of our shares could decline

The trading market for our shares will be influenced by the research and reports that industry or securities analysts may publish about us, our business, our market or our competitors. If any of the analysts who may cover us change their recommendations regarding our shares adversely, or provide more favorable relative recommendations about our competitors, the price of our shares would likely decline. If any analyst who may cover us were to cease coverage of our company or fail to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause the price or trading volume of our shares to decline.

Future sales of our shares by Abengoa may cause the price of our shares to fall

The market price of our shares could decline as a result of sales by Abengoa of such shares in the market, or the perception that these sales could occur. Abengoa has agreed to certain limitations on the ability to dispose of or hedge any of our shares, or any securities convertible into or exchangeable for our shares, for a period of time commencing on the date of this prospectus. Future sales of substantial amounts of the shares and/or equity-related securities in the public market, or the perception that such sales could occur, could adversely affect prevailing trading prices of the shares and could impair our ability to raise capital through future offerings of equity or equity-related securities. The price of the shares could be depressed by investors’ anticipation of the potential sale in the market of substantial additional amounts of shares. Disposals of shares could increase their offer in the market and depress their price.

There may not be a public market for our shares

There is currently, subject to official notice of issuance, no public market for our shares. While we have applied to list our shares on the NASDAQ Global Select Market, an active or liquid public market for our shares may not develop or be sustained. If an active trading market does not develop or is not maintained, the liquidity and market price of our shares could be negatively affected.

The trading market for our shares may be volatile and may be adversely affected by many events

The market for securities issued by issuers such as us is influenced by economic and market conditions and, to varying degrees, market conditions, interest rates, currency exchange rates and inflation rates in other countries. There can be no assurance that events in the United States, Latin America, Europe or elsewhere will not cause market volatility or that such volatility will not adversely affect the price of the shares or that economic and market conditions will not have any other adverse effect. Fluctuations in interest rates may give rise to arbitrage opportunities based upon changes in the relative value of the shares. Any trading by arbitrageurs could, in turn, affect the trading price of the shares.

As a “foreign private issuer” in the United States, we are exempt from certain rules under the U.S. securities laws and are permitted to file less information with the SEC than U.S. companies

As a “foreign private issuer,” we are exempt from certain rules under the Exchange Act that impose certain disclosure obligations and procedural requirements for proxy solicitations under Section 14 of the Exchange Act. In addition, our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and the rules under the Exchange Act with respect

 

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to their purchases and sales of our shares. Moreover, we are not required to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act. In addition, we are not required to comply with Regulation FD, which restricts the selective disclosure of material information.

Judgments of U.S. courts may not be enforceable against us

Judgments of U.S. courts, including those predicated on the civil liability provisions of the federal securities laws of the United States, may not be enforceable in courts in the United Kingdom or other countries in which we operate. As a result, our shareholders who obtain a judgment against us in the United States may not be able to require us to pay the amount of the judgment.

There are limitations on enforceability of civil liabilities under U.S. federal securities laws

We are incorporated under the laws of England and Wales. Most of our officers and directors reside outside of the United States. In addition, a portion of our assets and the majority of the assets of our directors and officers are located outside the United States. As a result it may be difficult or impossible to serve legal process on persons located outside the United States and to force them to appear in a U.S. court. It may also be difficult or impossible to enforce a judgment of a U.S. court against persons outside the United States, or to enforce a judgment of a foreign court against such persons in the United States. We believe that there may be doubt as to the enforceability against persons in England and Wales and in Spain, whether in original actions or in actions for the enforcement of judgments of U.S. courts, of civil liabilities predicated solely upon the laws of the United States, including its federal securities laws. Because we are a foreign private issuer, our directors and officers will not be subject to rules under the Exchange Act that under certain circumstances would require directors and officers to forfeit to us any “short-swing” profits realized from purchases and sales, as determined under the Exchange Act and the rules thereunder, of our equity securities. In addition, punitive damages in actions brought in the United States or elsewhere may be unenforceable in England and Wales and in Spain.

We will incur increased costs as a result of being a publicly traded company

As a public company, we will incur additional legal, accounting and other expenses that we did not incur as a private company. In addition, SEC and NASDAQ rules impose various requirements on public companies, including the establishment and maintenance of effective disclosure and financial controls and changes in corporate governance practices. Our management and other personnel will need to devote a substantial amount of time to these compliance initiatives. Moreover, these rules and regulations will increase our legal and financial compliance costs and will make some activities more time-consuming and costly. For example, we expect these rules and regulations to make it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified people to serve on our board of directors, our board committees or as executive officers.

We are an “emerging growth company” and may elect to comply with reduced public company reporting requirements, which could make our shares less attractive to investors

We are an “emerging growth company,” as defined by the JOBS Act. For as long as we continue to be an emerging growth company, we may choose to take advantage of exemptions from various public company reporting requirements. These exemptions include, but are not limited to, (i) not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act and (ii) reduced disclosure obligations regarding executive compensation in our periodic reports, proxy statements and registration statements. We could be an emerging growth company for up to five years after the first sale of our common equity securities pursuant to an effective registration statement under the Securities Act, which such fifth anniversary will occur in 2019. However, if certain events occur prior to the end of such five-year period,

 

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including if we become a “large accelerated filer,” our annual gross revenues exceed $1.0 billion or we issue more than $1.0 billion of non-convertible debt in any three-year period, we would cease to be an emerging growth company prior to the end of such five-year period. The information that we provide to holders of our shares may be different than you might receive from other public reporting companies in which you hold equity interests. We cannot predict if investors will find our shares less attractive as a result of our reliance on these exemptions. If some investors find our shares less attractive as a result of any choice we make to reduce disclosure, there may be a less active trading market for our shares and the price for our shares may be more volatile.

Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards until such time as those standards apply to private companies. However, we have irrevocably elected not to avail ourselves of this extended transition period for complying with new or revised accounting standards and, therefore, we will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.

Shareholders in certain jurisdictions may not be able to exercise their pre-emptive rights if we increase our share capital

Under our articles of association, holders of our shares generally have the right to subscribe and pay for a sufficient number of our shares to maintain their relative ownership percentages prior to the issuance of any new shares in exchange for cash consideration. Holders of shares in certain jurisdictions may not be able to exercise their pre-emptive rights unless securities laws have been complied with in such jurisdictions with respect to such rights and the related shares, or an exemption from the requirements of the securities laws of these jurisdictions is available. We currently do not intend to register the shares under the laws of any jurisdiction other than the United States, and no assurance can be given that an exemption from the securities laws requirements of other jurisdictions will be available to shareholders in these jurisdictions. To the extent that such shareholders are not able to exercise their pre-emptive rights, the pre-emptive rights would lapse and the proportional interests of such holders would be reduced.

The rights of our shareholders may differ from the rights typically offered to shareholders of a U.S. corporation organized in Delaware

We are incorporated under English law. The rights of holders of our shares are governed by English law, including the provisions of the U.K. Companies Act 2006, and by our articles of association. These rights differ in certain respects from the rights of shareholders in typical U.S. corporations organized in Delaware. The principal differences are set forth in “Description of Share Capital—Differences in Corporate Law.”

Provisions in the U.K. City Code on Takeovers and Mergers may have anti-takeover effects that could discourage an acquisition of us by others, even if an acquisition would be beneficial to our shareholders

The U.K. City Code on Takeovers and Mergers, or the Takeover Code, applies, among other things, to an offer for a public company whose registered office is in the United Kingdom and whose securities are not admitted to trading on a regulated market in the United Kingdom if the company is considered by the Panel on Takeovers and Mergers, or the Takeover Panel, to have its place of central management and control in the United Kingdom. This is known as the “residency test.” The test for central management and control under the Takeover Code is different from that used by the U.K. tax authorities. Under the Takeover Code, the Takeover Panel will determine whether we have our place of central management and control in the United Kingdom by looking at various factors, including the structure of our Board of Directors, the functions of the directors and where they are resident.

If at the time of a takeover offer the Takeover Panel determines that we have our place of central management and control in the United Kingdom, we would be subject to a number of rules and restrictions,

 

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including but not limited to the following: (1) our ability to enter into deal protection arrangements with a bidder would be extremely limited; (2) we may not, without the approval of our shareholders, be able to perform certain actions that could have the effect of frustrating an offer, such as issuing shares or carrying out acquisitions or disposals; and (3) we would be obliged to provide equality of information to all bona fide competing bidders

Risks Related to Taxation

Changes in our tax position can significantly affect our reported earnings and cash flows

Changes in corporate tax rates and/or other relevant tax laws in the United Kingdom, the United States or the other countries in which our assets are located could have a material impact on our future tax rate and/or our required tax payments. Although we consider our tax provision to be adequate, the final determination of our tax liability could be different from the forecasted amount, which could have potential adverse effects on our financial condition and cash flows. In relation to the United Kingdom Controlled Foreign Company regime, or the U.K. CFC rules, we have good arguments to consider that the foreign entities held under Abengoa Yield would not be subject to the U.K. CFC rules. Changes to the U.K. CFC rules or adverse interpretations of them, could have effects on the future tax rate and/or required tax payments in Abengoa Yield. With respect to some of our projects, we must meet defined requirements to apply favorable tax treatment, such as lower tax rates or exemptions. We intend to meet these requirements in order to benefit from the favorable tax treatment; however, there can be no assurance that we will be able to comply with all of the necessary requirements in the future, or the requirements could change or be interpreted in another manner, which could give rise to a greater tax liability and which could have an adverse effect on our results of operations and cash flows.

Our future tax liability may be greater than expected if we do not utilize Net Operating Losses, or NOLs, sufficient to offset our taxable income

We expect to generate NOLs and NOL carryforwards that we can use to offset future taxable income. Based on our current portfolio of assets, which include renewable assets that benefit from an accelerated tax depreciation schedule, and subject to potential tax audits, which may result in income, sales, use or other tax obligations, we do not expect to pay significant taxes for a period of approximately ten years, with the exception of ACT in Mexico, where we do not expect to pay significant income taxes until the fifth or sixth year after this offering once we use existing NOLs.

While we expect these losses will be available to us as a future benefit, in the event that they are not generated as expected, or are successfully challenged by the local tax authorities, such as the U.S. Internal Revenue Service, or the IRS, or Her Majesty’s Revenue and Customs among others, by way of a tax audit or otherwise, or are subject to future limitations as discussed below, our ability to realize these benefits may be limited. A reduction in our expected NOLs, a limitation on our ability to use such losses or the occurrence of future tax audits may result in a material increase in our estimated future income tax liability and may negatively impact our results of operations and liquidity.

Our ability to use U.S. NOLs to offset future income may be limited

Our ability to use U.S. NOLs generated in the future could be limited if we were to experience an “ownership change” as defined under Section 382 of the U.S. Internal Revenue Code of 1986, as amended, or the IRC, and similar state rules. In general, an “ownership change” would occur if our “5-percent shareholders,” as defined under Section 382 of the IRC, collectively increased their ownership in us by more than 50 percentage points over a rolling three-year period. A corporation that experiences an ownership change will generally be subject to an annual limitation on the use of its pre-ownership change U.S. NOLs equal to the equity value of the corporation immediately before the ownership change, multiplied by the long-term tax-exempt rate for the month in which the ownership change occurs. The long-term tax-exempt rate for April 2014 is 3.56%. Future sales of our shares by Abengoa, or sales of shares of Abengoa, as well as current or future issuances by us or Abengoa could contribute to a potential ownership change.

 

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Distributions to U.S. Holders of our shares may be fully taxable as dividends

It is difficult to predict whether or to what extent we will generate earnings or profits as computed for U.S. federal income tax purposes in any given tax year. If we make distributions on the shares from current or accumulated earnings and profits as computed for U.S. federal income tax purposes, such distributions generally will be taxable to U.S. Holders of our shares as ordinary dividend income for U.S. federal income tax purposes. Under current law, if certain requirements are met, such dividends would be eligible for the lower tax rates applicable to qualified dividend income of certain non-corporate U.S. Holders. While we expect that a portion of our distributions to U.S. Holders of our shares may exceed our current and accumulated earnings and profits as computed for U.S. federal income tax purposes, and therefore may constitute a non-taxable return of capital to the extent of a U.S. Holder’s basis in our shares, no assurance can be given that this will occur. We intend to calculate our earnings and profits annually in accordance with U.S. federal income tax principles. See “Taxation—Material U.S. Federal Income Tax Considerations.”

If we are a passive foreign investment company for U.S. federal income tax purposes for any taxable year, U.S. Holders of our shares could be subject to adverse U.S. federal income tax consequences

If Abengoa Yield were a “passive foreign investment company” within the meaning of Section 1297 of the U.S. Internal Revenue Code of 1986, as amended (“PFIC”) for any taxable year during which a U.S. Holder holds our shares, certain adverse U.S. federal income tax consequences may apply to the U.S. Holder. Abengoa Yield does not believe that it will be a PFIC for its current taxable year and does not expect to be a PFIC for U.S. federal income tax purposes for its current taxable year or in the foreseeable future. However, PFIC status depends on the composition of a company’s income and assets and the fair market value of its assets (including, among others, less than 25% owned equity investments) from time to time, as well as on the application of complex statutory and regulatory rules that are subject to potentially varying or changing interpretations. Accordingly, there can be no assurance that Abengoa Yield will not be considered a PFIC for any taxable year.

If we were a PFIC, U.S. Holders of our shares may be subject to adverse U.S. federal income tax consequences, such as taxation at the highest marginal ordinary income tax rates on capital gains and on certain actual or deemed dividends, interest charges on certain taxes treated as deferred, and additional reporting requirements. See “Taxation—Material U.S. Federal Income Tax Considerations—Passive foreign investment company rules.”

 

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USE OF PROCEEDS

We estimate the net proceeds to us from this offering will be approximately $            million, based on an assumed public offering price of $            per share, which is the midpoint of the price range set forth on the cover page of this prospectus and after deducting underwriting commissions payable by us.

We intend to distribute all of the net proceeds from this offering, less $30 million to strengthen our liquidity position, to Abengoa, as part of the consideration paid to Abengoa in connection with the Asset Transfer.

Each $1.00 increase (decrease) in the assumed public offering price would increase (decrease) the net proceeds to us by approximately $            million, after deducting underwriting commissions payable by us, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same. Any increase or decrease in net proceeds would result in a corresponding increase or decrease in the amount paid to Abengoa.

The underwriters may also purchase up to an additional              shares from the selling shareholder at the public offering price, less the underwriting commissions, from the closing date of this offering to cover over-allotments, if any. We estimate that the net proceeds to the selling shareholder will be approximately $            million, after deducting underwriting commissions and assuming the exercise in full of the underwriters’ over-allotment option. We will not receive any proceeds from the exercise of the underwriters’ over-allotment option.

 

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CASH DIVIDEND POLICY

You should read the following discussion of our cash dividend policy in conjunction with “—Assumptions and Considerations” below, which includes the factors and assumptions upon which we base our cash dividend policy. In addition, you should read “Cautionary Statements Regarding Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

This forecast of future operating results and cash available for distribution in future periods is based on the assumptions described below and other assumptions believed by us to be reasonable as of the date of this prospectus. However, we cannot assure you that any or all of these assumptions will be realized. These forward-looking statements are based upon estimates and assumptions about circumstances and events that have not yet occurred and are subject to all of the uncertainties inherent in making projections. This forecast should not be relied upon as fact or as an accurate representation of future results. Future results will be different from this forecast and the differences may be materially less favorable.

For additional information regarding our historical combined results of operations, you should refer to our Interim Combined Financial Statements and our Annual Combined Financial Statements included elsewhere in this prospectus.

General

Our Cash Dividend Policy

We intend to pay a regular quarterly dividend in U.S. dollars to our shareholders starting in the third quarter of 2014. Our quarterly dividend will initially be set at $0.2592 per share, or $1.04 per share on an annualized basis, and the amount may be changed in the future without advance notice.

We expect to pay a quarterly dividend on or about the 75th day following the expiration of each fiscal quarter to our shareholders of record on or about the 60th day following the last day of such fiscal quarter.

Together with the quarterly dividend corresponding to the third quarter of 2014, we expect to pay an additional dividend of $0.2592 per share pro-rated to the number of days elapsed from the completion of this offering until the end of the second quarter of 2014.

We have established our initial quarterly dividend level based on a targeted cash available for distribution payout ratio of 90%, after considering the cash available for distribution that we expect our projects will be able to generate, less reserves for the prudent conduct of our business (including for, among other things, dividend shortfalls as a result of fluctuations in our cash flows). Our board of directors may, by resolution, amend the cash dividend policy at any time. We intend to grow our business via improvements in our existing projects, the start of production of Mojave and through the acquisition of operational projects, which, we believe, will facilitate the growth of our cash available for distribution and enable us to increase our dividend per share over time. However, the determination of the amount of cash dividends to be paid to holders of our shares will be made by our board of directors and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our board of directors deem relevant. Our cash dividend policy reflects a basic judgment that our shareholders will be better served by distributing most of the cash distributions we receive from our project companies each quarter in the form of a quarterly dividend rather than retaining it. In addition, by providing for the provision of reserves each quarter after calculating cash available for distribution, and thereby enabling us to retain a portion of cash generated from operations, we believe we will also provide better value to our shareholders by maintaining the operating capacity of our assets and, in turn, dividend paying capacity.

 

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Our cash available for distribution is likely to fluctuate from quarter to quarter, in some cases significantly, as a result of the seasonality of our assets, the terms of our financing arrangements, maintenance and outage schedules, among other factors. Accordingly, during quarters in which our projects generate cash available for distribution in excess of the amount necessary for us to pay our stated quarterly dividend, we may reserve a portion of the excess to fund cash distributions in future quarters. In quarters in which we do not generate sufficient cash available for distribution to fund our stated quarterly cash dividend, if our board of directors so determines, we may use retained cash flow from other quarters, as well as other sources of cash, such as net cash provided by financing activities, receipts from cash grant proceeds, or, if applicable, borrowings under our new revolving credit line or future credit facilities, to pay dividends to our shareholders. Our estimation of cash available for distribution does not include non-recurring cash generation events nor the starting cash position of Abengoa Yield on an unconsolidated basis.

Estimate of Future Cash Available for Distribution

We primarily considered forecasted cash available for distribution in assessing the amount of cash that we expect our assets will be able to generate for the purposes of the dividends we will distribute during the forecast period. Cash available for distribution is a non-GAAP financial measure that is not required by, or presented in accordance with, IFRS as issued by IASB.

We believe that an understanding of cash available for distribution is useful to investors in evaluating our ability to pay dividends pursuant to our stated cash dividend policy. We have forecasted cash available for distribution through monthly cash projections that can actually reach the holding company per project. Nevertheless, in general we expect that “cash available for distribution” will be similar to Further Adjusted EBITDA generated during the period,

less:

 

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changes in other assets and liabilities (this can have both a negative and positive impact);

 

•

non-cash revenue linked to U.S. cash grants;

 

•

minorities dividend;

 

•

cash interest paid;

 

•

principal amortization of indebtedness; and

 

•

cash taxes;

plus:

 

•

temporary financial investment interests.

Our board of directors has adopted a resolution approving a policy to distribute 90% of our cash available for distribution and our controlling shareholder has communicated to us that it supports and plans to continue supporting such policy.

Risks Regarding Our Cash Dividend Policy

We do not have any operating history as an independent company upon which to rely in evaluating whether we will have sufficient cash available for distribution and other sources of liquidity to allow us to pay dividends on our shares at our initial quarterly dividend level on an annualized basis or at all. There is no guarantee that we will pay quarterly cash dividends to our shareholders. We do not have a legal obligation to pay our initial quarterly dividend or any other dividend. While we currently intend to maintain our initial dividend following the

 

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completion of this offering and to grow our business and increase our dividend per share over time, our cash dividend policy is subject to all the risks inherent in our business and may be changed at any time as a result of certain restrictions and uncertainties, including the following:

 

•

The amount of our quarterly cash available for distribution could be impacted by restrictions on cash distributions contained in our project-level financing arrangements, which require that our project-level subsidiaries comply with certain financial tests and covenants in order to make such cash distributions. Generally these restrictions limit the frequency of permitted cash distributions to semi-annual or annual payments, and prohibit distributions unless specified debt service coverage ratios, historical and/or projected, are met. See the sub-sections entitled “—Project Level Financing” under the individual project descriptions in “Business—Our Operations”. When forecasting cash available for distribution and dividend payments we have aimed to take these restrictions into consideration, but we cannot guarantee future dividends. Additionally, we may incur debt in the future to acquire new projects, the terms of which will likely require commencement of commercial operations prior to our ability to receive cash distributions from such acquired projects. These agreements likely will contain financial tests and covenants that our subsidiaries must satisfy prior to making distributions. Should we or any of our project-level subsidiaries be unable to satisfy these covenants or if any of us are otherwise in default under such facilities, we may be unable to receive sufficient cash distributions to pay our stated quarterly cash dividends notwithstanding our stated cash dividend policy. See the “Project-Level Financing” descriptions contained in “Business—Our Operations” for a description of such restrictions.

 

•

We and our board of directors will have the authority to establish cash reserves for the prudent conduct of our business and for future cash dividends to our shareholders, and the establishment of or increase in those reserves could result in a reduction in cash dividends from levels we currently anticipate pursuant to our stated cash dividend policy. These reserves may account for the fact that our project-level cash flows may vary from year to year based on, among other things, changes in prices under offtake agreements, operational costs and other project contracts, compliance with the terms of non-recourse project-level financing including debt repayment schedules, the transition to market or recontracted pricing following the expiration of offtake agreements, working capital requirements and the operating performance of the assets. Furthermore, our board of directors may increase reserves to account for the seasonality that has historically existed in our assets’ cash flows and the variances in the pattern and frequency of distributions to us from our assets during the year.

 

•

We may lack sufficient cash to pay dividends to our shareholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors, including low availability, unexpected operating interruptions, legal liabilities, costs associated with governmental regulation, changes in governmental subsidies, changes in regulation, as well as increases in our operating and/or general and administrative expenses, including existing contracts with Abengoa and its subsidiaries, principal and interest payments on our and our subsidiaries’ outstanding debt, income tax expenses, working capital requirements or anticipated cash needs at our project-level subsidiaries. See “Risk Factors” for more information on the risks to which our business is subject.

 

•

We may pay cash to our shareholders via capital reduction in lieu of dividends in some years.

 

•

Our project companies’ cash distributions to us (in the form of dividends or other forms of cash distributions such as shareholder loan repayments) and, as a result, our ability to pay or grow our dividends are dependent upon the performance of our subsidiaries and their ability to distribute cash to us. The ability of our project-level subsidiaries to make cash distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable corporation laws and other laws and regulations.

 

•

Our board of directors may, by resolution, amend the cash dividend policy at any time. The board of directors may elect to change the amount of dividends, suspend any dividend or decide to pay no dividends even if there is ample cash available for distribution.

 

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Our Ability to Grow our Business and Dividend

We intend to grow our business primarily through the improvement of existing assets, the COD of Mojave and the acquisition of contracted power generation assets, electric transmission lines and other infrastructure assets, which, we believe, will facilitate the growth of our cash available for distribution and enable us to increase our dividend per share over time. Our approved policy is to maximize cash distributions to shareholders and specifically to distribute 90% of our cash available for distribution. However, the final determination of the amount of cash dividends to be paid to our shareholders will be made by our board of directors and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our board of directors deems relevant.

We expect that we will rely primarily upon external financing sources, including commercial bank borrowings and issuances of debt and equity securities, to fund any future growth capital expenditures. To the extent we are unable to finance growth externally, our cash dividend policy could significantly impair our ability to grow because we do not currently intend to reserve a substantial amount of cash generated from operations to fund growth opportunities. If external financing is not available to us on acceptable terms, our board of directors may decide to finance acquisitions with cash from operations, which would reduce or even eliminate our cash available for distribution and, in turn, impair our ability to pay dividends to our shareholders. To the extent we issue additional shares to fund growth capital expenditures, the payment of dividends on those additional shares may increase the risk that we will be unable to maintain or increase our per share dividend level. Additionally, the incurrence of additional commercial bank borrowings or other debt to finance our growth would result in increased interest expense, which in turn may impact our cash available for distribution and, in turn, our ability to pay dividends to our shareholders.

For the fiscal year ended December 31, 2013, cash available for distribution was $0, as none of our assets generated any dividends or any other form of distribution during the period. Most of our assets (Solana, Mojave, Palmatir, ATS, Quadra 1 and Quadra 2) were under construction or had only been in operation for a few months, as of December 31, 2013, thus preventing any cash distribution. ATN’s and ACT’s project-level debt facilities were refinanced during the last quarter of 2013, which prevented cash distributions prior to that refinancing. Additionally, Solaben 2 and Solaben 3 reached COD during the second and fourth quarters of 2012, respectively and were prohibited by their project financing agreements from paying dividends prior to mid-2014. For the foregoing reasons, cash available for distribution in the first six months of 2014 is expected to be $0. See “Business—Our Operations” for details on project financing limitations for distributions.

Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2015 and June 30, 2016

Based upon the material assumptions described below and other assumptions that we believe to be reasonable as of the date of this prospectus, we forecast that our cash available for distribution during the twelve months ending June 30, 2015 and 2016 will be approximately $92 million and $150 million, respectively. The increase in the forecasted cash available for distribution for the twelve months ending June 30, 2016 over the twelve months ending June 30, 2015 is primarily attributable to a full twelve months of distributions from Mojave, which will have no distributions in the prior year and, to a lesser extent, the start of cash distributions from certain other projects, such as Palmatir, Quadra 1 and Quadra 2. We expect that Mojave will be our largest source of cash available for distribution following COD. This amount would be sufficient to pay our initial quarterly dividend of $0.2592 per share on all outstanding shares immediately after consummation of this offering for each quarter in the twelve months ending June 30, 2015 and the twelve months ending June 30, 2016. If our board were to decide to maintain the 90% payout ratio in the twelve month period ending June 30, 2016, based on the foregoing, our quarterly dividend would increase to approximately $0.42 per share or $1.69 on an annualized basis.

 

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We are providing this forecast to supplement our financial statements in support of our belief that we will have sufficient cash available to allow us to pay a regular quarterly dividend on all of our outstanding shares immediately after consummation of this offering for each quarter in the twelve months ended June 30, 2015, at our initial quarterly dividend of $0.2592 per share (or $1.04 per share on an annualized basis). Please read “—Assumptions and Considerations” for further information as to the assumptions we have made for the forecast. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” for information regarding the accounting policies we have followed for the forecast.

Our forecast is a forward-looking statement and reflects our judgment as of the date of this prospectus of the conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2015 and the twelve months ending June 30, 2016. It should be read together with the financial statements and the accompanying notes thereto included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” We believe that we have a reasonable basis for these assumptions and that our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. The assumptions and estimates underlying the forecast, as described below under “—Assumptions and Considerations,” are inherently uncertain and, although we consider them reasonable as of the date of this prospectus, they are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from forecasted results, including, among others, the risks and uncertainties described in “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they occur, could cause actual results of operations to vary significantly from those that would enable us to generate sufficient cash available for distribution to allow us to pay the aggregate annualized regular quarterly dividend on all outstanding shares for the twelve months ending June 30, 2015 and 2016, calculated at the initial quarterly dividend rate of $0.2592 per share per quarter (or $1.04 per share on an annualized basis). Accordingly, there can be no assurance that the forecast will be indicative of our future performance or that actual results will not differ materially from those presented in the forecast. If our forecasted results are not achieved, we may not be able to pay a regular quarterly dividend to our shareholders at our initial quarterly dividend level or at all. Inclusion of the forecast in this prospectus should not be regarded as a representation by us, the underwriters or any other person that the results contained in the forecast will be achieved.

Forecasted Financial Information

We do not as a matter of course make public projections as to future sales, earnings or other results. However, our management has prepared the prospective financial information set forth below to present the cash available for distribution during the twelve months ending June 30, 2015 and 2016. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, our expected course of action and future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information. Neither our independent auditors, nor any other independent accountants, have compiled, examined, or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for, and disclaim any association with, the prospective financial information. The assumptions and estimates underlying the forecasted financial information are inherently uncertain and, though considered reasonable by our management as of the date of its preparation, are subject to a wide variety of significant business, economic, and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the prospective financial information, including, among others, risks and uncertainties. See “Risk Factors.” Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results will not differ materially from those presented in the forecasted financial information. Inclusion of the forecasted financial information in this prospectus should not be regarded as a representation by any person that the results contained in the forecasted

 

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financial information will be achieved. We do not generally publish our business plans and strategies or make external disclosures of our anticipated financial position or results of operations. Accordingly, we do not intend to update or otherwise revise the forecasted financial information to reflect circumstances existing since its preparation or to reflect the occurrence of unanticipated events, even in the event that any or all of the underlying assumptions are shown to be in error. Furthermore, we do not intend to update or revise the forecasted financial information to reflect changes in general economic or industry conditions. Additional information relating to the principal assumptions used in preparing the projections is set forth below. See “Risk Factors” for a discussion of various factors that could materially affect our financial condition, results of operations, business, prospects and securities.

The statement that we believe that we will have sufficient cash available for distribution to allow us to pay the full regular quarterly dividend on all of our outstanding shares immediately after the consummation of this offering for each quarter in the twelve months ending June 30, 2015 and 2016 (based on our initial quarterly dividend rate of $0.2592 per share per quarter (or $1.04 per share on an annualized basis)) should not be regarded as a representation by us, the underwriters or any other person that we will pay such dividends. Therefore, you are cautioned not to place undue reliance on this information.

 

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The table below sets forth our forecasted cash available for distribution for the twelve months ending June 30, 2015 and 2016:

 

		Twelve months ending
(in millions of U.S. dollars)		June 30, 2015				June 30, 2016
Operating revenues
Total operating revenues		$	492			$	576
Operating costs and expenses
Costs of operations			(119	)			(132	)
Depreciations and amortization			(163	)			(174	)
General and administration			(5	)			(5	)
Total operating costs and expenses		$	(287	)		$	(310	)
Operating income		$	205			$	266
Other income/(expense)
Interest income			2				2
Interest expense			(191	)			(193	)
Total other income/(expense)		$	(189	)		$	(191	)
Cash distribution from unconsolidated affiliates			18				18
Income before income taxes			34				93
Income tax expense			(3	)			(5	)
Net income		$	31			$	88
Less:
Interest income			2				2
Add:
Depreciation and amortization			163				174
Interest expense			191				193
Income tax expense			3				5
Further Adjusted EBITDA		$	386			$	458
Changes in other assets and liabilities			(32	)			1
Non-cash revenue linked to U.S. cash grants			(25	)			(31	)
Less:
Minorities dividend			20				24
Cash interest paid			166				165
Principal amortization of indebtedness			51				87
Cash taxes			1				2
Add:
Temporary financial investment interests			1				1
Estimated cash available for distribution to shareholders after investing and funding activities		$	92			$	150
Annual dividend per ordinary share			1.04				1.68
Ordinary shares (in millions)			80				80
Aggregate annual dividend			83				135
Excess/(Shortfall) of cash available for distribution over aggregated annualized quarterly distributions		$	9			$	15

 

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The following tables provide a reconciliation of net income to Further Adjusted EBITDA by geography for the twelve months ending June 30, 2015 and 2016:

 

(in millions of U.S. dollars)		Twelve months ending June 30, 2015
		North America				South America(1)				Europe				Corporate				Total
Net income		$	28			$	5			$	2			$	(5	)		$	31
Less:
Interest income			0				1				0				0				2
Add:
Depreciation and amortization			103				36				24				0				163
Interest expense			113				57				22				0				191
Income tax expense			0				2				1				0				3
Further Adjusted EBITDA		$	243			$	99			$	49			$	(5	)		$	386

 

 

(1)	South America includes cash distributions from unconsolidated affiliates of $18 million.

 

(in millions of U.S. dollars)		Twelve months ending June 30, 2016
		North America				South America(1)				Europe				Corporate				Total
Net income		$	84			$	6			$	2			$	(5	)		$	88
Less:
Interest income			0				1				1				0				2
Add:
Depreciation and amortization			114				36				24				0				174
Interest expense			116				55				22				0				193
Income tax expense			0				4				1				0				5
Further Adjusted EBITDA		$	314			$	100			$	49			$	(5	)		$	458

 

 

(1)	South America includes cash distributions from unconsolidated affiliates of $18 million.

The following tables provide a reconciliation of net income to Further Adjusted EBITDA by business sector for the twelve months ending June 30, 2015 and 2016:

 

(in millions of U.S. dollars)		Twelve months ending June 30, 2015
		Renewable Energy				Conventional Power				Electric Transmission(1)				Corporate				Total
Net income		$	(33	)		$	67			$	1			$	(5	)		$	31
Less:
Interest income			1				0				1				0				2
Add:
Depreciation and amortization			134				0				29				0				163
Interest expense			98				41				52				0				191
Income tax expense			1				0				2				0				3
Further Adjusted EBITDA		$	200			$	108			$	83			$	(5	)		$	386

 

 

(1)	Electric Transmission includes cash distributions from unconsolidated affiliates of $18 million.

 

 

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(in millions of U.S. dollars)		Twelve months ending June 30, 2016
		Renewable Energy				Conventional Power				Electric Transmission(1)				Corporate				Total
Net income		$	21			$	69			$	3			$	(5	)		$	88
Less:
Interest income			1				0				1				0				2
Add:
Depreciation and amortization			145				0				29				0				174
Interest expense			103				40				50				0				193
Income tax expense			1				0				4				0				5
Further Adjusted EBITDA		$	269			$	109			$	85			$	(5	)		$	458

 

 

(1)	Electric Transmission includes cash distributions from unconsolidated affiliates of $18 million.

Assumptions and Considerations

Set forth below are the material assumptions that we have made to demonstrate our ability to generate our estimated Further Adjusted EBITDA and estimated cash available for distribution for the twelve months ending June 30, 2015 and June 30, 2016. The forecast has been prepared by and is the responsibility of our management. Our forecast reflects our judgment of the conditions we expect to exist and the course of action we expect to take during the forecast period. While the assumptions disclosed in this prospectus are not all inclusive, such assumptions are those that we believe are material to our forecasted results of operations. We believe we have a reasonable basis for these assumptions. We believe that our historical results of operations will approximate those reflected in our forecast. However, we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecasted and our historical results, and those differences may be material. While we believe that the assumptions underlying the forecast are reasonable in light of management’s current expectations concerning future events, we can give no assurance that our assumptions will be realized or that we will generate cash available for distribution during the forecast periods at the levels forecasted, in which event we may not be able to pay cash dividends on our shares at our initial dividend level or at all.

Assumptions and estimates underlying the forecast are inherently uncertain and our future operating results are subject to a wide variety of risks and uncertainties, including significant business, economic and competitive risks and uncertainties described under the headings “Risk Factors” and “Cautionary Statements Regarding Forward-Looking Statements” elsewhere in this prospectus.

 

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The following table presents the forecasted Further Adjusted EBITDA and cash available for distribution by geography and business sector for the twelve months ending June 30, 2015 and June 30, 2016 (in millions):

 

(in millions of U.S. dollars)		Twelve months ending
		June 30, 2015								June 30, 2016
		Further Adjusted EBITDA				Estimated Cash Available for Distribution				Further Adjusted EBITDA				Estimated Cash Available for Distribution
Split by Geography
North America		$	243			$	28			$	314			$	95
South America(1)			99				46				100				50
Europe			49				23				49				10
Corporate			(5	)			(5	)			(5	)			(5	)
Total		$	386			$	92			$	458			$	150
Split by Business sector
Renewable Energy		$	200			$	31			$	269			$	95
Conventional Power			108				19				109				19
Electric Transmission(1)			83				46				85				41
Corporate			(5	)			(5	)			(5	)			(5	)
Total		$	386			$	92			$	458			$	150

 

(1)	Includes cash distributions from unconsolidated affiliates of $18 million.

Potential Risks

Our business is exposed to numerous risks that could have a material adverse effect on our business, financial condition, results of operations or cash available for distribution. However, we have assumed that no such risks will materialize for the purposes of preparing the forecast. Nevertheless, when we have estimated dividends to be paid, we have used a 90% payout ratio for the twelve months ending June 30, 2015 and June 30, 2016. For a discussion of the important factors that could cause actual results to differ materially from our forecast, see “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” elsewhere in this prospectus.

Initial Public Offering

The forecast assumes that the proceeds of this offering will be used as described in “Use of Proceeds” elsewhere in this prospectus and that in connection with the completion of this offering, the other transactions contemplated upon under the heading “Summary—Asset Transfer” will have been consummated (other than the exercise by the underwriters of their option to purchase additional shares).

Our Projects and Investment

The forecast assumes that our projects and investment will be comprised, during the relevant periods, of the projects set forth in the table under “Business—Our Operations” and our preferred equity investment in ACBH. All projects are currently in operation, with the exception of Palmatir, which has completed construction, and Mojave, which has substantially completed construction. We expect to reach COD of Palmatir by May 2014 and COD of Mojave by October 2014 and our forecast assumes we reach COD by these dates. Although making acquisitions is part of our strategy, we have assumed that we will not make any further acquisitions during the forecasted period.

 

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Asset assumptions

Renewable Energy Assets

Revenues and expenses reflect the terms specified in the fixed-priced (including, in the case of Solana, a yearly fixed tariff increase) offtake agreements for 100% of energy production or, in the case of our Spanish assets (Solaben 2 and Solaben 3), a regulated revenue for 100% of energy production (see “Business—Our Operations—Renewable Energy—Solaben 2 and Solaben 3” for additional information). Our forecast assumes production based on solar and wind resource assessments of a 1-year P-50 output probability for each asset adjusted by our experience in typical ramp-up periods. Production based on a 1-year P-50 output probability is defined as the output level that has a greater than 50% probability of being exceeded in any given year. Our forecast for the solar facilities assumes an Adjusted EBITDA of approximately $133 per MWh for the twelve months ending June 30, 2015; an Adjusted EBITDA of approximately $145 per MWh for the twelve months ending June 30, 2016; an average capacity factor of approximately 24.0% for the twelve months ending June 30, 2015; and an average capacity factor of approximately 30.2% for the twelve months ending June 30, 2016. Our forecast for our wind facility assumes an Adjusted EBITDA of approximately $90 per MWh for the twelve months ending June 30, 2015; an Adjusted EBITDA of approximately $89 per MWh for the twelve months ending June 30, 2016; and an average capacity factor of 39.8% for the twelve months ending June 30, 2015 and 2016.

We expect our cash available for distribution from our renewable energy assets to increase from $31 million for the twelve months ending June 30, 2015 to $95 million for the twelve months ending June 30, 2016. This increase is primarily driven by the expected commencement of cash distributions from Mojave in December 2015 in accordance with its project finance agreement. In addition, we expect Palmatir to commence cash distributions in August 2015, also in accordance with its project finance agreement. After December and August 2015, respectively, we expect that Mojave and Palmatir will continue fulfilling the required debt service coverage ratios (see “Business—Our Operations—Renewable Energy”) and continue to distribute cash. We expect Mojave, for the twelve months ending June 30, 2016, which will be the first twelve month forecast period that it will be fully operational, to represent more than 37% of total operating revenues from Renewable Energy Assets and more than 60% of cash available for distribution from this business sector due to its profitability and the fact that there are no minority interests in Mojave that would reduce the cash distributions from Mojave to us (as opposed to Solana and Solaben 2 and 3, which have minority interests).

Conventional Power Asset

Revenues and expenses reflect the terms specified in the Pemex Conversion Services Agreement under which ACT is required to sell all of the plant’s thermal and electrical output to Pemex. The price is fixed and will be adjusted annually, part of it according to inflation and part according to a mechanism agreed in the contract that on average over the life of the contract reflects expected inflation. Our forecast assumes an average Adjusted EBITDA margin of approximately 80%. The Conversion Services Agreement requires Pemex to supply, free of charge, the facility with the fuel and water necessary to operate the Cogeneration Plant and produce electrical energy and steam requested by the Pemex Purchasers based on the expected levels of efficiency. See “Business—Our Operations—Conventional Power—Abengoa Cogeneracion Tabasco” for additional information.

Transmission Lines Assets

Revenues and expenses for electric transmission assets reflect fixed price concession agreements with inflation adjustment mechanisms and negotiated and/or regulated rates independent from the effective utilization of the transmission lines and substations related to the projects. Our forecast assumes an Adjusted EBITDA margin of approximately 85% and receipt by us of $18.4 million per year pursuant to our preferred equity investment in ACBH, which is shown above as cash distribution from unconsolidated affiliates.

 

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Total Operating Revenue

We estimate that we will generate total operating revenue of $492 million for the twelve months ending June 30, 2015 and $576 million for the twelve months ending June 30, 2016, compared with $210.9 million for the twelve months ended December 31, 2013. This increase in our forecasted periods from the historical period is primarily attributed to the contributions from several assets that started or are expecting to start operations in late 2013 or 2014, including Solana, Mojave, ATS, Quadra 1, Quadra 2 and Palmatir. The increase in the forecast period for the twelve months ending June 30, 2016 over the twelve months ending June 30, 2015 is primarily attributed to a full twelve months of generation from Mojave.

Cost of Operations

We estimate that we will incur a cost of operations expense of $119 million for the twelve months ending June 30, 2015 and $132 million for the twelve months ending June 30, 2016, compared with $52 million for the twelve months ended December 31, 2013. This increase in our forecasted period ending June 30, 2015 from the historical period is primarily attributed to the contributions from projects that started operations in late 2013 or early 2014. The increase in the forecast period for the twelve months ending June 30, 2016 over the twelve months ending June 30, 2015 is primarily attributed to a full twelve months of generation from Mojave.

Depreciation and Amortization

We estimate that we will incur depreciation and amortization expense of $166 million for the twelve months ending June 30, 2015 and $177 million for the twelve months ending June 30, 2016, compared with $47 million for the twelve months ended December 31, 2013. This increase in our forecasted periods from the historical period is primarily attributed to the contributions from projects that started operations in late 2013 or early 2014 and the commencement of operations at Mojave. Forecasted depreciation and amortization expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies under IFRS.

General and Administrative Expenses

We estimate that we will incur general and administrative expenses, or G&A expenses, of $4.5 million for the twelve months ending June 30, 2015 and $4.6 million for the twelve months ending June 30, 2016. G&A expenses include certain shared services and administrative expenses, including our services payments to Abengoa under the Executive Services Agreement and the Support Services Agreement and specifically for the forecasts, together with the aforementioned expenses, and certain costs associated with being a public company.

Capital Expenditures

We expect our maintenance capital and operating expenditures to be minimal since they are generally limited by O&M agreements.

Any growth capital expenditures, such as new asset acquisitions, will be funded through retained cash or external financing sources (which may be debt or equity), and will not affect our cash available for distribution forecast.

Financing and Other

We estimate that interest expense will be $191 million for the twelve months ending June 30, 2015 and $193 million for the twelve months ending June 30, 2016, compared with $123.8 million for the twelve months ended December 31, 2013. The increase is primarily attributed to additional indebtedness incurred to fund the construction of Mojave. Forecasted interest expense is based on the following assumptions:

 

•

We estimate that our net debt level will be approximately $3.4 billion as of June 30, 2015 and $3.3 billion as of June 30, 2016; and

 

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•

We estimate that our borrowing costs will average 5.2% and 5.4% for the twelve months ending June 30, 2015 and June 30, 2016, respectively.

We estimate that principal amortization of indebtedness will be $51 million for the twelve months ending June 30, 2015 and $87 million for the twelve months ending June 30, 2016. The increase is primarily attributed to Mojave.

On November 14, 2013, Abengoa finalized its application for cash grant proceeds on behalf of Solana under the American Recovery and Reinvestment Act of 2009 Section 1603 (Cash Grant Program), or the 1603 Cash Grant Program, which provides a cash payment from the federal government in lieu of ITCs for eligible renewable generation sources, and will finalize its application under the same 1603 Cash Grant Program on behalf of Mojave by December 2014 or earlier. Based on recent estimates announced by the U.S. Office of Management and Budget, or OMB, for fiscal year 2014, we estimate a 7.2% reduction for awards. Assuming receipt of proceeds under the 1603 Cash Grant Program, or 1603 Cash Grant Proceeds, after giving effect to sequestration, we estimate that a portion of such proceeds will be used to pay down the amount outstanding under the cash grant bridge loan. Any remaining amount of the 1603 Cash Grant Proceeds, after giving effect to the sequestration, will be received by us.

As we classify 1603 Cash Grant Proceeds as one-time items, we have excluded the excess proceeds distributable to us from our forecasted cash available for distribution. We intend to retain such excess proceeds for general corporate purposes and to potentially fund future acquisitions of assets (whether Abengoa ROFO Assets or otherwise).

Exchange Rates

The forecast assumes that the average exchange rate between the U.S. dollar and the Euro will be approximately €1: U.S.$1.35 and €1: U.S.$1.36 for the twelve months ending June 30, 2015 and June 30, 2016, respectively.

Significant Accounting Policies

In preparing the forecast, we have applied the accounting policies used in the preparation of our financial statements shown elsewhere in this prospectus. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” and the notes to our financial statements included elsewhere in this prospectus.

Regulatory, Industry and Economic Factors

Our estimated results of operations for the forecasted period are based on the following assumptions related to regulatory, industry and economic factors:

 

•

no material nonperformance or credit-related defaults by customers, suppliers, Abengoa Concessions, S.L. or any of our commercial customers;

 

•

final validation of the approval process of the new Royal Decree and the new Ministerial Order as currently drafted (see “Regulation—Regulation in Spain—Solar Regulatory Framework Applicable to Concentrating Solar Power Plants Currently in Operation”;

 

•

no new or material amendments to United States (federal, state or local), UK, Mexican, Peruvian, Chilean, Brazilian, Uruguayan, Spanish or any other laws or regulations, or interpretation or application of existing laws or regulation, that in either case will be materially adverse to our business or to the business of our suppliers, Abengoa Concessions, S.L. or any of our commercial customers or the ability of our subsidiaries to pay dividends or make other distributions to us;

 

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•

no material adverse effects to our business, industry or the business of our suppliers, Abengoa Concessions, S.L. or any of our commercial customers on account of natural disasters;

 

•

no material adverse change resulting from supply disruptions or reduced demand for electricity; and

 

•

no material adverse changes in market, regulatory and overall economic conditions.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and combined capitalization as of March 31, 2014:

 

•

on a historical basis;

 

•

as adjusted to give effect to (i) the transfer of the preferred equity investment in ACBH, a subsidiary holding company of Abengoa that is engaged in the development, construction, investment and management of contracted concessions in Brazil, comprised mostly of transmission lines (see “Summary—Asset Transfer”), which is not included in the historical financial information, (ii) the contribution of certain related party loans that have occurred or we expect to occur prior to consummation of this offering and (iii) the repayment of debt to related parties and a reduction of equity that we expect to occur prior to the consummation of the offering. See “Unaudited Pro Forma Combined Financial Information”; and

 

•

as further adjusted to give effect to the offering and the use of proceeds set forth under the heading “Use of Proceeds.”

You should read the following table in conjunction with the sections entitled “Use of Proceeds,” “Selected Financial Information,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Unaudited Pro Forma Combined Financial Information”, our Interim Combined Financial Statements and our Annual Combined Financial Statements included elsewhere in this prospectus.

 

		As of March 31, 2014(1)
(in millions of U.S. dollars)		Historical				As Adjusted(2)				As Further Adjusted(3)
Cash and cash equivalents(4)		$	809.7			$	624.7			$	654.7
Short-term financial investments			164.3				182.7				182.7
Total cash and cash equivalents and short-term financial investments		$	974.0			$	807.4			$	837.4
Borrowings(4)			2,721.7				2,721.7				2,721.7
Notes and bonds			107.9				107.9				107.9
Non-recourse project financing (long- and short-term)		$	2,829.6			$	2,829.6			$	2,829.6
Total equity			1,486.0				1,880.5				1,910.5
Total capitalization		$	4,315.5			$	4,710.0			$	4,740.0

 

(1)

We have prepared the information presented in the “as adjusted” and “as further adjusted” columns for illustrative purposes only. The information presented in the “as adjusted” and “as further adjusted” columns addresses pro forma situations and, therefore, does not represent our actual financial position or results. Consequently, such information may not be indicative of our total capitalization as of the date of this prospectus. Investors are cautioned not to place undue reliance on this pro forma information.

(2)

As adjusted to give effect to the transfer of a preferred instrument in ACBH and to the repayment of debt held with related parties of $98.2 million (debt previously held by General Electric) and a reduction of equity by $86.8 million that we expect to occur prior to the consummation of the offering. We estimate the fair value of the preferred equity investment in ACBH to be $263 million, of which $18.4 million has been classified as a short-term financial investment, as that amount is expected to be collected in the next twelve months. In addition, prior to the consummation of this offering, we expect to contribute debt with related parties (which is equivalent to a debt capitalization from an accounting perspective) of $218.3 million.

(3)	As further adjusted to give effect to $30 million of proceeds from the offering added to cash and cash equivalents.

(4)	On April 2, 2014, Solana fully repaid the short-term tranche of its loan with the Federal Financing Bank for a total of $451 million, using the proceeds from an ITC Cash Grant payment awarded to it by the U.S. Department of the Treasury.

 

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DILUTION

Dilution is the amount by which the offering price per share paid by the purchasers of shares sold in this offering will exceed the pro forma net tangible book value per share. Pro forma net tangible book value per share as of a particular date represents the amount of our total tangible assets (which excludes intangible assets from pro forma combined assets) less pro forma combined liabilities divided by the number of shares outstanding as of that date. See “Unaudited Pro Forma Combined Financial Information.”

Dilution Information

As of March 31, 2014, our pro forma combined net tangible book value, excluding the $30 million of proceeds that will be retained by us, was $(3,292.0) million or $             per share, assuming Abengoa had contributed the assets described in the Asset Transfer in exchange for             million shares, which will occur prior to the consummation of this offering. (See “Summary—Asset Transfer”).

Immediately following the consummation of this offering, assuming that we distribute to Abengoa all of the net proceeds from this offering less $30 million as part of the consideration paid to Abengoa in connection with the Asset Transfer, our pro forma combined net tangible book value as of March 31, 2014, as adjusted, would have been $(3,262.0) million or $             per share.

Dilution per share represents the difference between the price per share to be paid by new investors for the shares sold in the offering and the pro forma combined net tangible book value per share immediately after the offering of the shares. The following table illustrates this per share dilution (assuming an initial public offering price at the midpoint of the range set forth on the front cover of this prospectus):

 

Assumed initial public offering price		$
Pro forma combined net tangible book value per share as of March 31, 2014 attributable to existing shareholders
Increase in net tangible book value per share attributable to existing investors
Pro forma consolidated net tangible book value per share, as adjusted for this offering
Dilution per share to new investors		$

If the underwriters exercise their option to purchase additional shares in full, the pro forma combined net tangible book value per share after the offering will not change, given that no new shares will be issued, as the underwriters would purchase the shares subject to such option from the selling shareholder.

If the initial public offering price were to increase or decrease by $1.00 per share, the dilution in net tangible book value would equal $             and $            , respectively.

The following table sets forth the number of shares (as applicable) purchased, the total consideration paid, or to be paid to us, and the average price per share paid, or to be paid, by our existing shareholder immediately and by the new investors, at the initial public offering price of $             per share, before deducting underwriting fees and commissions.

 

		Shares Purchased				Total Consideration
		Number		Percent		Amount		Percent		Average Price per Share
						(in $)				(in $)
Existing shareholder (Abengoa)(1)
New investors in this offering

 

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(1)

The assets contributed by Abengoa in the Asset Transfer will be recorded at the predecessor historical cost. The book value of the consideration to be provided by Abengoa in the Asset Transfer as of December 31, 2013 will be approximately the same as the pro forma combined book value as of March 31, 2014, which amounts to $1,910.5 million.

Supplemental Dilution Information

For the reasons set forth below, we believe that it is useful for investors that we present supplemental dilution information that does not exclude intangible service concession agreements from the calculation of pro forma combined net tangible book value and pro forma combined net tangible book value per share. We refer to these measures which have been calculated to include intangible service concession agreements, as supplemental pro forma combined net tangible book value and supplemental pro forma combined net tangible book value per share.

Some of our service concession agreements are accounted for as intangible assets in accordance with IFRIC 12, representing the right to future cash flows under existing concession arrangements, for a net amount of $3,677.1 million as of March 31, 2014 and $5,172.4 million on a pro forma basis as of March 31, 2014. Contracted concessional assets should be contemplated in the same way for calculations of “net tangible book value,” irrespective of whether they are recorded as financial assets or intangible assets for accounting purposes. Contracted concessional assets are our productive assets, which constitute the value of our company and the recovery of the book value of these assets is not subject to significant uncertainty or illiquidity. As a result, management believes that it is appropriate to include intangible service concession agreements in the calculation of pro forma combined net tangible book value and pro forma combined net tangible book value per share.

Had combined pro forma net tangible book value and pro forma combined net tangible book value per share been calculated so as to include intangible service concession agreements in these calculations, supplemental pro forma combined net tangible book value, excluding the $30 million of proceeds that will be retained by us, as of March 31, 2014 would have been $1,880.5 million, or $             per share. Furthermore, following the sale by us of shares in the offering at the initial public offering price of $             per share and assuming that we distribute to Abengoa all of the net proceeds from this offering less $30 million, as part of the consideration paid to Abengoa in connection with the Asset Transfer, the supplemental pro forma combined net tangible book value as of March 31, 2014 as adjusted, would have been $             per share. This would have represented an immediate increase in supplemental pro forma combined net tangible book value to existing stockholders of $             per share and an immediate dilution to new investors of $             per share. Dilution per share represents the difference between the price per share to be paid by new investors for the shares sold in the offering and supplemental combined net tangible book value per share, as adjusted for the offering of the shares. The following table illustrates this per share dilution (assuming an initial public offering price at the midpoint of the range set forth on the front cover of this prospectus):

 

Assumed initial public offering price		$
Pro forma combined net tangible book value per share as of March 31, 2014 attributable to existing shareholders
Increase in net tangible book value per share attributable to existing investors
Pro forma consolidated net tangible book value per share, as adjusted for this offering
Dilution per share to new investors		$

 

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UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION

The following unaudited pro forma combined financial information sets forth the unaudited pro forma combined income statement of Abengoa Yield for the three-month period ended March 31, 2014 and the years ended December 31, 2013 and 2012, as well as the unaudited pro forma combined statement of financial position of Abengoa Yield as of March 31, 2014 to give effect to: (i) the consolidation of Mojave, (ii) the transfer of a preferred equity investment in ACBH, (iii) the contribution of certain related party loans that have occurred or we expect to occur prior to the consummation of this offering, (iv) the repayment of debt to a related party (a third party prior to March 31, 2014) and a reduction of equity that have occurred or we expect to occur prior to the consummation of this offering and (v) the proceeds from the offering that will be retained by us to strengthen our liquidity position.

Unaudited pro forma combined financial information has been derived from, and should be read in conjunction with, the Interim Combined Financial Statements as of and for the three-month period ended March 31, 2014 and with the Annual Combined Financial Statements of our accounting predecessor as of and for the years ended December 31, 2013 and 2012 prepared in accordance with IFRS as issued by the IASB, included elsewhere in this prospectus.

We have included the unaudited pro forma combined financial information to illustrate the following, on a pro forma basis:

 

(a)

The consolidation of Mojave Solar, LLC, once we assume control over Mojave Solar, LLC, which is expected to occur when Mojave achieves COD. Mojave is currently recorded as an associate under the equity method in our Annual Combined Financial Statements. The entry into operation of Mojave, and thereby its full consolidation, is a highly probable event that will have a significant impact on our total assets and financial position. Therefore, such disclosure is considered material for investors.

 

(b)

The transfer of a preferred equity investment in ACBH, a Brazilian company that owns 15 electric transmission lines in Brazil (as described in “Business—Our Operations—Exchangeable Preferred Equity Investment in Abengoa Concessoes Brasil Holding”) which is not included in the historical combined financial statements as part of the Asset Transfer because such preferred equity investment was not made during the period covered by such financial statements.

 

(c)

The capitalization of certain related party loans which occurred in February 2014 and the contribution by Abengoa of certain related party loans that we expect to occur prior to the consummation of this offering, which is equivalent to a capitalization of debt from an accounting perspective, as we will receive the collection right of existing debt with related parties.

 

(d)

The repayment of debt to a related party (previously held by General Electric) and a reduction of equity that have occurred or we expect to occur prior to the consummation of this offering.

 

(e)

The proceeds from the offering that will be retained by us to strengthen our liquidity position.

We have elected to account for the Asset Transfer, which includes the assets mentioned above, using the predecessor values, given that these will be transactions between entities under common control. Any difference between the consideration given and the aggregate book value of the assets and liabilities of the acquired entities as of the date of the transaction will be reflected as an adjustment to equity. We present herein pro forma income statements for the three-month period ended March 31, 2014 and for the years ended December 31, 2013 and 2012, which are the same periods included in the Interim Combined Financial Statements and the Annual Combined Financial Statements.

The events above are described in more detail in notes 1 to 6 to this “Unaudited Pro Forma Combined Financial Information.”

We have assumed that the above transactions have been completed on:

 

•

January 1, 2012 for the purpose of presenting the Unaudited Pro Forma Combined Income Statement for the three-month period ended March 31, 2014 and the Unaudited Pro Forma Income Statement for the years ended December 31, 2013 and 2012.

 

•

March 31, 2014 for the purpose of presenting the Unaudited Pro Forma Combined Statement of Financial Position as of March 31, 2014.

 

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The unaudited pro forma combined financial information is presented for illustrative purposes only and reflects estimates and certain assumptions made by our management that are considered reasonable under the circumstances as of the date of this prospectus and which are based on the information available at the time of the preparation of the unaudited pro forma combined financial information. Actual adjustments may differ materially from the information presented herein. The unaudited pro forma combined financial information does not purport to represent what our combined income statement and combined statement of financial position would have been if the relevant transactions had occurred on the dates indicated and is not intended to project our consolidated results of operations or consolidated financial position for any future period or date.

Unaudited Pro Forma Combined Income Statement for the three-month period ended March 31, 2014

 

		Historical Combined information				Pro Forma adjustments for Mojave consolidation(1)				Pro Forma adjustments for the preferred shares  of ACBH(2)				Pro Forma adjustments for debt capitalization(3)				Pro Forma adjustments for debt repayment and  capital reduction(4)				Pro Forma Abengoa Yield
		(in millions of U.S. dollars)
Revenue		$	63.8				—				—				—				—			$	63.8
Other operating income			20.3				—				—				—				—				20.3
Raw materials and consumables used.			(4.5	)			—				—				—				—				(4.5	)
Employee benefit expenses			(1.7	)			—				—				—				—				(1.7	)
Depreciation, amortization and impairment charges			(27.2	)			(0.0	)			—				—				—				(27.2	)
Other operating expenses			(26.8	)			(0.0	)			—				—				—				(26.8	)
Operating Profit/(loss)		$	23.9			$	(0.0	)			—				—				—			$	23.9
Financial income			0.2				—				4.6												4.8
Financial expenses			(54.3	)			—				—				6.3				2.5				(45.5	)
Net exchange differences			0.6				—				—				—				—				0.6
Other financial income/expenses, net.			(0.4	)			(0.0	)			—				—				—				(0.4	)
Financial expense, net		$	(54.0	)		$	(0.0	)		$	4.6			$	6.3			$	2.5			$	(40.6	)
Share of (loss)/profit of associates carried under the equity method		$	(0.3	)		$	0.0								—				—			$	(0.3	)
Profit/(loss) before income tax		$	(30.4	)		$	(0.0	)		$	4.6			$	6.3			$	2.5			$	(17.0	)
Income tax			1.8				—								—				—				1.8
Profit/(loss) for the year		$	(28.6	)		$	(0.0	)		$	4.6			$	6.3			$	2.5			$	(15.2	)
Profit attributable to non-controlling interests			1.7				—				—				—				—				1.7
Profit/(loss) for the year attributable to the combined group		$	(26.9	)		$	(0.0	)		$	4.6			$	6.3			$	2.5			$	(13.5	)
Number of ordinary shares outstanding (millions)(5)																							80.0
Earnings per share (U.S.$ per share)(5)																						$	(0.17	)

 

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Unaudited Pro Forma Combined Income Statement for the year ended December 31, 2013

 

		Historical combined information				Pro Forma adjustment for Mojave consolidation(1)				Pro Forma adjustment for the preferred shares of ACBH(2)				Pro Forma adjustments for debt capitalization(3)				Pro Forma adjustments for debt repayment and capital reduction(4)				Pro Forma Abengoa Yield
		(in millions of U.S. dollars)
Revenue		$	210.9				—				—				—				—			$	210.9
Other operating income			379.6				—				—				—				—				379.6
Raw materials and consumables used			(8.7	)			—				—				—				—				(8.7	)
Employee benefit expenses			(2.4	)			—				—				—				—				(2.4	)
Depreciation, amortization, and impairment charges			(46.9	)			—				—				—				—				(46.9	)
Other operating expenses			(420.9	)			(0.1	)			—				—				—				(421.0	)
Operating Profit/(loss)		$	111.6			$	(0.1	)			—				—				—			$	111.5
Financial income			1.2				—				18.4				—				—				19.6
Financial expenses			(123.8	)			(0.1	)			—				27.0				10.6				(86.3	)
Net exchange differences			(0.9	)			—				—				—				—				(0.9	)
Other financial income/expenses, net			(1.7	)			0.3				—				—				—				(1.4	)
Financial expense, net		$	(125.2	)		$	0.1			$	18.4			$	27.0			$	10.6			$	(69.1	)
Share of (loss)/profit of associates carried under the equity method		$	—				—				—				—				—			$	—
Profit/(loss) before income tax		$	(13.6	)		$	—			$	18.4			$	27.0			$	10.6			$	42.4
Income tax			11.8				—				—				—				—				11.8
Profit/(loss) for the year		$	(1.8	)		$	0.1			$	18.4			$	27.0			$	10.6			$	54.2
Profit/(loss) attributable to non-controlling interests			(1.6	)			—				—				—				—				(1.6	)
Profit/(loss) for the year attributable to the combined group		$	(3.4	)		$	0.1			$	18.4			$	27.0			$	10.6			$	52.6
Number of ordinary shares outstanding (millions)(5)																							80.0
Earnings per share (U.S.$ per share)(5)																						$	0.66

 

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Unaudited Pro Forma Combined Income Statement for the year ended December 31, 2012

 

		Historical combined information				Pro Forma adjustment for Mojave consolidation(1)				Pro Forma adjustment for the preferred shares of ACBH(2)				Pro Forma adjustments for debt capitalization(3)				Pro Forma adjustments for debt repayment and capital reduction(4)				Pro Forma Abengoa Yield
		(in millions of U.S. dollars)
Revenue		$	107.2				—				—				—				—			$	107.2
Other operating income			560.4				—				—				—				—				560.4
Raw materials and consumables used			(4.3	)			—				—				—				—				(4.3	)
Employee benefit expenses			(1.8	)			—				—				—				—				(1.8	)
Depreciation, amortization, and impairment charges			(20.2	)			—				—				—				—				(20.2	)
Other operating expenses			(573.5	)			(0.4	)			—				—				—				(573.9	)
Operating Profit/(loss)		$	67.7			$	(0.4	)			—				—				—			$	67.4
Financial income			0.7				—				18.4				—				—				19.1
Financial expenses			(64.1	)			—				—				2.8				7.3				(53.9	)
Net exchange differences			0.4				—				—				—				—				0.4
Other financial income/expenses, net			(0.2	)			—				—				—				—				(0.2	)
Financial expense, net		$	(63.2	)			—			$	18.4			$	2.8			$	7.3			$	(34.6	)
Share of (loss)/profit of associates carried under the equity method		$	(0.4	)			—				—				—				—			$	(0.4	)
Profit/(loss) before income tax		$	4.2			$	(0.4	)		$	18.4			$	2.8			$	7.3			$	32.4
Income tax			(4.0	)			—				—				—				—				(4.0	)
Profit/(loss) for the period		$	0.1			$	(0.4	)		$	18.4			$	2.8			$	7.3			$	28.4
Profit attributable to non-controlling interests			1.2				—				—				—				—				1.2
Profit/(loss) for the period attributable to the combined group		$	1.3			$	(0.4	)		$	18.4			$	2.8			$	7.3			$	29.6
Number of ordinary shares outstanding (millions)(5)																							80.0
Earnings per share (U.S.$ per share)(5)																						$	0.37

 

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Unaudited Pro Forma Combined Statement of Financial Position as of March 31, 2014

 

		Historical Combined Information				Pro Forma adjustments for Mojave consolidation(1)				Pro Forma adjustments for the preferred shares of ACBH(2)				Pro Forma adjustments for debt capitalization(3)				Pro Forma adjustments for debt repayment and capital reduction(4)				Pro Forma adjustments for Proceeds of the offering(6)				Pro Forma Abengoa Yield
		(in millions of U.S. dollars)
Non-current assets
Contracted concessional assets		$	4,400.7			$	1,495.3				—				—				—				—			$	5,896.0
Investments carried under the equity method			402.6				(396.9	)			—				—				—				—				5.8
Financial investments			73.6				15.3				244.6				—				—				—				333.6
Deferred tax assets			44.7				—				—				—				—				—				44.7
Total Non-Current Assets		$	4,921.7			$	1,113.8			$	244.6				—			$	0.0				—			$	6,280.1
Current assets
Inventories			5.4				—				—				—				—				—				5.4
Clients and other receivables			94.2				0.6				—				—				—				—				94.8
Financial investments			164.3				20.4				18.4				—				—				—				203.1
Cash and cash equivalents			809.7				0.6				—				—				(185.0	)			30.0				655.3
Total Current Assets			1,073.6				21.7				18.4				—				(185.0	)		$	30.0			$	958.6
Total Assets		$	5,995.3			$	1,135.5			$	263.0				—			$	(185.0	)		$	30.0			$	7,238.7
Equity and Liabilities
Total Equity		$	1,486.0			$	0.0			$	263.0			$	218.3			$	(86.8	)		$	30.0			$	1,910.5
Non-current liabilities
Long-term non-recourse (project financing)			2,312.5				796.1				—				—				—				—				3,108.6
Grants and other liabilities			1,055.1				266.4				—				—				—				—				1,321.6
Related parties			369.6				—				—				(218.3	)			(98.2	)			—				53.1
Derivative liabilities			71.4				—				—				—				—				—				71.4
Deferred tax liabilities			3.3				—				—				—				—								3.3
Total Non-Current Liabilities		$	3,812.0			$	1,062.5			$	0.0			$	(218.3	)		$	(98.2	)						$	4,558.0
Current Liabilities
Short-term non-recourse (project financing)			517.1				7.0				—				—				—				—				524.1
Trade payables and other current liabilities			178.4				65.9				—				—				—				—				244.4
Income and other tax payables			1.8				—				—				—				—				—				1.8
Total Current Liabilities		$	697.3			$	72.9			$	0.0				—				—				—				770.2
Total Equity and Liabilities		$	5,995.3			$	1,135.5			$	263.0				—			$	(185.0	)		$	30.0			$	7,238.7

 

(1)

Reflects the impact of consolidating Mojave Solar LLC, the company that holds our Mojave project, which is recorded under the equity method during its construction period. We have derived the pro forma adjustments in the pro forma combined income statement for Mojave’s consolidation from Mojave’s income statement for the years ended December 31, 2013 and 2012 and for the three-month period ended March 31, 2014; we have not made any adjustments to reflect the construction in progress performed by related parties in 2013, 2012 or in the three-month period ended March 31, 2014 because Mojave will be operational when it is consolidated. Mojave is expected to enter into operation by October 2014 and will be fully consolidated once we obtain control over Mojave Solar LLC.

We reassess whether or not we control an investee when facts and circumstances indicate that there are changes to the elements that determine control (power over the investee, exposition to variable returns of the investee and ability to use its power to affect its returns).

 

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We concluded that during the construction phase of Mojave all the relevant decisions were subject to the control and approval of a third party. As a result, we did not have control over Mojave during the construction period. IFRS 10 (B80) provides that control requires a continuous assessment and that we shall reassess if it controls an investee if facts and circumstances indicate that there are changes to the elements of control. Once Mojave enters into operation, the decision-making process will change, the investee will be controlled and it will be fully consolidated. Because during the construction period the assets were included under the scope of IFRIC 12, we estimate that the book value of consolidated assets and liabilities will be similar to its fair value.

(2)

Reflects a preferred equity investment in ACBH, a subsidiary holding company of Abengoa that is engaged in the development, construction, investment and management of contracted concessions in Brazil, comprised mostly of transmission lines. This investment is not reflected in our historical combined financial statements; as a result it has been included as an adjustment in the unaudited pro forma combined financial statements. The expected annual dividend is $18.4 million ($4.6 million per quarter), and we estimate the expected fair value of this instrument to be $263 million.

(3)

Reflects the capitalization of certain related party loans and the contribution by Abengoa of certain related party loans that have occurred or we expect to occur prior to the consummation of this offering, which is equivalent to a capitalization of debt from an accounting perspective, as we will receive the collection right of existing debt with related parties. The total debt to be capitalized amounted to $439.4 million as of December 31, 2013 and $164.0 million as of December 31, 2012. As of March 31, 2014, our Interim Combined Financial Statements already show the capitalization of loans with related parties amounting to $232.1 million; therefore, the pro forma adjustment for purposes of the statement of financial position reflects only the contribution by Abengoa of certain related party loans receivable of $218.3 million that we expect to occur prior to the consummation of this offering.

(4)

Reflects the purchase of the 15% interest in ACT held by General Electric, and a preferred interest in ACT also held by General Electric which is considered debt from an accounting perspective given the characteristics of the investment. This debt amounted to $98.2 million as of March 31, 2014 ($95.7 million as of December 31, 2013 and $66.7 million as of December 31, 2012). On March 21, 2014 the interest in ACT held by General Electric was purchased by a related party. As a result, this amount is included in payables to “Related parties” in the historical statement of financial position as of March 31, 2014. In addition, the adjustment reflects a reduction of equity of $86.8 million to be made prior to consummation of this offering.

(5)

We have calculated earnings per share assuming a total of 80,000,000 shares outstanding after the consummation of this offering. Since our predecessor is a combination of entities under the common control of Abengoa and did not have any share capital as of December 31, 2013 or 2012, we have not calculated earnings per share on an historical basis.

(6)	Reflects the proceeds from this offering that will be retained by us to strengthen our liquidity position.

 

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SELECTED FINANCIAL INFORMATION

The selected combined financial information as of March 31, 2014 and for the three-month periods ended March 31, 2014 and 2013, and as of and for the years ended December 31, 2013 and 2012, and as of January 1, 2012, is not intended to be an indicator of our financial condition or results of operations in the future. You should review such selected combined financial information together with our Annual Combined Financial Statements and our Interim Combined Financial Statements and notes thereto, included elsewhere in this prospectus.

The following tables should be read in conjunction with “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Annual Combined Financial Statements and our Interim Combined Financial Statements and related notes included elsewhere in this prospectus.

Combined Income Statement

 

(in millions of U.S. dollars)		Three-month period ended March 31,								Year ended December 31,
		2014				2013				2013				2012
			(unaudited)
Operating revenues and costs
Revenue		$	63.8			$	32.3			$	210.9			$	107.2
Other operating income			20.3				97.9				379.6				560.4
Raw materials and consumables used			(4.5	)			(0.5	)			(8.7	)			(4.3	)
Employee benefit expense			(1.7	)			(0.6	)			(2.4	)			(1.8	)
Depreciation, amortization and impairment charges			(27.2	)			(8.5	)			(46.9	)			(20.2	)
Other operating expenses			(26.8	)			(103.9	)			(420.9	)			(573.6	)
Operating profit		$	23.9			$	16.8			$	111.6			$	67.7
Finance income			0.2				0.4				1.2				0.7
Finance expense			(54.3	)			(20.6	)			(123.8	)			(64.1	)
Net exchange differences			0.6				(0.4	)			(0.9	)			0.4
Other financial income/(expense), net			(0.4	)			(1.7	)			(1.7	)			(0.2	)
Finance expense, net		$	(54.0	)		$	(22.4	)		$	(125.2	)		$	(63.2	)
Share of (loss)/profit of associates carried under the equity method			(0.3	)			(0.1	)			—				(0.4	)
Profit/(loss) before income tax		$	(30.4	)		$	(5.7	)		$	(13.6	)		$	4.2
Income tax benefit/(expense)			1.8				(0.8	)			11.8				(4.0	)
Profit/(loss) for the period		$	(28.6	)		$	(6.6	)		$	(1.8	)		$	0.1
Profit/(loss) attributable to non-controlling interest			1.7				1.6				(1.6	)			1.2
Profit/(loss) for the period attributable to the combined group		$	(26.9	)		$	(4.9	)		$	(3.4	)		$	1.3

 

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Combined Statement of Financial Position

 

(in millions of U.S. dollars)		As of March 31,				As of December 31,								As of January 1,
		2014				2013				2012				2012
			(unaudited)
Non-current assets:
Contracted concessional assets		$	4,400.7			$	4,418.1			$	2,058.9			$	1,546.8
Investments in associates carried under the equity method			402.6				387.3				734.1				180.2
Financial investments and other			73.6				28.9				13.7				9.4
Deferred tax assets			44.7				52.8				60.2				44.1
Total non-current assets		$	4,921.7			$	4,887.1			$	2,866.9			$	1,780.5
Current assets:
Inventories		$	5.4			$	5.2			$	—			$	—
Clients and other receivables			94.2				97.6				106.1				124.8
Financial investments			164.3				266.4				127.6				101.7
Cash and cash equivalents			809.7				357.7				97.5				40.2
Total current assets		$	1,073.6			$	726.9			$	331.2			$	266.7
Total assets		$	5,995.3			$	5,614.0			$	3,198.1			$	2,047.2
Total equity			1,486.0				1,287.2				1,139.8				583.9
Non-current liabilities:
Long-term non-recourse project financing			2,312.5				2,842.4				1,320.0				1,003.2
Other liabilities			1,499.5				1,209.4				502.2				214.6
Total non-current liabilities		$	3,812.0			$	4,051.8			$	1,822.2			$	1,217.8
Current liabilities:
Short-term non-recourse project financing			517.1				52.4				48.9				78.7
Other liabilities			180.2				222.6				187.2				166.8
Total current liabilities			697.3				275.0				236.1				245.5
Equity and Total liabilities		$	5,995.3			$	5,614.0			$	3,198.1			$	2,047.2

Combined Cash Flow Statement

 

(in millions of U.S. dollars)		Three-month period ended March 31,								Year ended December 31,
		2014				2013				2013				2012
			(unaudited)
Gross cash flows from operating activities
Profit/(loss) for the year		$	(28.6	)		$	(6.6	)		$	(1.8	)		$	0.1
Adjustments to reconcile after-tax profit to net cash generated by operating activities			76.2				8.0				92.4				22.8
Net interest/taxes paid			(11.8	)			(0.4	)			(62.4	)			(41.6	)
Variations in working capital			(36.3	)			(7.5	)			9.2				66.6
Total net cash flow generated by (used in) operating activities		$	(0.5	)		$	(6.5	)		$	37.4			$	47.9
Net cash flows from investment activities
Investments			(26.3	)			(133.0	)			(694.6	)			(1,098.7	)
Disposals			(13.6	)			(4.0	)			—				—
Total net cash flows used in investment activities		$	(39.9	)		$	(137.0	)		$	(694.6	)		$	(1,098.7	)
Net cash flows generated by finance activities		$	492.5			$	185.3			$	914.9			$	1,107.3
Net increase/(decrease) in cash and cash equivalents			452.1				41.8				257.7				56.5
Cash and cash equivalents at the beginning of the period			357.7				97.5				97.5				40.2
Currency translation difference on cash and cash equivalents			(0.1	)			(1.2	)			2.5				0.8
Cash and cash equivalents at the end of the period		$	809.7			$	138.1			$	357.7			$	97.5

 

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Geography and business sector data

Revenue by geography

 

(in millions of U.S. dollars)		Three-month period ended March 31,								Year ended December 31,
		2014				2013				2013				2012
			(unaudited)
North America		$	42.9			$	20.0			$	114.0			$	62.3
South America			14.3				5.7				25.4				17.0
Europe			6.7				6.7				71.5				27.9
Total revenue		$	63.8			$	32.3			$	210.9			$	107.2

Revenue by business sectors

 

(in millions of U.S. dollars)		Three-month period ended March 31,								Year ended December 31,
		2014				2013				2013				2012
			(unaudited)
Renewable Energy		$	20.8			$	6.7			$	82.7			$	27.9
Conventional Power			28.8				20.0				102.8				62.3
Electric Transmission			14.3				5.7				25.4				17.0
Total revenue		$	63.8			$	32.3			$	210.9			$	107.2

Non-GAAP Financial Data

Adjusted EBITDA by geography

 

(in millions of U.S. dollars)		Three-month period ended March 31,								Year ended December 31,
		2014				2013				2013				2012
			(unaudited)
North America		$	37.2			$	18.6			$	96.7			$	61.1
South America			11.0				3.9				19.0				10.2
Europe			2.9				2.8				42.8				16.7
Adjusted EBITDA(1)		$	51.1			$	25.3			$	158.5			$	88.0

Adjusted EBITDA by business sectors

 

(in millions of U.S. dollars)		Three-month period ended March 31,								Year ended December 31,
		2014				2013				2013				2012
			(unaudited)
Renewable Energy		$	16.6			$	2.7			$	55.8			$	16.1
Conventional Power			23.5				18.6				83.3				61.1
Electric Transmission			11.1				4.0				19.4				10.8
Adjusted EBITDA(1)		$	51.1			$	25.3			$	158.5			$	88.0

 

(1)

Adjusted EBITDA is calculated as profit for the period from continuing operations, after adding back income tax expense, share of (loss)/profit of associates, finance expense net and depreciation, amortization and impairment charges of the combined entities. Adjusted EBITDA is not a measurement of performance under IFRS as issued by the IASB, and you should not consider Adjusted EBITDA as an alternative to operating income or profits or as a measure of our operating performance, cash flows from operating, investing and financing activities or as a measure of our ability to meet our cash needs or any other measures of performance under generally accepted accounting principles. We believe that Adjusted EBITDA is a useful indicator of our ability to incur and service our indebtedness and can assist securities analysts, investors and other parties to evaluate us. Adjusted EBITDA and similar measures are used by different companies for different purposes and are often calculated in ways that reflect the circumstances of those companies. Adjusted EBITDA may not be indicative of our historical operating results, and is not are meant to be predictive of potential future results. See “Presentation of Financial Information—Non-GAAP Financial Measures.”

 

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The following table sets forth a reconciliation of Adjusted EBITDA to our profit/(loss) for the period from continuing operations:

 

(in millions of U.S. dollars)		Three-month period ended March 31,								Year ended December 31,
		2014				2013				2013				2012
Reconciliation of profit/(loss) for the year to Adjusted EBITDA
Profit/(loss) for the year attributable to the combined group		$	(26.9	)		$	(4.9	)		$	(3.4	)		$	1.3
Profit/(loss) attributable to non-controlling interest from continued operations			(1.7)				(1.6)				1.6				(1.2)
Income tax expenses/(benefits)			(1.8)				0.8				(11.8)				4.0
Share of loss/(profit) of associated companies			0.3				0.1				—				0.4
Financial expenses, net			54.0				22.4				125.2				63.2
Operating profit		$	23.9			$	16.8			$	111.6			$	67.7
Depreciation, amortization and impairment charges			27.2				8.5				46.9				20.2
Adjusted EBITDA (unaudited)		$	51.1			$	25.3			$	158.5			$	88.0

The following table sets forth a reconciliation of Adjusted EBITDA to our net cash generated by operating activities:

 

(in millions of U.S. dollars)		Three-month period ended March 31,								Year ended December 31,
		2014				2013				2013				2012
Reconciliation of Adjusted EBITDA to net cash generated by operating activities
Adjusted EBITDA (unaudited)		$	51.2			$	25.3			$	158.5			$	88.0
Other cash finance costs and other			(25.3)				(23.9)				(67.9)				(65.0)
Variations in working capital			(14.5)				(7.5)				9.2				66.6
Income tax (paid)/received			0.2				(0.2)				(0.1)				(0.3)
Interests (paid)/received			(12.0)				(0.2)				(62.3)				(41.4)
Net cash generated by operating activities		$	(0.5	)		$	(6.5	)		$	37.4			$	47.9

Unaudited Pro Forma Combined Financial Information

The following unaudited pro forma combined financial information sets forth the unaudited pro forma combined income statement of Abengoa Yield for the three-month period ended March 31, 2014 and the years ended December 31, 2013 and 2012, as well as the unaudited pro forma combined statement of financial position of Abengoa Yield as of March 31, 2014 to give effect to the consolidation of Mojave, to the transfer of a preferred equity investment in ACBH, to the contribution of certain related party loans that have occurred or we expect to occur prior to the consummation of this offering, to the repayment of debt to a related party (a third party prior to March 31, 2014), a reduction of equity that has occurred or we expect to occur prior to the consummation of this offering and to the proceeds of this offering that we will retain.

 

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Unaudited Pro Forma Combined Income Statement for the three-month period ended March 31, 2014 and the years ended December 31, 2013 and 2012

 

		Pro Forma Abengoa Yield
		For the three-month period ended March 31,				For the years ended December 31,
		2014				2013				2012
Revenue		$	63.8			$	210.9			$	107.2
Other operating income			20.3				379.6				560.4
Raw materials and consumables used			(4.5	)			(8.7	)			(4.3	)
Employee benefit expenses			(1.7	)			(2.4	)			(1.8	)
Depreciation, amortization, and impairment charges			(27.2	)			(46.9	)			(20.2	)
Other operating expenses			(26.8	)			(421.0	)			(573.9	)
Operating Profit/(loss)		$	23.9			$	111.5			$	67.4
Financial income			4.8				19.6				19.1
Financial expenses			(45.5	)			(86.3	)			(53.9	)
Net exchange differences			0.6				(0.9	)			0.4
Other financial income/expenses, net			(0.4	)			(1.4	)			(0.2	)
Financial expense, net		$	(40.6	)		$	(69.1	)		$	(34.6	)
Share of (loss)/profit of Associates carried under the equity method		$	(0.3	)		$	—			$	(0.4	)
Profit/(loss) before Income Tax		$	(17.0	)		$	42.4			$	32.4
Income tax			1.8				11.8				(4.0	)
Profit/(loss) for the period		$	(15.2	)		$	54.2			$	28.4
Profit/(loss) attributable to non-controlling interests			1.7				(1.6	)			1.2
Profit/(loss) for the period attributable to the combined group		$	(13.5	)		$	52.6			$	29.6
Number of ordinary shares outstanding (millions)			80.0				80.0				80.0
Earnings per Share (U.S.$ per share)(1)		$	(0.17	)		$	0.66			$	0.37

 

(1)

We have calculated earnings per share assuming a total of 80,000,000 shares outstanding after the consummation of this offering. Since our predecessor is a combination of entities under common control of Abengoa and did not have any share capital as of December 31, 2013 or 2012, we have not calculated earnings per share on an historical basis.

 

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Unaudited Pro Forma Combined Statement of Financial Position as of March 31, 2014

 

		Abengoa Yield Pro Forma
Non-current assets
Contracted concessional assets		$	5,896.0
Investments carried under the equity method			5.8
Financial investments			333.6
Deferred tax assets			44.7
Total Non-Current Assets		$	6,280.1
Current assets
Inventories			5.4
Clients and Other Receivables			94.8
Financial Investments			203.1
Cash and Cash Equivalents			655.3
Total Current Assets			958.6
Total Assets		$	7,238.7
Equity and Liabilities
Total Equity		$	1,910.5
Non-Current Liabilities
Long-term Non-Recourse (Project Financing)			3,108.6
Grants and other liabilities			1,321.6
Related parties			53.1
Derivative liabilities			71.4
Deferred tax liabilities			3.3
Total Non-Current Liabilities		$	4,558.0
Current Liabilities
Short-term Non-Recourse (Project Financing)			524.1
Trade Payables and Other Current Liabilities			244.4
Income and other tax payables			1.8
Total Current Liabilities		$	770.2
Total Equity and Liabilities		$	7,238.7

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Our Interim Combined Financial Statements and our Annual Combined Financial Statements appearing elsewhere in this prospectus were prepared on a “carve-out” basis from Abengoa and are intended to represent the financial results during those periods of a portfolio of renewable energy, conventional power and electric transmission line assets in North America (the United States and Mexico), South America (Peru, Chile and Uruguay) and Europe (Spain) that will be contributed to us as part of the Asset Transfer.

The following discussion should be read together with, and is qualified in its entirety by reference to, our Interim Combined Financial Statements and our Annual Combined Financial Statements, included elsewhere in this prospectus, which have been prepared in accordance with IFRS as issued by the IASB. The following discussion contains forward-looking statements that reflect our plans, estimates and beliefs, which are based on assumptions we believe to be reasonable. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are a dividend growth-oriented company formed to serve as the primary vehicle through which Abengoa will own, manage and acquire renewable energy, conventional power and electric transmission lines and other contracted revenue-generating assets, initially focused on North America (the United States and Mexico) and South America (Peru, Chile, Uruguay and Brazil), as well as Europe (Spain). In the future, we intend to expand this presence to selected countries in Africa and the Middle East.

We believe we are well positioned to be a premier company for investors seeking a total return based on stable and growing dividend income from a diversified portfolio of low-risk, high-quality assets, and for investors with a key objective of accretive dividend growth.

We intend to take advantage of favorable trends in the power generation and electric transmission sectors globally, including energy scarcity and a focus on the reduction of carbon emissions. To that end, we believe that our cash flow profile, coupled with our scale, diversity and low-cost business model, will offer us a lower cost of capital than that of a traditional engineering or construction company and independent power producer and provide us with a significant competitive advantage with which to execute our growth strategy.

With this business model, our objective is to pay a consistent and growing cash dividend to holders of our shares that is sustainable on a long-term basis. We expect to target a payout ratio of 90% of our cash available for distribution and will seek to increase such cash dividends over time through organic growth and as we acquire assets with characteristics similar to those in our current portfolio. We will focus on high-quality, newly-constructed and long-life facilities with creditworthy counterparties that we expect will produce stable, long-term cash flows.

Upon consummation of this offering, we will own eleven assets, comprising 710 MW of renewable energy generation, 300 MW of conventional power generation and 1,018 miles of electric transmission lines and an exchangeable preferred equity investment in ACBH. Each of the assets we own has a project-finance agreement in place. Our project-level debt was approximately $2,830 million as of March 31, 2014.

We have signed an exclusive agreement with Abengoa, referred to as the ROFO Agreement, which provides us with a right of first offer on any proposed sale, transfer or other disposition of any of Abengoa’s contracted renewable energy, conventional power, electric transmission lines or water assets in operation and located in North America, Chile, Peru, Uruguay, Brazil, Colombia and the European Union, as well as four assets in selected countries in Africa and the Middle East. We refer to the contracted assets subject to the ROFO Agreement as the

 

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“Abengoa ROFO Assets.” See “Related Party Transactions—Right of First Offer.” Based on the acquisition opportunities available to us, which include the Abengoa ROFO Assets as well as any third-party acquisitions we pursue, we believe that we will have the opportunity to grow our cash available for distribution in a manner that would allow us to further increase our cash dividends per share over time. Prospective investors should read “Cash Dividend Policy,” including our financial forecast and related assumptions, and “Risk Factors,” including the risks and uncertainties related to our forecasted results, acquisition opportunities and growth plan, in their entirety.

We own a diversified portfolio of renewable energy, conventional power and electric transmission line contracted assets in North America (the United States and Mexico) and South America (Peru, Chile, Uruguay and Brazil), as well as in Spain. Our portfolio consists of five renewable energy assets, a cogeneration facility and several electric transmission lines, all of which are fully operational, with the exception of Palmatir, construction of which is complete and which we expect to be fully operational in May 2014, and Mojave, construction of which is substantially complete and which we expect to be fully operational by October 2014. In addition, we own an exchangeable preferred equity investment in ACBH, a subsidiary holding company of Abengoa that is engaged in the development, construction, investment and management of contracted concessions in Brazil, consisting mostly of transmission lines. All of our assets have contracted revenues (regulated revenues in the case of the Spanish assets) with low-risk offtakers and collectively have an average remaining contract life of approximately 26 years as of December 31, 2013. Over 90% of cash available for distribution from these assets in each of the next four years will be in U.S. dollars or indexed to the U.S. dollar and our policy is to use currency coverage contracts if required to maintain that ratio. Over 90% of our project-level debt is hedged against changes in interest rates through an underlying fixed rate on the debt instrument or through interest rate swaps, caps or similar hedging instruments.

Our revenue and Adjusted EBITDA by geography and business sector for the three-month periods ended March 31, 2014 and 2013 and for the years ended December 31, 2013 and 2012 are set forth in the following tables:

 

		Three-month period ended March 31,																Year ended December 31,
Revenue by geography		2014 (unaudited)								2013 (unaudited)								2013								2012
		$ in millions				% of revenue				$ in millions				% of revenue				$ in millions				% of revenue				$ in millions				% of revenue
North America		$	42.9				67.1	%		$	20.0				61.8	%		$	114.0				54.1	%		$	62.3				58.1	%
South America			14.3				22.4	%			5.7				17.5	%			25.4				12.0	%			17.0				15.9	%
Europe			6.7				10.5	%			6.7				20.7	%			71.5				33.9	%			27.9				26.0	%
Total revenue		$	63.8				100.0	%		$	32.3				100.0	%		$	210.9				100.0	%		$	107.2				100.0	%

 

		Three-month period ended March 31,																Year ended December 31,
Revenue by business sector		2014 (unaudited)								2013 (unaudited)								2013								2012
		$ in millions				% of revenue				$ in millions				% of revenue				$ in millions				% of revenue				$ in millions				% of revenue
Renewable energy		$	20.8				32.6	%		$	6.7				20.7	%		$	82.7				39.2	%		$	27.9				26.0	%
Conventional power			28.8				45.1	%			20.0				61.8	%			102.8				48.7	%			62.3				58.1	%
Electric transmission lines			14.3				22.3	%			5.7				17.5	%			25.4				12.1	%			17.0				15.9	%
Total revenue		$	63.8				100.0	%		$	32.3				100.0	%		$	210.9				100.0	%		$	107.2				100.0	%

 

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		Three-month period ended March 31,																Year ended December 31,
Adjusted EBITDA by geography		2014 (unaudited)								2013 (unaudited)								2013								2012
		$ in millions				% of revenue				$ in millions				% of revenue				$ in millions				% of revenue				$ in millions				% of revenue
North America		$	37.2				86.8	%		$	18.6				93.2	%		$	96.7				84.8	%		$	61.1				98.1	%
South America			11.0				77.1	%			3.9				69.1	%			19.0				74.8	%			10.2				60.0	%
Europe			2.9				44.0	%			2.8				41.9	%			42.8				59.9	%			16.7				59.9	%
Adjusted EBITDA		$	51.1				80.1	%		$	25.3				78.4	%		$	158.5				75.2	%		$	88.0				82.1	%

 

		Three-month period ended March 31,																Year ended December 31,
Adjusted EBITDA by business sector		2014 (unaudited)								2013 (unaudited)								2013								2012
		$ in millions				% of revenue				$ in millions				% of revenue				$ in millions				% of revenue				$ in millions				% of revenue
Renewable energy		$	16.6				79.8	%		$	2.7				40.7	%		$	55.8				67.5	%		$	16.1				57.7	%
Conventional power			23.5				81.6	%			18.6				93.2	%			83.3				81.0	%			61.1				98.1	%
Electric transmission lines			11.1				77.7	%			4.0				70.4	%			19.4				76.4	%			10.8				63.5	%
Adjusted EBITDA		$	51.1				80.1	%		$	25.3				78.4	%		$	158.5				75.2	%		$	88.0				82.1	%

Factors Affecting our Results of Operations

Commencement of operations of projects

The comparability of our results of operations is significantly influenced by the volume of projects that become operational during a particular year. The number of projects becoming operational and the length of lead times for projects under construction significantly affect our revenue and operating profit, which makes the comparison of periods difficult.

 

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The following table sets forth our assets that were in or commenced operation through March 31, 2014 and during each of the years ended December 31, 2013 and 2012, and those expected to commence in the subsequent quarters of 2014, including the quarter in which operations began or are expected to begin:

 

Geography Segment		Asset		Business Sector		Capacity		Status		Commercial Operation Date
North America		Solana		Renewable energy		280 MW		Operational		4Q 2013
		Mojave		Renewable energy		280 MW		Startup and Production Testing		4Q 2014(*)
		ACT		Conventional power		300 MW		Operational		2Q 2013
South America		ATN		Electric transmission		362 miles		Operational		1Q 2011
		ATS		Electric transmission		569 miles		Operational		1Q 2014
		Quadra 1		Electric transmission		49 miles		Operational		2Q 2014
		Quadra 2		Electric transmission		32 miles		Operational		1Q 2014
		Palmucho		Electric transmission		6 miles		Operational		4Q 2007
		Palmatir		Renewable energy		50 MW		Startup and Production Testing		2Q 2014(*)
Europe		Solaben 2		Renewable energy		50 MW		Operational		2Q 2012
		Solaben 3		Renewable energy		50 MW		Operational		4Q 2012

 

(*)	Expected commercial operation date.

Regulation

We operate in a significant number of regulated markets. The degree of regulation to which our activities are subject varies by country. In a number of the countries in which we operate, regulation is carried out by national regulatory authorities. In some countries, such as the United States and, to a certain degree, Spain, there are various additional layers of regulation at the state, regional and/or local levels. In such countries, the scope, nature, and extent of regulation may differ among the various states, regions and/or localities.

While we believe the requisite authorizations, permits, and approvals for our existing activities have been obtained and that our activities are operated in substantial compliance with applicable laws and regulations, we remain subject to a varied and complex body of laws and regulations that both public officials and private parties may seek to enforce. See “Regulation” for a description of the primary industry-related regulations applicable to our activities in the United States and Spain and currently in force in certain of the principal markets in which we operate.

Power purchase agreements and other contracted revenue agreements

As of December 31, 2013, the average remaining life of our PPAs, concessions and contracted revenue agreements was approximately 26 years. We believe that the average life of our PPAs and contracted revenue agreements is a significant indicator of our forecasted revenue streams and the growth of our business. Contracted assets and concessions consist of long-term projects awarded to and undertaken by us (in conjunction with other companies or on an exclusive basis) typically over a term of 20 to 30 years. Upon expiration of our PPAs and contracted revenue agreements and in order to maintain and grow our business, we must obtain extensions to these agreements or secure new agreements to replace them as they expire. Under most of our PPAs and concessions, there is an established price structure that provides us with price adjustment mechanisms that partially protect us against inflation.

 

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Tax incentives in the United States for renewable energy assets

U.S. federal, state and local governments have established several incentives and financial mechanisms to reduce the cost of renewable energy and spur the development of energy from renewable, non-carbon–based, sources. Some of the major tax incentives applied in our projects are, among others, Investment Tax Credit, Cash Grant in Lieu of ITC, Modified Accelerated Cost Recovery System, or MACRS, and Loan Guarantee Program.

We do not expect Solana or Mojave to pay U.S. federal income tax for the foreseeable future due to the relevant NOLs and NOL carryfowards generated by the application of the aforementioned tax incentives established in the United States, in particular MACRS accelerated depreciation.

Tax accelerated depreciation for Spanish new assets

For investments in new material assets and investment properties used for economic activities acquired in the tax periods commencing in 2009 up to March 31, 2012, tax free depreciation is allowed.

Due to this special regime, Solaben 2 and Solaben 3 do not expect to pay taxes in the following 10 years.

Specific corporate income tax rules in Mexico

Our project in Mexico, ACT, must pay Mexican corporate income tax on its business income and capital gains. The general taxable income is calculated in a similar way to the other jurisdictions in which our assets are located; however, the Mexican corporate income tax provides for specific inflationary adjustments on monetary assets and liabilities.

Notwithstanding the above, the project is not expected to pay significant income taxes until the fifth or sixth year after this offering due to the NOL carryforwards generated during the construction phase.

Capital expenditures

We finance our contracted assets primarily through non-recourse debt issued by a financial institution. Consequently, a significant part of our business is capital-intensive and our new assets are highly leveraged. See “Liquidity and capital resources—Capital expenditures.”

Interest rates

We incur significant indebtedness in our assets. The interest rate risk arises mainly from indebtedness with variable interest rates. To mitigate the interest rate risk, we primarily use long-term interest rate swaps and interest rate options which, in exchange for a fee, offer protection against a rise in interest rates. We estimate that currently over 90% of our interest cost exposure is covered. Nevertheless, our results of operations can be affected by changes in interest rates with respect to the unhedged portion of our indebtedness that bears interest at floating rates, which typically bears a spread over EURIBOR or LIBOR.

Exchange rates

Our functional currency is the U.S. dollar, as most of our revenues and expenses are denominated or linked to U.S. dollars. All our companies located in North America and most of those located in South America have their PPAs, or concessional agreements, and financing contracts signed in, or indexed to, U.S. dollars, and report their individual financial statements in U.S. dollars. There are some companies with revenue and expenses denominated in the local currency of the jurisdictions in which we operate, in particular, our Concentrating Solar Power plants in Spain, Solaben 2 and Solaben 3 (2x50 MW), and the Palmucho electric transmission line in Chile (6 miles), where the principal revenues and expenses are denominated in euros and Chilean pesos, respectively.

 

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Fluctuations in the value of foreign currencies, mainly the euro, in relation to the U.S. dollar may affect our operating results. Impacts associated with fluctuations in foreign currency are discussed in more detail under “Quantitative and qualitative disclosure about market risk—Foreign exchange rate risk.” In subsidiaries with functional currency other than the U.S. dollar, assets and liabilities are translated into U.S. dollars using end-of-period exchange rates; revenue, expenses and cash flows are translated using average rates of exchange. The following table illustrates the average rates of exchange used in the case of euros:

 

		U.S. dollar average per euro
Three months ended March 31, 2014		$	1.3704
Three months ended March 31, 2013		$	1.3202
Year ended December 31, 2013		$	1.3277
Year ended December 31, 2012		$	1.2857

Apart from the impact of translation differences described above, the exposure of our income statement to fluctuations of foreign currencies is limited, as the financing of projects is typically denominated in the same currency as that of the contracted revenue agreement. This policy seeks to ensure that the main revenue and expenses in foreign companies are denominated in the same currency, limiting our risk of foreign exchange differences in our financial results.

In our discussion of operating results, we have included foreign exchange impacts in our revenue by providing constant currency revenue growth. The constant currency presentation is a non-IFRS financial measure, which excludes the impact of fluctuations in foreign currency exchange rates. We believe providing constant currency information provides valuable supplemental information regarding our results of operations. We calculate constant currency amounts by converting our current period local currency revenue using the prior period foreign currency average exchange rates and comparing these adjusted amounts to our prior period reported results. This calculation may differ from similarly titled measures used by others and, accordingly, the constant currency presentation is not meant to substitute for recorded amounts presented in conformity with IFRS nor should such amounts be considered in isolation.

Key Performance Indicators

In addition to the factors described above, we closely monitor the following key drivers of our business sectors’ performance to plan for our needs, and to adjust our expectations, financial budgets and forecasts appropriately.

 

		Three-month period ended March 31,								Year ended December 31,
Key performance indicator		2014				2013				2013				2012
Renewable energy
MW in operation			380				100				380				100
GWh produced			129				18				280				75
Conventional power
MW in operation			300				—				300				—
GWh produced			648				—				1,849				—
Availability (%)			99.6	%			—				97.0	%			—
Electric transmission lines
Miles in operation			969				368				368				368
Availability (%)			99.1	%			99.6	%			99.6	%			99.2	%

 

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Results of operations

The tables below illustrate our results of operations for the three-month periods ended March 31, 2014 and 2013 and years ended December 31, 2013 and 2012.

 

		Three-month period ended March 31,								Year ended December 31,
Results of operations		2014				2013				2013				2012
		($ in millions)								($ in millions)
		(unaudited)
Revenue		$	63.8			$	32.3			$	210.9			$	107.2
Other operating income			20.3				97.9				379.6				560.4
Raw materials and consumables used			(4.5	)			(0.5	)			(8.7	)			(4.3	)
Employee benefit expense			(1.7	)			(0.6	)			(2.4	)			(1.8	)
Depreciation, amortization and impairment charges			(27.2	)			(8.5	)			(46.9	)			(20.2	)
Other operating expenses			(26.8	)			(103.9	)			(420.9	)			(573.6	)
Operating profit		$	23.9			$	16.8			$	111.6			$	67.7
Financial income			0.2				0.4				1.2				0.7
Financial expense			(54.3	)			(20.6	)			(123.8	)			(64.1	)
Net exchange differences			0.6				(0.4	)			(0.9	)			0.4
Other net financial income/(expense)			(0.4	)			(1.7	)			(1.7	)			(0.2	)
Financial expense, net		$	(54.0	)		$	(22.4	)		$	(125.2	)		$	(63.2	)
Share of profit/(loss) of associates			(0.3	)			(0.1	)			0.0				(0.4	)
Profit/(loss) before income tax		$	(30.4	)		$	(5.7	)		$	(13.6	)		$	4.2
Income tax benefit/(expense)			1.8				(0.8	)			11.8				(4.0	)
Profit/(loss) for the period		$	(28.6	)		$	(6.6	)		$	(1.8	)		$	0.1
Profit/(loss) attributable to non-controlling interest			1.7				1.6				(1.6	)			1.2
Profit/(loss) attributable to the combined group		$	(26.9	)		$	(4.9	)		$	(3.4	)		$	1.3

Explanation of Combined Income Statement Items

Comparison of the Three-Month Periods ended March 31, 2014 and March 31, 2013

Revenues

Revenues increased by 97.6% to $63.8 million in the three-month period ended March 31, 2014, compared with $32.3 million for the three-month period ended March 31, 2013. The increase is largely attributable to the commencement of operations of ACT and Solana in the second quarter and the last quarter of 2013, respectively, and to the entry into operation of ATS in the first quarter of 2014. This resulted in a net electricity production of 777 GWh for the three-month period ended March 31, 2014, compared with 18 GWh produced during the three-month period ended March 31, 2013.

 

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Other operating income

The following table sets forth our other operating income for the three-month periods ended March 31, 2014 and 2013:

 

		Three-month period ended March, 31,
Other operating income		2014				2013
		($ in millions)
		(unaudited)
Grants		$	9.0			$	—
Income from various services			2.2				0.1
Income from subcontracted construction services for our assets and concessions			9.1				97.8
Total		$	20.3			$	97.9

Other operating income decreased by 79.3% to $20.3 million for the three-month period ended March 31, 2014, compared with $97.9 million for the three-month period ended March 31, 2013. As certain assets owned by us were under construction and subcontracted to related parties during 2013 and 2014, we were required to account for income from construction services as “Other operating income” in accordance with IFRIC 12. The corresponding costs of construction were recorded within “Other operating expenses.” This income decreased by 90.7% to $9.1 million for the three-month period ended March 31, 2014, compared with $97.8 million for the three-month period ended March 31, 2013. These amounts reflect the construction progress of the assets and concessions during the first quarter of 2014 and 2013. The decrease was primarily due to the completion of construction of ATS, ACT, Quadra 2 and Quadra 1. We do not expect to have significant other operating income from construction activities in future periods. The increase in grants is related to the financial support provided by the U.S. Administration to Solana.

Raw materials and consumables used

Raw materials and consumables used increased by 845.1% to $4.5 million for the three-month period ended March 31, 2014, compared with $0.5 million for the three-month period ended March 31, 2013. This was primarily due to the commencement of operations of Solana in the last quarter of 2013.

Employee benefits expenses

Employee benefit expenses increased by 198.0% to $1.7 million for the three-month period ended March 31, 2014, compared with $0.6 million for the three-month period ended March 31, 2013. This was attributable to an increase in the number of employees at ATN. In April 2014, all ATN employees were transferred to an entity excluded from the perimeter of Abengoa Yield.

Depreciation, amortization and impairment charges

Depreciation, amortization and impairment charges increased by 218.8% to $27.2 million for the three-month period ended March 31, 2014, compared with $8.5 million for the three-month period ended March 31, 2013. The net change was due to the increase in depreciation and amortization, resulting from the commencement of operations of Solana and ATS, given that depreciation and amortization are recorded from the commencement of operations of the contracted assets.

 

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Other operating expenses

The following table sets forth our other operating expenses for the three-month periods ended March 31, 2014 and 2013:

 

		Three-month period ended March, 31
Other operating expenses		2014 (unaudited)								2013 (unaudited)
		$ in millions				% of revenue				$ in millions				% of revenue
Leases and fees		$	0.3				0.5	%		$	0.2				0.7	%
Repairs and maintenance			2.6				4.0	%			0.1				0.4	%
Independent professional services(*)			4.6				7.3	%			3.2				9.9	%
Transportation			0.0				0.1	%			0.2				0.6	%
Supplies			2.2				3.4	%			0.4				1.4	%
Other external services			2.1				3.3	%			0.4				1.1	%
Levies and duties			3.2				5.0	%			0.5				1.7	%
Other expenses			2.6				4.1	%			0.9				2.9	%
Construction costs			9.1				14.3	%			97.8				302.8	%
Total		$	26.8				42.0	%		$	103.9				321.6	%

 

(*)	Includes approximately $0.9 million in the first quarter of 2014 and $0.9 million in the first quarter of 2013 of allocated costs and expenses for general and administrative services provided by Abengoa.

Other operating expenses decreased by 74.2% to $26.8 million for the three-month period ended March 31, 2014, compared with $103.9 million for the three-month period ended March 31, 2013. This was primarily due to the decrease in construction costs by 90.7% to $9.1 million for the three-month period ended March 31, 2014 compared with $97.8 million for the three-month period ended March 31, 2013. This decrease, due to the completion of construction of ATS, ACT, Quadra 2 and Quadra 1, was partially offset by increases in repairs and maintenance and supplies related to the commencement of operations of ACT and Solana in the second quarter and the last quarter of 2013 respectively, as well as an increase in levies and duties in Solana.

Operating profit

As a result of the above factors, operating profit increased by 42.5% to $23.9 million for the three-month period ended March 31, 2014, compared with $16.8 million for the three-month period ended March 31, 2013.

Financial expense

The following table sets forth our financial expense for the three-month periods ended March 31, 2014 and 2013:

 

		Three-month period ended March 31,
Financial expense		2014				2013
		($ in millions)
		(unaudited)
Expenses due to interest:
—Loans from credit entities		$	30.5			$	17.7
—Other debts			15.5				1.0
Interest rates losses derivatives: cash flow hedges			8.4				1.9
Total		$	54.3			$	20.6

 

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Financial expenses increased by 163.3% to $54.3 million for the three-month period ended March 31, 2014, compared with $20.6 million for the three-month period ended March 31, 2013. This increase was primarily attributable to interest expenses from loans and credits associated with Solana, which entered into operation during the last quarter of 2013 and ATS, which entered into operation during the first quarter of 2014. Interest is capitalized for our intangible concession assets during the construction period and begins to be expensed upon commercial operation. Losses from interest-rate derivatives designated as cash flow hedges of $8.3 million in 2014 were due to transfers from equity to financial expense in accordance with our cash flow hedge accounting policy mainly related to ACT, Solaben 2 and Solaben 3.

Financial expense, net

Net financial expense increased by 140.5% to $54.0 million for the three-month period ended March 31, 2014, compared with $22.4 million for the three-month period ended March 31, 2013. This increase was primarily attributable to the aforementioned change in financial expense.

Profit/(loss) before income tax

As a result of the above factors, loss before income taxes amounted to $30.4 million for the three-month period ended March 31, 2014, compared with a loss of $5.7 million for the three-month period ended March 31, 2013.

Income tax benefit/(expense)

Income tax benefit amounted to $1.8 million for the three-month period ended March 31, 2014, compared with an income tax expense of $0.8 million for the three-month period ended March 31, 2013. Our effective tax rate differs from the average nominal tax rate mainly due to permanent differences in some jurisdictions and to the fact that we do not record tax credits for losses in all jurisdictions where we have recorded losses.

Profit/(loss) attributable to non-controlling interests

Loss attributable to non-controlling interests, corresponding mainly to losses from Solaben 2 and Solaben 3, remained stable in the three-month period ended March 31, 2014 with respect to the same period in the prior year.

Profit/(loss) attributable to the combined group

As a result of the above factors, loss attributable to the parent company amounted to $26.9 million for the three-month period ended March 31, 2014, compared with a loss attributable to the parent company of $4.9 million for the three-month period ended March 31, 2013.

Total comprehensive income/(loss)

Total comprehensive loss attributable to the combined group increased to $45.9 million for the three-month period ended March 31, 2014 compared with an income of $3.6 million for the three-month period ended March 31, 2013, mainly due to the increase in loss for the period and to the change in fair value of cash flow hedges, corresponding to interest rate derivatives.

Comparison of Years ended December 31, 2013 and 2012

Revenues

Revenues increased by 96.8% to $210.9 million for the year ended December 31, 2013, compared with $107.2 million for the year ended December 31, 2012. On a constant currency basis, revenue for the year ended

 

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December 31, 2013 would have been $208.2 million, representing an increase of $101.0 million, or 94.2%, compared to the year ended December 31, 2012. The increase is largely attributable to the commencement of operations of ACT and Solana in the first quarter and the last quarter of 2013, respectively, and a full year of operations of Solaben 2 and Solaben 3, as they commenced operations during 2012. This resulted in net electricity production of 2,129 GWh for the year ended December 31, 2013 compared with 75 GWh produced during the year ended December 31, 2012.

Other operating income

The following table sets forth our other operating income for the years ended December 31, 2013 and 2012:

 

		Year ended December 31,
Other operating income		2013				2012
		($ in millions)
Grants		$	10.1			$	—
Income from various services			4.8				1.8
Income from subcontracted construction services for our assets and concessions			364.7				558.6
Total		$	379.6			$	560.4

Other operating income decreased by 32.3% to $379.6 million for the year ended December 31, 2013, compared with $560.4 million for the year ended December 31, 2012. As certain assets owned by us were under construction and subcontracted to related parties during 2012 and 2013, we were required to account for income from construction services as “Other operating income” in accordance with IFRIC 12. The corresponding costs of construction were recorded within “Other operating expenses.” This income decreased by 34.7% to $364.7 million for the year ended December 31, 2013 compared with $558.6 million for the year ended December 31, 2012. These amounts reflect the construction progress of the assets and concessions during 2013 and 2012. The decrease was primarily due to the completion of construction of ACT. We do not expect to have significant other operating income from construction activities in future periods. The increase in grants is related to the financial support provided by the U.S. Administration to Solana.

Raw materials and consumables used

Raw materials and consumables used increased by 102.3% to $8.7 million for the year ended December 31, 2013, compared with $4.3 million for the year ended December 31, 2012. This was primarily due to the commencement of operations of ACT and Solana in the first and last quarters of 2013, respectively, and a full year of operation of Solaben 2 and Solaben 3, as they commenced operations during 2012.

Employee benefits expenses

Employee benefit expenses increased by 33.3% to $2.4 million for the year ended December 31, 2013, compared with $1.8 million for the year ended December 31, 2012. This was attributable in full to an increase in the number of employees at ATN.

Depreciation, amortization and impairment charges

Depreciation, amortization and impairment charges increased by 132.2% to $46.9 million for the year ended December 31, 2013, compared with $20.2 million for the year ended December 31, 2012. The net change was due to the increase in depreciation and amortization, due to the commencement of operations of Solana and a full year of operation of Solaben 2 and Solaben 3.

 

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Other operating expenses

The following table sets forth our other operating expenses for the years ended December 31, 2013, and 2012.

 

		Year ended December 31,
Other operating expenses		2013								2012
		$ in millions				% of revenue				$ in millions				% of revenue
Leases and fees		$	1.8				0.9	%		$	0.4				0.4	%
Repairs and maintenance			12.8				6.0	%			0.9				0.8	%
Independent professional services(*)			22.6				10.7	%			9.6				9.0	%
Transportation			0.4				0.2	%			0.3				0.3	%
Supplies			3.3				1.6	%			0.7				0.6	%
Other external services			5.5				2.6	%			1.8				1.6	%
Levies and duties			6.6				3.1	%			0.4				0.4	%
Other expenses			3.2				1.5	%			0.9				0.9	%
Construction costs			364.7				172.9	%			558.6				521.2	%
Total		$	420.9				199.6	%		$	573.6				535.1	%

 

(*)	Includes approximately $3.5 million in 2013 and $2.0 million in 2012 of allocated costs and expenses for general and administrative services provided by Abengoa.

Other operating expenses decreased by 26.6% to $420.9 million for the year ended December 31, 2013, compared with $573.6 million for the year ended December 31, 2012. This was primarily due to the decrease of construction costs by 34.7% to $364.7 million for the year ended December 31, 2013 compared with $558.6 million for the year ended December 31, 2012. This decrease, due to the completion of construction of ACT, was partially offset by increases in repairs and maintenance and independent professional services related to the commencement of operations of ACT and Solana in the first quarter and the last quarter of 2013 respectively, a full year of operation of Solaben 2 and Solaben 3, as well as an increase in levies and duties in the Spanish plants due primarily to the existing levy on revenues from power generation.

Operating profit

As a result of the above factors, operating profit increased by 64.7% to $111.6 million for the year ended December 31, 2013, compared with $67.7 million for the year ended December 31, 2012. This increase was primarily attributable to the commencement of operations of several projects (ACT and Solana in the first quarter and the last quarter of 2013, respectively) and a full year of operation of Solaben 2 and Solaben 3.

Financial expense

The following table sets forth our financial expense for the years ended December 31, 2013 and 2012:

 

		Year ended December 31,
Financial expense		2013				2012
		($ in millions)
Expenses due to interest:
—Loans from credit entities		$	78.6			$	53.6
—Other debts			17.2				4.5
Interest rates losses derivatives: cash flow hedges			28.0				6.0
Total		$	123.8			$	64.1

 

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Financial expenses increased by 93.2% to $123.8 million for the year ended December 31, 2013, compared with $64.1 million for the year ended December 31, 2012. This increase was primarily attributable to interest expenses from loans and credits associated with Solana, which entered into operation during the last quarter of 2013 and Solaben 2 and Solaben 3, which entered into operation during the second and fourth quarters of 2012, respectively. Losses from interest-rate derivatives designated as cash flow hedges of $28 million in 2013 were due to transfers from equity to financial expense in accordance with our cash flow hedge accounting policy and to a one-time loss of $9 million resulting from the transfer to the income statement of all of the accumulated amount in equity as the hedged financing agreement of ATN was cancelled and replaced.

Financial expense, net

Net financial expense increased by 98.1% to $125.2 million for the year ended December 31, 2013, compared with $63.2 million for the year ended December 31, 2012. This increase was primarily attributable to the aforementioned change in financial expense.

Profit/(loss) before income tax

As a result of the above factors, loss before income taxes amounted to $13.6 million for the year ended December 31, 2013, compared with a profit of $4.1 million for the year ended December 31, 2012.

Income tax benefit/(expense)

Income tax benefit increased to $11.8 million for the year ended December 31, 2013, compared with an income tax expense of $4.0 million for the year ended December 31, 2012. Our effective tax rate differs from the average nominal tax rate mainly due to tax incentives in some jurisdictions and to permanent differences in Mexico, resulting from the application of local tax regulation in Mexico.

Profit/(loss) attributable to non-controlling interests

Profit attributable to non-controlling interests amounted to $1.6 million for the year ended December 31, 2013, compared with a loss of $1.2 million for the year ended December 31, 2012. This amount was primarily attributable to our minority shareholders in Solaben 2 and Solaben 3.

Profit/(loss) attributable to the combined group

As a result of the above factors, loss attributable to the parent company amounted to $3.4 million for the year ended December 31, 2013, compared with a profit attributable to the parent company of $1.3 million for the year ended December 31, 2012.

Total comprehensive income/(loss)

Total comprehensive income attributable to the combined group increased to $69.8 million for the year ended December 31, 2013, compared with a loss of $17.7 million for the year ended December 31, 2012, mainly due to the change in fair value of cash flow hedges, corresponding to interest rate derivatives.

Segment Reporting

We organize our business into the following three geographies where the contracted assets and concessions are located:

 

•

North America;

 

•

South America; and

 

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•

Europe.

In addition, we have identified the following business sectors based on the type of activity:

 

•

Renewable Energy, which includes our activities related to the production electricity from concentrating solar power and wind plants;

 

•

Conventional Power, which includes our activities related to the production of electricity and steam from natural gas; and

 

•

Electric Transmission, which include our activities related to the operation of electric transmission lines.

As a result we report our results in accordance with both criteria.

Comparison of the Three-Month Periods Ended March 31, 2014 and March 31, 2013

Revenue and Adjusted EBITDA by geography and business sector

The following table sets forth our revenue, Adjusted EBITDA and volumes for the three-month periods ended March 31, 2014 and 2013, by geographic region:

 

		Three-month period ended March 31,
Revenue by geography		2014								2013
		(unaudited)								(unaudited)
		$ in millions				% of revenue				$ in millions				% of revenue
North America		$	42.9				67.1	%		$	20.0				61.8	%
South America			14.3				22.4	%			5.7				17.5	%
Europe			6.7				10.5	%			6.7				20.7	%
Total revenue		$	63.8				100.0	%		$	32.3				100.0	%

 

		Three-month period ended March 31,
Adjusted EBITDA by geography		2014								2013
		(unaudited)								(unaudited)
		$ in millions				% of revenue				$ in millions				% of revenue
North America		$	37.2				86.8	%		$	18.6				93.2	%
South America			11.0				77.1	%			3.9				69.1	%
Europe			2.9				44.0	%			2.8				41.9	%
Adjusted EBITDA		$	51.1				80.1	%		$	25.3				78.4	%

 

		Volume sold
		Three-month period ended March 31,
Geography		2014				2013
North America (GWh)			759				—
South America (miles in operation)			969				368
Europe (GWh)			18				18

North America. Revenues increased by 114.7% to $42.9 million for the three-month period ended March 31, 2014, compared with $20.0 million for the three-month period ended March 31, 2013. The increase was primarily due to the commencement of operations of Solana in the last quarter of 2013. As a result, Adjusted EBITDA increased to $37.2 million for the three-month period ended March 31, 2014 compared with $18.6 million for the three-month period ended March 31, 2013.

 

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South America. Revenue increased by 152.0% to $14.3 million for the three-month period ended March 31, 2014, compared with $5.7 million for the three-month period ended March 31, 2013. The increase was mostly attributable to the commencement of operations of ATS in the first quarter of 2014. Thus, Adjusted EBITDA amounted to $11.0 million for the three-month period ended March 31, 2014, which represents an increase of $7.1 million as compared with the three-month period ended March 31, 2013.

Europe. Revenue was $6.7 million for the each of the three-month periods ended March 31, 2014 and 2013. Revenue was attributable to Solaben 2 and Solaben 3, which entered into operation during 2012. Adjusted EBITDA amounted to $2.9 million for the three-month period ended March 31, 2014, compared with $2.8 million for the same period in 2013.

The following table sets forth our revenue, Adjusted EBITDA and volumes for the three-month periods ended March 31, 2014 and 2013 by type of business sector:

 

		Three-month period ended March 31,
Revenue by business sector		2014								2013
		(unaudited)								(unaudited)
		$ in millions				% of revenue				$ in millions				% of revenue
Renewable Energy		$	20.8				32.6	%		$	6.7				20.7	%
Conventional Power			28.8				45.1	%			20.0				61.8	%
Electric Transmission			14.3				22.3	%			5.7				17.5	%
Total revenue		$	63.8				100.0	%		$	32.3				100.0	%

 

		Three-month period ended March 31,
Adjusted EBITDA by business sector		2014								2013
		(unaudited)								(unaudited)
		$ in millions				% of revenue				$ in millions				% of revenue
Renewable energy		$	16.6				79.8	%		$	2.7				40.7	%
Conventional power			23.5				81.6	%			18.6				93.2	%
Electric transmission lines			11.1				77.7	%			4.0				70.4	%
Adjusted EBITDA		$	51.1				80.1	%		$	25.3				78.4	%

 

		Volume sold
		Three-month period ended March 31,
Business Sectors		2014				2013
Renewable Energy (GWh)			129				18
Conventional power (GWh)			648				—
Electric transmission (miles in operation)			969				368

Renewable energy. Revenue increased by 211.2% to $20.8 million for the three-month period ended March 31, 2014, compared with $6.7 million for the three-month period ended March 31, 2013. The increase was attributable to the commencement of operations of Solana in the last quarter of 2013. As a consequence, the average capacity in terms of installed MW available throughout the period increased by 280 MW. This resulted in a net electricity production of 129 GWh for the three-month period ended March 31, 2014, compared with 18 GWh produced during the three-month period ended March 31, 2013. Adjusted EBITDA amounted to $16.6 million for the three-month period ended March 31, 2014, which represented an increase of $13.9 million with respect to the three-month period ended March 31, 2013.

 

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Conventional power. Revenue increased by 44.1% to $28.8 million for the three-month period ended March 31, 2014, compared with $20.0 million for the three-month period ended March 31, 2013. The increase was due to the commencement of operations of ACT in 2013. This resulted in net electricity production of 648 GWh for the three-month period ended March 31, 2014. As a consequence, Adjusted EBITDA increased to $23.5 million for the three-month period ended March 31, 2014, from $18.6 million for the three-month period ended March 31, 2013.

Electric transmission lines. Revenue increased by 152.0% to $14.3 million for the three-month period ended March 31, 2014, compared with $5.7 million for the three-month period ended March 31, 2013. The increase was mostly attributable to the commencement of operations of ATS in the first quarter of 2014. Thus, Adjusted EBITDA amounted to $11.1 million for the three-month period ended March 31, 2014, an increase of $7.1 million compared with the three-month period ended March 31, 2013.

Comparison of Years ended December 31, 2013 and 2012

Revenue and Adjusted EBITDA by geography and business sector

The following table sets forth our revenue, Adjusted EBITDA and volumes for the years ended December 31, 2013 and 2012, by geographic region:

 

		Year ended December 31,
Revenue by geography		2013								2012
		$ in millions				% of revenue				$ in millions				% of revenue
North America		$	114.0				54.1	%		$	62.3				58.1	%
South America			25.4				12.0	%			17.0				15.9	%
Europe			71.5				33.9	%			27.9				26.0	%
Total revenue		$	210.9				100.0	%		$	107.2				100.0	%

 

		Year ended December 31,
Adjusted EBITDA by geography		2013								2012
		$ in millions				% of revenue				$ in millions				% of revenue
North America		$	96.7				84.8	%		$	61.1				98.1	%
South America			19.0				74.8	%			10.2				60.0	%
Europe			42.8				59.9	%			16.7				59.9	%
Adjusted EBITDA		$	158.5				75.2	%		$	88.0				82.1	%

 

		Volume sold
Geography		2013				2012
North America (GWh)			1,938				—
South America (miles in operation)			368				368
Europe (GWh)			191				75

North America. Revenues increased to $114.0 million for the year ended December 31, 2013, compared with $62.3 million for the year ended December 31, 2012. The increase was due to the commencement of operations of ACT and Solana in the first quarter of 2013 and in the last quarter of 2013 respectively. As a result, Adjusted EBITDA increased to $96.7 million for the year ended December 31, 2013, compared with $61.1 million for the year ended December 31, 2012.

South America. Revenue increased by 49.4% to $25.4 million for the year ended December 31, 2013, compared with $17.0 million for the year ended December 31, 2012. On a constant currency basis, revenue for

 

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the year ended December 31, 2013 would have been $25.5 million, representing an increase of $8.5 million, or 50.0%, compared with the same period of the previous year. The increase is mostly attributable to the higher level of availability of ATN in 2013 compared with 2012 and to revenues from Quadra 1 and Quadra 2 electric transmission lines. Thus, Adjusted EBITDA amounted to $19.0 million for the year ended December 31, 2013, which represents an increase of $8.8 million with respect to the year ended December 31, 2012.

Europe. Revenue increased by 156.3% to $71.5 million for the year ended December 31, 2013, compared with $27.9 million for the year ended December 31, 2012. On a constant currency basis, revenue for the year ended December 31, 2013 would have been $68.7 million, representing an increase of $40.8 million, or 146%, compared with the same period of the previous year. The increase is mainly attributable to Solaben 2 and Solaben 3, which entered into operation during 2012. As a result, Adjusted EBITDA increased to $42.8 million for the year ended December 31, 2013, compared with $16.7 million for the same period in 2012.

The following table sets forth our revenue, Adjusted EBITDA and volumes for the years ended December 31, 2013 and 2012 by type of business sector:

 

		Year ended December 31,
Revenue by business sector		2013								2012
		$ in millions				% of revenue				$ in millions				% of revenue
Renewable Energy		$	82.7				39.2	%		$	27.9				26.0	%
Conventional Power			102.8				48.7	%			62.3				58.1	%
Electric Transmission			25.4				12.1	%			17.0				15.9	%
Total revenue		$	210.9				100.0	%		$	107.2				100.0	%

 

		Year ended December 31,
Adjusted EBITDA by business sector		2013								2012
		$ in millions				% of revenue				$ in millions				% of revenue
Renewable Energy		$	55.8				67.5	%		$	16.1				57.7	%
Conventional Power			83.3				81.0	%			61.1				98.1	%
Electric Transmission			19.4				76.4	%			10.8				63.5	%
Adjusted EBITDA		$	158.5				75.2	%		$	88.0				82.1	%

 

		Volume sold
Business Sectors		2013				2012
Renewable Energy (GWh)			280				75
Conventional Power (GWh)			1,849				—
Electric Transmission (miles in operation)			368				368

Renewable energy. Revenue increased by 196% to $82.7 million for the year ended December 31, 2013, compared with $27.9 million for the year ended December 31, 2012. On a constant currency basis, revenue for the year ended December 31, 2013 would have been $79.9 million, representing an increase of $52.0 million, or 186%, compared with the same period of the previous year. The increase was mainly attributable to the larger contribution from Solaben 2 and Solaben 3 that entered into operation during 2012 and the commencement of operations in the last quarter of 2013 of Solana. As a consequence, the average capacity in terms of installed MW available throughout the period increased by 280 MW. This resulted in a net electricity production of 280 GWh for the year ended December 31, 2013, compared with 75 GWh produced during the year ended December 31, 2012. Thus, Adjusted EBITDA reached $55.8 million for the year ended December 31, 2013, which represented an increase of $39.7 million with respect to the year ended December 31, 2012.

 

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Conventional power. Revenue increased to $102.8 million for the year ended December 31, 2013, compared with $62.3 million for the year ended December 31, 2012. The increase was due to the commencement of operations of ACT in the first quarter of 2013. This resulted in net electricity production of 1,849 GWh for the year ended December 31, 2013. As a consequence, Adjusted EBITDA increased to $83.3 million for the year ended December 31, 2013, from $61.1 million for the year ended December 31, 2012.

Electric transmission lines. Revenue increased to $25.4 million for the year ended December 31, 2013, compared with $17.0 million for the year ended December 31, 2012. On a constant currency basis, revenue for the year ended December 31, 2013 would have been $25.5 million, representing an increase of $8.5 million, or 50.0%, compared with the same period of the previous year. The increase was mostly attributable to the higher level of availability of ATN in 2013 compared with 2012 and to revenues from Quadra 1 and Quadra 2 electric transmission lines. Thus, Adjusted EBITDA amounted to $19.4 million for the year ended December 31, 2013, an increase of $8.6 million compared with the year ended December 31, 2012.

Liquidity and Capital Resources

The liquidity and capital resources discussion which follows contains certain estimates as of the date of this prospectus of our estimated future sources and uses of liquidity (including estimated future capital resources and capital expenditures) and future financial and operating results. These estimates, while presented with numerical specificity, necessarily reflect numerous estimates and assumptions made by us with respect to industry performance, general business, economic, regulatory, market and financial conditions and other future events, as well as matters specific to our businesses, all of which are difficult or impossible to predict and many of which are beyond our control. These estimates reflect subjective judgment in many respects and thus are susceptible to multiple interpretations and periodic revisions based on actual experience and business, economic, regulatory, financial and other developments. As such, these estimates constitute forward-looking information and are subject to risks and uncertainties that could cause our actual sources and uses of liquidity (including estimated future capital resources and capital expenditures) and financial and operating results to differ materially from the estimates made here, including, but not limited to, our performance, industry performance, general business and economic conditions, customer requirements, competition, adverse changes in applicable laws, regulations or rules, and the various risks set forth in this prospectus. See “Cautionary Statements Regarding Forward-Looking Statements.”

In addition, these estimates reflect assumptions of our management as of the time that they were prepared as to certain business decisions that were and are subject to change. These estimates also may be affected by our ability to achieve strategic goals, objectives and targets over the applicable periods. The estimates cannot, therefore, be considered a guarantee of future sources and uses of liquidity (including estimated future capital resources and capital expenditures) and future financial and operating results, and the information should not be relied on as such. Without disclaiming responsibility to have a reasonable basis for the prospective financial information included in this prospectus, none of us, the board, the underwriters or any of our or their respective advisors or representatives or any of our or their respective affiliates, assumes any responsibility for the validity, accuracy or completeness of such information. None of us, the board, the underwriters or our or their respective affiliates, advisors, officers, directors or representatives intends to, and each of them disclaims any obligation to, update, revise, or correct these estimates, except as otherwise required by law, including if the estimates are or become inaccurate (even in the short term).

The inclusion in this prospectus of these estimates should not be deemed an admission or representation by us, the board, the underwriters or our or their respective affiliates that such information is viewed by us, the board, the underwriters or our or their respective affiliates as material information of ours. Such information should be evaluated, if at all, in conjunction with the historical financial statements and other information regarding Abengoa Yield contained in this prospectus. None of us, the board, the underwriters or our or their respective affiliates, advisors, officers, directors or representatives has made or makes any representation to any prospective investor or other person regarding our ultimate performance compared to the information contained

 

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in these estimates or that forecasted results will be achieved. In light of the foregoing factors and the uncertainties inherent in the information provided above, investors are cautioned not to place undue reliance on these estimates. Our liquidity plans are subject to a number of risks and uncertainties, some of which are outside of our control. Macroeconomic conditions could limit our ability to successfully execute our business plans and, therefore, adversely affect our liquidity plans. See “Risk Factors.”

Our principal liquidity requirements are to service our debt, pay cash dividends to investors and acquire new companies and operations. Historically, our predecessor operations were largely financed by internally generated cash flows as well as corporate and/or project-level borrowings to satisfy its capital expenditure requirements. As a normal part of our business, depending on market conditions, we will from time to time consider opportunities to repay, redeem, repurchase or refinance our indebtedness. Changes in our operating plans, lower than anticipated sales, increased expenses, acquisitions or other events may cause us to seek additional debt or equity financing in future periods. There can be no guarantee that financing will be available on acceptable terms or at all. Debt financing, if available, could impose additional cash payment obligations and additional covenants and operating restrictions. In addition, any of the items discussed in detail under “Risk Factors” in this prospectus may also significantly impact our liquidity.

Our principal liquidity and capital requirements consist of the following:

 

•

debt service requirements on our existing and future debt;

 

•

cash dividends to investors; and

 

•

acquisitions of new companies and operations (see “Business—Our Growth Strategy”).

Liquidity position

As of March 31, 2014, our cash and cash equivalents were $809.7 million as compared with $357.7 million as of December 31, 2013 and $97.5 million as of December 31, 2012. This increase during the first three months of 2014 was primarily due to an ITC Cash Grant payment awarded to Solana by the U.S. Department of the Treasury. This cash was used on April 2, 2014 to fully repay the short-term tranche of Solana’s loan with the Federal Financing Bank ($451.3 million).

Following the consummation of this offering, we will have a cash position of approximately $90 million at the Abengoa Yield plc level, including the proceeds retained from this offering. A portion of this cash position ($38 million) will be used to purchase Cofides’ stake in ATS as described under “Business—Our Operations—Electric Transmission—Abengoa Transmission Sur.”

Sources of liquidity

Following the consummation of this offering, we expect our ongoing sources of liquidity to include cash on hand, cash generated from our operations, non-recourse project financing arrangements, corporate debt and the issuance of additional equity securities, as appropriate, given market conditions. As described in Note 13 of our Annual Combined Financial Statements, our financing agreements consist mainly of the project-level financings for our various assets.

Our ability to meet our debt service obligations and other capital requirements, including capital expenditures, as well as acquisitions, will depend on our future operating performance which, in turn, will be subject to general economic, financial, business, competitive, legislative, regulatory and other conditions, many of which are beyond our control.

Concurrently with the consummation of this offering, we plan to enter into a new $50 million revolving credit line with Abengoa, subject to the terms of the Financial Support Agreement. See “Related Party Transactions term—Financial Support Agreement.”

 

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We believe that our existing liquidity position and cash flows from operations will be sufficient to meet our requirements and commitments for the foreseeable future, to finance growth and to distribute dividends to our investors. Based on our current level of operations, we believe our cash flow from operations, available cash and available borrowings under our financing agreements will be adequate to meet our future liquidity needs for at least the next twelve months.

Debt service

Principal payments on debt as of December 31, 2013 are due in the following periods:

 

Repayment schedule by geography		Total				Up to one year				Between one and three years				Between three and five years				Subsequent years
(in millions of U.S. dollars)
North America		$	1,842.9			$	18.5			$	174.3			$	88.9			$	1,561.2
South America			605.3				18.2				44.6				303.6				238.9
Europe			446.4				15.6				34.6				40.2				356.0
Total		$	2,894.6			$	52.3			$	253.5			$	432.7			$	2,156.1

 

Repayment schedule by business sectors		Total				Up to one year				Between one and three years				Between three and five years				Subsequent years
(in millions of U.S. dollars)
Renewable Energy		$	1,667.2			$	18.3			$	60.1			$	72.9			$	1,515.9
Conventional Power			729.3				18.5				156.6				64.1				490.1
Electric Transmission			498.1				15.5				36.8				295.7				150.1
Total		$	2,894.6			$	52.3			$	253.5			$	432.7			$	2,156.1

The debt maturities relate to non-recourse financing that will be repaid with cash flows generated from the projects in respect of which that financing was incurred.

Capital expenditures

Our capital spending program is focused on completing the construction of assets where construction is in process. As of March 31, 2014, to finance our capital expenditures plan, we have secured commitments for the provision of $110 million of non-recourse debt, and the remaining $37.1 million will be contributed to us as part of the Asset Transfer. As of the date of this offering, the funds to be provided as equity in relation to the Mojave project are held in cash in one of our subsidiaries.

As of March 31, 2014, our estimated capital expenditures for the remainder of 2014 are as follows:

 

Committed contracted assets
		(unaudited and estimated) ($ in millions)
Mojave		$	144.0
Palmatir and ATS			3.1
Total capex plan		$	147.1

 

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We intend to analyze the acquisition of certain operational assets in the future that meet our defined investment criteria. See “Business—Our Growth Strategy.” Abengoa has a pipeline of projects in various phases of development that are expected to become operational over the course of the next two years. Upon consummation of this offering, we will enter into the ROFO Agreement with Abengoa. The ROFO Agreement will provide us with a right of first offer to acquire all of the future contracted assets of Abengoa in our primary geographies (North America, Chile, Peru, Uruguay, Brazil, Colombia and the European Union) and four assets to be mutually agreed in other selected regions. The following table presents the projects that, based on their maturity stage and cash generation profile, we expect Abengoa to propose to us for evaluation for acquisition in 2015 and 2016:

 

Expected ROFO Assets

Type

Ownership

Location

Currency

Capacity

Status

Offtaker

Counterparty Credit Ratings(1)

COD/ Expected COD

Contract Years Left

2015

Cadonal

Renewable (Wind)

100%

Uruguay

USD

50 MW

Construction

Uruguay

BBB-/Baa3/BBB-

1Q 2015

20

Solacor 1 & 2

Renewable (CSP)

74%(2)

Spain

Euro

2x50 MW

Operational

Spain

BBB-/ Baa2/BBB+

2012

23

Shams

Renewable (CSP)

20%

U.A.E.

USD(3)

100 MW

Operational

Abu Dhabi

AA/Aa2/AA

3Q 2013

25

Honaine

Water

25.5%

Algeria

USD

7M ft3/day

Operational

Sonatrach

N/A

2012

23

2016

3T

Conventional Power

100%

Mexico

USD

220 MW

Construction

Several

N/A

4Q 2016

20-25

ATN3

Transmission Line

40%

Peru

USD

220 Miles

Construction

Peru

BBB+/Baa2/BBB+

3Q 2016

30

Helioenergy 1 & 2

Renewable (CSP)

50%

Spain

Euro

2x50 MW

Operational

Spain

BBB-/Baa2/BBB+

2011

23

SPP1

Conventional Power

51%

Algeria

Euro

150 MW

Operational

Sonatrach

N/A

3Q 2011

22

 

 

(1)	Reflects the counterparty’s credit ratings issued by S&P, Moody’s and Fitch.

(2)	Abengoa has the right to receive 83% on average of the cash available for future distribution from Solacor 1 & 2 due to having 100% of the subordinated debt of the project.

(3)	Shams’ revenues are denominated in United Arab Emirates dirham, which has been pegged to the U.S. dollar since 1997.

Cash dividends to investors

We intend to distribute to holders of our shares in the form of a quarterly distribution all of the cash available for distribution that is generated each quarter, less reserves for the prudent conduct of our business. The cash available for distribution is likely to fluctuate, and in some cases significantly, from quarter to quarter as a result of the seasonality of our assets, the terms of our financing arrangements, maintenance and outage schedules and other factors. See “Cash Dividend Policy—Assumptions and Considerations.”

 

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Cash Flow

The following table sets forth combined cash flow data for the three-month periods ended March 31, 2014 and 2013 and for each of the years ended December 31, 2013 and 2012:

 

		Three-month period ended March 31,								Year ended December 31,
		2014				2013				2013				2012
		(unaudited)
		($ in millions)
Gross cash flows from operating activities
Profit/(loss) for the year		$	(28.6	)		$	(6.6	)		$	(1.8	)		$	0.1
Adjustments to reconcile combined after-tax profit to net cash generated by operating activities			76.2				8.0				92.4				22.8
Net interest / taxes paid			(11.8	)			(0.4	)			(62.4	)			(41.6	)
Variations in working capital			(36.3	)			(7.5	)			9.2				66.6
Total net cash flow generated by (used in) operating activities		$	(0.5	)		$	(6.5	)		$	37.4			$	47.9
Total net cash flows used in investment activities		$	(39.9	)		$	(137.0	)		$	(694.6	)		$	(1,098.7	)
Net cash flows generated by finance activities		$	492.5			$	185.3			$	914.9			$	1,107.3
Net increase/(decrease) in cash and cash equivalents			452.1				41.8				257.7				56.5
Cash and cash equivalents at the beginning of the period			357.7				97.5				97.5				40.2
Currency translation difference on cash and cash equivalents			(0.1	)			(1.2	)			2.5				0.8
Cash and cash equivalents at the end of the period		$	809.7			$	138.1			$	357.7			$	97.5

Net cash flows from operating activities

For the three-month period ended March 31, 2014, net cash used in operating activities was $0.5 million, compared with $6.5 million for the three-month period ended March 31, 2013. During the three-month period ended March 31, 2014, profit adjusted by non-monetary items was $47.6 million, compared with $1.4 million for the three-month period ended March 31, 2013. The increase was primarily due to the commencement of operations of Solana and ACT during 2013 and the entry into operation of ATS in the first quarter of 2014. This increase was mostly offset by larger net interest and taxes paid in the three-month period ended March 31, 2014 of $11.8 million compared with $0.4 million in the three-month period ended March 31, 2013. In addition, the increase of profit for the period adjusted by non-monetary items was offset by reductions in variations in working capital related to the end of the construction phase of the projects. The variation in working capital amounted to $(36.3) million for the three-month period ended March 31, 2014 compared with $(7.5) million for the three-month period ended March 31, 2013.

For the year ended December 31, 2013, we generated net cash from our operating activities of $37.4 million, compared with net cash generated from operating activities of $47.9 million for the year ended December 31, 2012. In 2013, profit for the period adjusted by non-monetary items was $90.6 million compared with $ 22.9 million. The increase is mainly due to the commencement of operations of ACT and Solana in the first and last quarters of 2013, respectively, and to a full year of operations of Solaben 2 and Solaben 3, as they commenced operations during the second and fourth quarters of 2012, respectively. This increase was mostly offset by reductions in variations in working capital due primarily to the reductions of other current liabilities related to the end of the construction phase of the projects. The variation in working capital amounted to $9.2 million in 2013 compared with $66.6 million in 2012. In addition, the increase of profit for the period adjusted by non-monetary items was offset by larger net interest and taxes paid in 2013 of $62.3 million compared with $41.6 million in 2012.

 

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Net cash generated from investing activities

For the three-month period ended March 31, 2014, net cash used in investing activities decreased to $39.9 million, compared with $137.0 million for the three-month period ended March 31, 2013 due to the completion of construction of Solana and ATS in the last quarter of 2013 and the first quarter of 2014, respectively.

For the year ended December 31, 2013, net cash used in investing activities declined to $694.6 million compared with $1,098.7 million for the year ended December 31, 2012 due to finalization of construction of some of our larger projects. For the year ended December 31, 2013, our net investments in Solana and Mojave amounted to $240.6 million compared with $554.3 million in 2012, as Solana entered into operation in October 2013 and Mojave had substantially completed construction in 2013. The net investment in Solaben 2 and Solaben 3 was nil in 2013, as each project commenced operations in mid-2012, compared with $142.0 million in 2012. Finally, the net cash used in investments of ATS amounted to $158.3 million in 2013 compared with $215.4 million in 2012, as the project reached COD in January 2014.

Net cash generated from financing activities

For the three-month period ended March 31, 2014, net cash flow from financing activities was $492.5 million, compared with $185.3 million for the three-month period ended March 31, 2013. The net cash generated from financing activities during the three-month period ended March 31, 2014 related primarily to an ITC Cash Grant payment awarded to Solana by the U.S. Department of the Treasury. This cash was used on April 2, 2014 to fully repay the short-term tranche of Solana’s loan with the Federal Financing Bank amounting to $451.3 million. In addition, net cash generated from financing activities includes net proceeds from non-recourse financing of $15.1 million and proceeds from related parties and other financing of $13.4 million. The net cash generated from financing activities during the three-month period ended March 31, 2013 related to net proceeds from non-recourse financing of $74.9 million and proceeds from related parties and other financing of $110.4 million. The net cash used in financing activities during the first three months of 2014 related mostly to the construction of ACT, Mojave and ATS.

For the year ended December 31, 2013, net cash flow from financing activities was $914.9 million, compared with $1,107.3 million for the year ended December 31, 2012. The net cash generated from financing activities during 2013 comprises proceeds from non-recourse financing of $1,139.7 million, repayment of non-recourse financing of $667.7 million, proceeds from related parties and other financing of $443.0 million. The net cash generated from financing activities in 2013 related primarily to drawdowns of non-recourse loans for the construction of electric transmission lines in Peru and ACT in Mexico and the investment by Liberty in Solana. The net cash generated from financing activities during 2012 related to proceeds from non-recourse financing of $339.5 million, repayment of non-recourse financing of $61.6 million, proceeds from related parties and other financing of $829.3 million. The net cash generated from financing activities in 2012 relate mostly to proceeds for the construction of Solana, Mojave, electric transmission lines in Peru, ACT in Mexico and Solaben 2 and Solaben 3.

Off-Balance Sheet Arrangements

As of December 31, 2013, our only off-balance sheet arrangements consisted of bank bond and surety insurance in an aggregate amount of $7.1 million attributed to transactions of a technical nature.

 

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Tabular Disclosure of Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2013.

 

(in millions of U.S. dollars)		Total				Up to one year				Between one and three years				Between three and five years				Subsequent years
Loans with credit institutions		$	2,786.0			$	49.5			$	247.6			$	426.3			$	2,062.6
Notes and bonds		$	108.6			$	2.8			$	5.9			$	6.4			$	93.5
Purchase commitments		$	1,132.1			$	48.6			$	109.7			$	116.0			$	858.0
Derivative financial instruments		$	44.2			$	4.5			$	8.2			$	6.9			$	24.6
Accrued interest estimate during the useful life of loans		$	1,318.1			$	97.4			$	193.2			$	189.3			$	838.2

We have contractual obligations to make future payments in connection with bank debt and notes and bonds. In addition, during the normal course of business, we enter into agreements where we commit to future purchases of goods and services from third parties.

For more detailed information on Project Financing (loans with credit institutions) refer to Note 13 in our Annual Combined Financial Statements.

Notes and bonds refer to the carrying value of issuances made during 2013, which are described in detail in Note 13 in our Annual Combined Financial Statements.

Purchase obligations include agreements for the purchase of goods or services that are enforceable and legally binding on the combined group and that specify all significant terms, including fixed or minimum quantities to be purchased, fixed, minimum or variable price provisions and the appropriate timing of the transactions.

Accrued interest estimate during the useful life of loans represents the estimation for the total amount of interest to be paid or accumulated over the useful life of the loans, notes and bonds.

Critical Accounting Policies and Estimates

The preparation of our combined financial statements in conformity with IFRS requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and on various other assumptions we believe to be reasonable under the specific circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

An understanding of the accounting policies for these items is important to understand the combined financial statements. The following discussion provides more information regarding the estimates and assumptions used for these items in accordance with IFRS and should be considered in conjunction with the combined financial statements.

The most critical accounting policies, which reflect significant management estimates and judgment to determine amounts in our combined financial statements, are as follows:

 

•

Contracted concessional agreements and PPAs;

 

•

Impairment of intangible assets;

 

•

Assessment of control;

 

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•

Derivative financial instruments and fair value estimates; and

 

•

Income taxes and recoverable amount of deferred tax assets.

Some of these accounting policies require the application of significant judgment by management to select the appropriate assumptions to determine these estimates. These assumptions and estimates are based on our historical experience, forecasts and other circumstances and expectations as of the close of the financial period. The assessment is considered in relation to the global economic situation of the industries and regions where we operate, taking into account future development of our businesses. By their nature, these judgments are subject to an inherent degree of uncertainty; therefore, actual results could materially differ from the estimates and assumptions used. In such cases, the carrying values of assets and liabilities are adjusted.

As of the date of preparation of our Annual Combined Financial Statements, no relevant changes in the estimates made are anticipated and, therefore, no significant changes in the value of the assets and liabilities recognized at December 31, 2013, are expected.

Although these estimates and assumptions are being made using all available facts and circumstances, it is possible that future events may require management to amend such estimates and assumptions in future periods. Changes in accounting estimates are recognized prospectively, in accordance with IAS 8, in the combined income statement of the year in which the change occurs. Our significant accounting policies are more fully described in Note 2 to the Annual Combined Financial Statements as of and for the years ended December 31, 2013 and 2012, presented elsewhere in this prospectus.

Contracted concessional agreements

Contracted concessional assets include fixed assets financed through non-recourse loans, related to service concession arrangements recorded in accordance with IFRIC 12. The infrastructures accounted for as concessions are related to the activities concerning electric transmission lines, solar electricity generation plants, cogeneration plants and a wind farm. The infrastructure used in a concession can be classified as an intangible asset or a financial asset, depending on the nature of the payment entitlements established in the agreement.

The application of IFRIC 12 requires extensive judgment in relation with, among other factors, (i) the identification of certain infrastructures and contractual agreements in the scope of IFRIC 12, (ii) the understanding of the nature of the payments in order to determine the classification of the infrastructure as a financial asset or as an intangible asset and (iii) the timing and recognition of the revenue from construction and concessionary activity.

Under the terms of contractual arrangements within the scope of this interpretation, the operator shall recognize and measure revenue in accordance with IAS 11 and 18 for the services it performs. If the operator performs more than one service (i.e., construction or upgrade services and operation services) under a single contract or arrangement, consideration received or receivable shall be allocated by reference to the relative fair values of the services delivered, when the amounts are separately identifiable.

Consequently, even though construction is subcontracted to Abengoa, in accordance with the provisions of IFRIC 12, we recognize and measure revenue and costs for providing construction services during the period of construction of the infrastructure in accordance with IAS 11 “Construction Contracts.” Construction revenue is recorded within “Other operating income” and “Construction cost”, which is fully contracted with related parties, is recorded within “Other operating expense.” This applies in the same way to the two models.

 

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Intangible assets

We recognize an intangible asset to the extent that we receive a right to charge final customers for the use of the infrastructure. This intangible asset is subject to the provisions of IAS 38 and is amortized linearly, taking into account the estimated period of commercial operation of infrastructure, which generally coincides with the concession period.

We recognize and measure revenue, costs and margin for providing construction services during the period of construction of the infrastructure in accordance with IAS 11 “Construction contracts” and revenue for other services in accordance with IAS 18 “Revenue.” The interest costs derived from financing the project incurred during construction are capitalized during the period of time required to complete and prepare the asset for its predetermined use.

Once the infrastructure is in operation, the treatment of income and expenses is as follows:

 

•

Revenues from the updated annual revenue for the contracted concession, as well as operations and maintenance services are recognized in each period according to IAS 18 “Ordinary income.”

 

•

Operating and maintenance costs and general overheads and administrative costs are recorded in accordance with the nature of the cost incurred (amount due) in each period.

 

•

Financing costs are expensed as incurred.

Financial assets

We recognize a financial asset when demand risk is assumed by the grantor, to the extent that the contracted concession holder has an unconditional right to receive payments for the asset. This asset is recognized at the fair value of the construction services provided, considering improvements.

The financial asset is subsequently recorded at amortized cost calculated according to the effective interest method. Revenue from operations and maintenance services is recognized in each period according to IAS 18 “Ordinary income.” The remuneration of managing and operating the asset resulting from the valuation at amortized cost is also recorded in revenue.

Financing costs are expensed as incurred.

Impairment of intangible assets

We review our contracted revenue assets to identify any indicators of impairment annually.

The recoverable amount of an asset is the higher of its fair value less costs to sell and its value in use, defined as the present value of the estimated future cash flows to be generated by the asset. In the event that the asset does not generate cash flows independently of other assets, we calculate the recoverable amount of the cash generating unit, or CGU to which the asset belongs.

When the carrying amount of the CGU to which these assets belong is lower than its recoverable amount assets are impaired.

Assumptions used to calculate value in use include a discount rate and projections considering real data based on the contract terms and projected changes in both selling prices and costs. The discount rate is estimated by management, to reflect both changes in the value of money over time and the risks associated with the specific CGU.

 

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For contracted or concession revenue assets with a defined useful life and with a specific financial structure, cash flow projections until the end of the project are considered and no terminal value is assumed. Contracted revenue assets have a contractual structure that permits to estimate quite accurately the costs of the project (both in the construction and in the operations periods) and revenue during the life of the project.

Projections take into account real data based on the contract terms and fundamental assumptions based in specific reports prepared by experts, assumptions on demand and assumptions on production. Additionally, assumptions on macroeconomic conditions are also taken into account, such as inflation rates, future interest rates and sensitivity analysis are performed over all major assumptions, which can have a significant impact on the value of the asset.

Cash flow projections of CGUs are calculated in the functional currency of those CGUs and are discounted using rates that take into consideration the risk corresponding to each specific country and currency.

Taking into account that in most CGUs its specific financial structure is linked to the financial structure of the projects that are part of those CGUs, the discount rate used to calculate the present value of cash flow projections is based on the weighted average cost of capital (WACC) for the type of asset, adjusted, if necessary, in accordance with the business of the specific activity and with the risk associated with the country where the project is performed. In any case, sensitivity analyses are performed, especially in relation with the discount rate used and fair value changes in the main business variables, in order to ensure that possible changes in the estimates of these items do not impact the possible recovery of recognized assets. See Note 2 to our combined financial statements for further information on WACCs.

In the event that the recoverable amount of an asset is lower than its carrying amount, an impairment charge for the difference would be recorded in the combined income statement under the item “depreciation, amortization and impairment charges.”

Assessment of control

Control over an investee is achieved when we have power over the investee, we are exposed, or have rights, to variable returns from our involvement with the investee; and have the ability to use its power to affect its returns.

We reassess whether or not we control an investee when facts and circumstances indicate that there are changes to one or more of the three elements of control listed above. In order to evaluate the existence of control, we need to distinguish two independent stages in these projects in terms of the decision-making process: the construction phase and the operation phase. In some of these projects, such as Solana and Mojave, we have concluded that all the relevant decisions during the construction phase are subject to the approval of a third party. As a result, we do not have control over these assets during this period and we record these companies as associates under the equity method. Once the project is in operation, we gain control over these companies, which are then fully consolidated.

We use the acquisition method to account for business combinations. According to this method, identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Any contingent consideration is recognized at fair value at the acquisition date and subsequent changes in its fair value are recognized in accordance with IAS 39 either in profit or loss or as a change to other comprehensive income. Acquisition-related costs are expensed as incurred. We recognize any non-controlling interest in the acquired entity either at fair value or at the non-controlling interest’s proportionate share of the acquirer’s net assets on an acquisition-by-acquisition basis.

All assets and liabilities between entities within the group, equity, income, expenses and cash flows relating to transactions between entities of the group are eliminated in full.

 

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Derivative financial instruments and fair value estimates

Derivatives are recorded at fair value. We apply hedge accounting to all hedging derivatives that qualify to be accounted for as hedges under IFRS.

When hedge accounting is applied, hedging strategy and risk management objectives are documented at inception, as well as the relationship between hedging instruments and hedged items. Effectiveness of the hedging relationship needs to be assessed on an ongoing basis. Effectiveness tests are performed prospectively and retrospectively at inception and at each reporting date, following the dollar offset method.

We apply cash flow hedge accounting. Under this method, the effective portion of changes in fair value of derivatives designated as cash flow hedges are recorded temporarily in equity and are subsequently reclassified from equity to profit or loss in the same period or periods during which the hedged item affects profit or loss. Any ineffective portion of the hedged transaction is recorded in the combined income statement as it occurs.

When interest rate options are designated as hedging instruments, the intrinsic value and time value of the financial hedge instrument are separated. Changes in intrinsic value which are highly effective are recorded in equity and subsequently reclassified from equity to profit or loss in the same period or periods during which the hedged item affects profit or loss. Changes in time value are recorded as financial income or expenses, together with any ineffectiveness.

When the hedging instrument matures or is sold, or when it no longer meets the requirements to apply hedge accounting, accumulated gains and losses recorded in equity remain as such until the forecast transaction is ultimately recognized in the income statement. However, if it becomes unlikely that the forecast transaction will actually take place, the accumulated gains and losses in equity are recognized immediately in the income statement.

The inputs used to calculate fair value of our derivatives are based on inputs other than quoted prices that are observable for the asset or liability, either directly (i.e., as prices) or indirectly (i.e., derived from prices), through the application of valuation models (Level 2). The valuation techniques used to calculate fair value of our derivatives include discounting estimated future cash flows, using assumptions based on market conditions at the date of valuation or using market prices of similar comparable instruments, amongst others. The valuation of derivatives requires the use of considerable professional judgment. These determinations were based on available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Income taxes and recoverable amount of deferred tax assets

The current income tax provision is calculated on the basis of relevant tax laws in force at the date of the statement of financial position in the countries in which the subsidiaries and associates operate and generate taxable income.

Determining income tax payable requires judgment in assessing the timing and the amount of deductible and taxable items, as well as the interpretation and application of tax laws in different jurisdictions. Due to this fact, contingencies or additional tax expenses could arise as a result of tax inspections or different interpretations of certain tax laws by the corresponding tax authorities.

We recognize deferred tax assets for all deductible temporary differences and all unused tax losses and tax credits to the extent that it is probable that future taxable profit will be available against which they can be utilized.

 

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We consider it probable that we will have sufficient taxable profit available in the future to enable a deferred tax asset to be recovered when:

 

•

There are sufficient taxable temporary differences relating to the same tax authority, and the same taxable entity is expected to reverse either in the same period as the expected reversal of the deductible temporary difference or in periods into which a tax loss arising from the deferred tax asset can be carried back or forward.

 

•

It is probable that the taxable entity will have sufficient taxable profit, relating to the same tax authority and the same taxable entity, in the same period as the reversal of the deductible temporary difference (or in the periods into which a tax loss arising from the deferred tax asset can be carried back or forward).

 

•

Tax planning opportunities are available to the entity that will create taxable profit in appropriate periods.

Our management assesses the recoverability of deferred tax assets on the basis of estimates of future taxable profit. These estimates are derived from the projections of each of our assets. Based on our current estimates, we expect to generate sufficient future taxable income to achieve the realization of our current tax credits and tax loss carryforwards, supported by our historical trend of business performance.

In assessing the recoverability of our deferred tax assets, our management also considers the foreseen reversal of deferred tax liabilities and tax planning strategies. To the extent management relies on deferred tax liabilities for the readability of our deferred tax assets, such deferred tax liabilities are expected to reverse in the same period and jurisdiction and are of the same character as the temporary differences giving rise to the deferred tax assets. We consider that the recovery of our current deferred tax assets is probable without counting on potential tax planning strategies that we could use in the future.

Quantitative and Qualitative Disclosure about Market Risk

Our activities are undertaken through our segments and are exposed to market risk, credit risk and liquidity risk. Risk is managed by our Risk Management and Finance Department in accordance with mandatory internal management rules. The internal management rules provide written policies for the management of overall risk, as well as for specific areas, such as exchange rate risk, interest rate risk, credit risk, liquidity risk, use of hedging instruments and derivatives and the investment of excess cash.

Market risk

We are exposed to market risk, such as movement in foreign exchange rates and interest rates. All of these market risks arise in the normal course of business and we do not carry out speculative operations. For the purpose of managing these risks, we use a series of swaps and options on interest rates. None of the derivative contracts signed has an unlimited lose exposure.

Foreign exchange rate risk

The main cash flows in the entities included in these combined financial statements are cash collections arising from long-term contracts with clients and debt payments arising from project finance repayment. Given that financing of the projects is always denominated in the same currency in which the contract with the client is signed, a natural hedge exists for our main operations. Consequently, there are no forward sale contracts signed as of December 31, 2013.

 

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Interest rate risk

Interest rate risks arise mainly from our financial liabilities at variable interest rate (less than 10% of our total project debt financing). We use interest rate swaps and interest rate options (caps) to mitigate interest rate risk.

As a result, the notional amounts hedged, strikes contracted and maturities, depending on the characteristics of the debt on which the interest rate risk is being hedged, are very diverse, including the following:

 

1)

Non-recourse debt in U.S. dollars: between 75% and 100% of the notional amount, maturities until 2028 and average guaranteed interest rates of between 2.515% and 3.787%.

 

2)

Non-recourse debt in euro: between 80% and 100% of the notional amount, maturities until 2030 and average guaranteed interest rates of between 0.75% and 3.75%.

In connection with our interest rate derivative positions, the most significant impact on our combined financial statements are derived from the changes in EURIBOR or LIBOR, which represents the reference interest rate for the majority of our debt.

In relation to our interest rate swaps positions, an increase in EURIBOR or LIBOR above the contracted fixed interest rate would create an increase in our financial expense which would be positively mitigated by our hedges, reducing our financial expense to our contracted fixed interest rate. However, an increase in EURIBOR or LIBOR that does not exceed the contracted fixed interest rate would not be offset by our derivative position and would result in a net financial loss recognized in our combined income statement. Conversely, a decrease in EURIBOR or LIBOR below the contracted fixed interest rate would result in lower interest expense on our variable rate debt, which would be offset by a negative impact from the mark-to-market of our hedges, increasing our financial expense up to our contracted fixed interest rate, thus likely resulting in a neutral effect.

In relation to our interest rate options positions, an increase in EURIBOR or LIBOR above the strike price would result in higher interest expenses, which would be positively mitigated by our hedges, reducing our financial expense to our capped interest rate, whereas a decrease of EURIBOR or LIBOR below the strike price would result in lower interest expenses.

In addition to the above, our results of operations can be affected by changes in interest rates with respect to the unhedged portion of our indebtedness that bears interest at floating rates.

In the event that EURIBOR and LIBOR had risen by 25 basis points as of December 31, 2013, with the rest of the variables remaining constant, the effect in the combined income statement would have been a loss of $195,000 (a profit of $296,000 in 2012) and an increase in hedging reserves of $16.3 million ($24.0 million in 2012). The increase in hedging reserves would be mainly due to an increase in the fair value of interest rate swaps designated as hedges.

Credit risk

We consider that we have limited credit risk with clients as revenues are derived from power purchase agreements and other revenue contracted agreements with electric utilities and state-owned entities.

The following table shows the maturity detail of trade receivables as of December 31, 2013 and 2012:

 

		Balance as of December 31,
		2013				2012
		(in $ millions)
Maturity
Up to 3 months		$	26.6			$	11.2
Between 3 and 6 months			—				—
Total		$	26.6			$	11.2

 

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Liquidity risk

The objective of our financing and liquidity policy is to ensure that we maintain sufficient funds to meet our financial obligations as they fall due.

Project finance borrowing permits us to finance projects through non-recourse debt and thereby insulate the rest of our assets from such credit exposure. We incur project finance debt on a project-by-project basis.

The repayment profile of each project is established on the basis of the projected cash flow generation of the business. This ensures that sufficient financing is available to meet deadlines and maturities, which mitigates the liquidity risk significantly.

 

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INDUSTRY AND MARKET OPPORTUNITY

Overview

Over the last decade, global investment in the renewable energy and environmental sectors has witnessed significant growth. Moreover, energy scarcity, the focus on reduction of carbon emissions, and the potential increased costs of building and operating conventional and nuclear plants are expected to continue to drive renewable technology. We expect this to continue both in the short- and long-term and expect that this will support demand for the type of contracted assets that we own. Overall energy demand is expected to increase by 1.2% per year from 2011 through 2035, while fossil-based energy sources are expected to become scarcer. The World Energy Outlook forecasts that, for example, global installed capacity of solar power will grow at 10% per year from 2011 to reach capacity of 760 GW by 2035. In addition, according to the International Energy Association, total investment of $1.8 trillion is expected in the electric transmission sector worldwide between 2012 and 2035 and approximately 61% of such investment is projected in regions where we focus our electric transmission activity. Bloomberg’s Global Renewable Energy Market Outlook expects generation from renewable sources to increase significantly from 2012 to 2030.

In addition, increasing environmental consciousness, reducing carbon and greenhouse gas emissions, increasing focus on security of energy supply in many developed countries and the related tightening of environmental regulation are important factors that we expect to bolster global demand and provide an impetus to our sustainable development focus.

Solar

Solar energy is one of the largest sources of renewable energy and the market for solar energy has become increasingly prominent in recent years. According to the BP Statistical Review of World Energy 2013, the global consumption of solar electricity has grown from 1.6 TWh in 2002 to more than 90 TWh in 2012. The principal factors that have contributed to the development of this industry are the following:

 

•

political will and awareness of environmental problems associated with non-renewable energy sources;

 

•

the need for countries with limited fossil fuel resources to reduce dependence on non-renewable energy sources; and

 

•

the increased cost and price volatility of fossil fuels.

Among the different types of renewable energy, solar energy has become a technologically proven option. The two technologies that rely on solar power as a primary source of electricity generation are Concentrating Solar Power and photovoltaics, or PV.

Overview of Concentrating Solar Power Technology

Concentrating Solar Power technology uses direct sunlight to heat a fluid (heat transfer fluid) that produces steam to feed a steam cycle and produce electricity. This technology has experienced significant international development in the last decade. Concentrating Solar Power technology requires a high level of direct solar irradiation to be feasible. The best geographical areas for Concentrating Solar Power plants are located between 35º North and 35º South from the Equator, an area that we refer to as the “sunbelt.” This area includes the southwestern United States and Spain, where we have Concentrating Solar Power facilities.

The most important factor that distinguishes Concentrating Solar Power technology from other forms of renewable energy generation, such as PV, is its “dispatchability,” or the ability to adapt production to demand, which is essential for electrical grids. During the course of a day, demand for electricity fluctuates according to human activity with three different phases: base, middle and peak, which are covered with different loads by the utilities. Not all renewable energy sources are able to meet demand in the same way as Concentrating Solar

 

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Power for daily power generation. PV and wind are intermittent sources of renewable power and battery storage for those sources is relatively expensive and cumbersome. PV and wind cannot generate power at all times and therefore require back-up capacity and can unbalance the electrical grid. However, in contrast to PV and wind, Concentrating Solar Power plants achieve dispatchability through thermal inertia inherent in the heat transfer fluid used, the addition of thermal energy storage and/or hybridization with conventional fuels, like gas or biomass. Accordingly, Concentrating Solar Power is more versatile than PV because it can meet base, middle and peak load demands.

There are four technologies in the Concentrating Solar Power market:

 

•

parabolic trough;

 

•

tower;

 

•

Fresnel; and

 

•

dish Stirling,

among which parabolic trough and tower are the more mature and commercially available technologies.

Our four Concentrating Solar Power projects use parabolic trough technology. Parabolic trough systems consist of parallel rows of mirrors (reflectors) curved in one dimension to focus the sun’s rays. The mirror arrays can be more than 100 meters long with the curved surface that is five to six meters across. Stainless steel pipes (absorber tubes) with a selective coating serve as the heat collectors. The coating is designed to allow pipes to absorb high levels of solar radiation while emitting very little infrared radiation. The pipes are insulated in an evacuated glass envelope. The reflectors and the absorber tubes move in tandem with the sun as it crosses the sky. Synthetic oil is the fluid used to transfer heat from collector pipes to heat exchangers, where water is preheated, evaporated and then superheated into steam. The superheated steam runs a turbine, which drives a generator to produce electricity. After being cooled and condensed, the water returns to the heat exchangers. Some of the Concentrating Solar Power plants have seven or more hours of storage capacity by using molten salts storage technology, other plants have around three hours of capacity and some plants have no storage capacity other than the plant’s thermal inertia.

Concentrating Solar Power Technology in the United States

Concentrating Solar Power development in the United States began in the late 1970s with the creation by the DOE of renewable energy incentives and the development of energy R&D programs. These developments occurred following the oil crisis in the 1970s and the recognition of the need for the United States to become energy independent. California, which has among the best direct solar insolation in the United States, was the first state to support solar development. State tax incentives in California combined with federal tax incentives enabled the construction of the first Concentrating Solar Power plants in California in the late 1980s.

California’s policies enabled the building of nine SEGS plants with a total capacity of 354 MW, in the Mojave Desert from 1985 through 1992. The SEGS plants sold electricity to Southern California Edison with 30-year PPAs for each plant and each SEGS plant belonged to an independent investor group. The construction and operation of the SEGS plants was a landmark for Concentrating Solar Power in the United States and demonstrated the financial viability of parabolic trough Concentrating Solar Power plants. The SEGS plants continued to operate and their operation and maintenance was eventually taken over by the Kramer Junction Company and two other companies. The SEGS plants continue to produce electricity under their existing contracts.

A further wave of Concentrating Solar Power development in the United States began ten years ago with the re-establishment of federal renewable energy policies and the enactment of state renewable portfolio standards.

The Energy Policy Act of 2005 established the 1603 Loan Guarantee Program by the DOE to help renewable energy projects obtain financing at lower interest rates and longer terms by providing the financial

 

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support of the U.S. federal government. This program has expanded since 2005 through federal legislation and renewable energy received additional support following the election of President Obama in 2008. The Emergency Economic Stabilization Act of 2008, or EESA, included tax credits for investments in wind and solar power generation facilities. The EESA included an investment tax credit, or ITC, which provides a tax credit of 30% for qualified expenditures for solar power facilities that are placed in service on or before December 31, 2016. This credit is currently scheduled to be reduced to 10% effective January 1, 2017. The ITC is crucial for the development of large-scale Concentrating Solar Power plants in the United States. The benefits of ITC may also be reduced in any future tax reform.

The American Recovery and Reinvestment Act of 2009 provided further support for the Concentrating Solar Power industry by earmarking billions of dollars for renewable energy projects. In addition, the DOE’s Concentrating Solar Power budget for R&D programs increased ten-fold from 2004 to 2011.

Some states also have enacted renewable portfolio standards, or RPS, to help develop renewable energy projects. RPSs require regulated retail electric utilities to procure a specified percentage of total electricity delivered to retail customers in the state from eligible renewable generation sources, such as Concentrating Solar Power facilities, by a specified date. Since 2004, 29 states have enacted RPSs. California has a 33% renewable energy mandate by 2020, Nevada has a renewable energy target of 25% by 2025 and Arizona has 15% renewable energy mandate by 2025.

According to SEIA, from 2005 to 2010, new Concentrating Solar Power projects were developed in the southwestern United States reaching total operating capacity of 517 MW. Since 2010, five new Concentrating Solar Power plants, including Solana, have been built reaching a total operating capacity of 1,300 MW.

The future development of the Concentrating Solar Power industry in the United States will be tied to federal and state incentives and state RPS targets. California continues to be an ardent supporter of solar power in general and Concentrating Solar Power in particular. Arizona, Nevada, New Mexico and Texas may increase their respective RPSs, but any such increase would require legislative action.

At the federal level, the ITC is available for solar projects that are placed in service by December 31, 2016. Concentrating Solar Power plants require multi-year development timelines and for the ITC to be of further practical use, Congress would need to replace the “placed in service” requirement with a “commence construction” requirement. The “placed in service” requirement means that any solar project needs to be complete and capable of generating power substantially equal to its capacity by December 31, 2016 in order to be eligible for the ITC. A “commence construction” requirement would allow projects that start construction prior to the December 31, 2016 deadline to take advantage of the ITC when such projects were placed into service, even if they were placed in service after the December 31, 2016 deadline. The benefits of ITC may also be reduced in any future tax reform.

Accelerated depreciation for projects is available pursuant to the Modified Accelerated Cost Recovery System, or MACRS, for Concentrating Solar Power projects, but the benefits of MACRS could be reduced in any future tax reform. There is also legislative discussion regarding the inclusion of renewable energy projects as qualified assets for Real Estate Investment Trusts and Master Limited Partnerships, which may offer a new financing approach and capital leverage.

Additionally, through Presidential action, the Environmental Protection Agency, or EPA, is tightening its regulations on new coal power plants, and as a result, fewer coal plants may be built and many existing coal power plants may close, which may increase the demand for renewable energy. Finally, there is also the possibility that the United States will enact a federal carbon pricing legislation or a carbon tax, which could increase the cost of carbon-based energy resources.

 

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Concentrating Solar Power in Spain

Since the late twentieth century, various governments of Spain have strongly promoted renewable energies. The Development Plan for Renewable Energy (2000-2010) aimed to generate 30% of electricity from renewable energy sources in 2010. The objective was achieved for electricity in 2010 as 35% of the total electricity demand was generated from renewable energy sources and renewable energy sources became the main source of electricity generation in the country.

The regulation of renewable energies based on a feed-in-tariff system facilitated the penetration of renewable energies in Spain. Currently, energy projects receive a fixed and variable monthly payment in addition to the market price of electricity produced, that guarantees a return linked to the long-term Spanish Government bond yield applied to a standardized asset base, plus a complement to cover standardized O&M expenses. See “Regulation—Regulation in Spain.”

Spain has a historical record of accomplishment in the Concentrating Solar Power development. In 1981, the “Plataforma Solar Almeria” started its operations, an R&D center jointly sponsored by the German and Spanish governments in order to develop and improve Concentrating Solar Power technologies.

The evolution of the Concentrating Solar Power in Spain represented a breakthrough in the development of this technology. Since 2007, when Abengoa opened Europe’s first commercial Concentrating Solar Power tower plant, with capacity of 11 MW in Seville, the Concentrating Solar Power market has expanded rapidly; there are now 50 plants with a total capacity of 2,300 MW, according to the European Solar Thermal Electricity Association. Abengoa is the leader in this market with an aggregate installed capacity of 681 MW.

Concentrating Solar Power in Other Markets

As of the date hereof, our business in Concentrating Solar Power is concentrated in the United States and Spain. Going forward, as we acquire new assets (whether Abengoa ROFO Assets or otherwise), we expect to expand our operations in other “Sunbelt” areas such as Chile, the Middle East and South Africa, where new Concentrating Solar Power projects are being developed at a significant scale.

Wind Power

Wind power harnesses the kinetic energy of moving air. Electricity is generated from the energy of wind flows exerted on the blades of a wind turbine, which activates an electric generator. Wind turbines are equipped with a control system that optimizes electricity generation output. In addition, wind power projects can be monitored and operated remotely to respond to changing weather conditions, including shutting down during heavy lightning storms and rotating to adjust to shifts in wind direction.

The amount of energy that the wind transfers to the turbine depends on the blades’ surface area and the wind speed. The amount of energy captured by a wind turbine increases as a square-function of an increase in blade size. For example, doubling the surface area of the blades quadruples the wind energy captured. The speed of the wind has an even greater effect. As wind speed doubles, the available energy increases by a factor of eight. Stronger winds are also able to drive larger turbine blades. In order to maximize the efficiency of the transfer of energy from wind to electricity, blade size must be designed to capture the most wind energy the highest proportion of the time.

Wind is a source of energy that is naturally variable; wind generally does not blow at a constant speed throughout a given day nor month-to-month. As a result, the amount of electricity generated on a daily or monthly basis is also variable or intermittent. However, long-term historical site-specific measurements for wind power allow for an annual average or “mean” wind speed, enabling the use of statistical analyses to estimate electricity generation.

 

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Wind Power in Uruguay

A number of Latin American governments are looking to wind power to support their emerging economies, to alleviate variations in hydropower and other seasonal electricity sources, and to reduce the threat posed by insecure imported power sources.

Latin America has abundant wind resources, both onshore and offshore, much of which remains untapped in many countries. According to the Global Wind Energy Council, in 2013 the Latin American market installed 1.1 GW of new wind capacity, reaching a total installed capacity of just over 4.7 GW. MAKE Consulting forecasts a 20% compounded annual growth rate in Latin America. MAKE Consulting also predicts that, for the first time, the majority of new wind capacity brought online in the Americas will occur outside of the U.S. market. Wind Power estimates that by 2025, wind power production in all of Latin America, including Mexico, will reach a capacity of 37.7 GW, including capacity of 1.5 GW in Uruguay.

In Uruguay, the traditional main source of energy has been hydroelectric power. However, due to growing demand, the exploitation of large-scale hydropower has reached its economic limit. This has resulted in the installation of additional base load thermal plants and the incorporation of other alternative energy sources.

However, due to thermal generation’s environmental costs and oil price volatility, there is an opportunity for the development of renewable energies. It is therefore expected that UTE, the state-owned company in Uruguay that has a monopoly over the transmission and distribution of energy and controls 58% of all generation capacity, will continue to award PPAs to private generators for renewable energy purchases, particularly in wind and biomass.

Conventional Power

Cogeneration, which is the simultaneous production of electricity and heat using a single fuel source such as natural gas, harnesses heat that would otherwise be wasted in the generation of power.

The cogeneration process increases thermal efficiency and reduces emissions of carbon dioxide that are a normal part of the power generation process. Cogeneration can therefore make a meaningful contribution towards the achievement of emissions stabilization necessary to reduce the risk of major climate disruption.

Power Generation in Mexico

According to the Secretaria de Energia de Mexico, power generation in Mexico amounted to approximately 300,000 GWh in 2012. The power generation market in Mexico is comprised of:

 

•

state-owned power generation plants, which contributed 60.4% of energy generated;

 

•

independent power producers, or IPPs, which produced 28.1% of the energy generated; and

 

•

self-generation, which accounted for 11.6% of the energy generated.

According to the Secretaria de Energia de Mexico, conventional sources, which include thermal, dual and coal, accounted for 73% of generation capacity in the country as of 2013.

The energy sector in Mexico is administered by the Secretaria de Energia de Mexico, and by several commissions and institutions at both the federal level and state level. Two state-owned companies, the Comision Federal de Electricidad, or CFE and Pemex, are both particularly important to this sector and our operations in Mexico.

CFE is a company created and owned by the Mexican government. According to CFE, it generates, distributes and markets electric power for almost 35.3 million customers and almost 100 million people. It produces electric power using various technologies and primary energy sources, mainly thermoelectric and hydroelectric, and all IPPs in Mexico are required to sell their energy production to CFE. CFE also serves as the power planning body of the country.

 

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Pemex is a state-owned petroleum company which until recently had a monopoly of exploration, refining and distribution of hydrocarbons in Mexico.

We believe future growth of the Mexican conventional power industry will be driven by economic growth in Mexico and the effect of the energy reform that is currently under way.

Energy Reform in Mexico

Mexican energy reform has three main pillars:

 

•

to facilitate and increase the role of private sector investment in the power sector and in areas of the hydrocarbons value chain (such as refining);

 

•

to strengthen independence and transparency in the energy regulatory bodies; and

 

•

to focus to a greater extent on environmental protection by fostering cleaner energies and fuels (such as natural gas and co-generation schemes).

We believe that the effect of this reform, coupled with economic growth in the country, may foster new capacity additions in the private sector for projects such as combined cycles and cogeneration plants.

We own one co-generation plant in Mexico that produces both steam and power and we believe there are significant additional co-generation opportunities in Mexico.

According to Secretaria de Energia de Mexico, co-generation potential in Mexico is estimated to be between 6 and 10 GW in total, comprising 1 GW for the sugar production sector, between 2 and 6 GW for the general industrial sector and 3 GW for Pemex.

Electric Transmission

Overview

The potential for growth and development in the electric transmission sector comes from several factors: (i) increasing global demand for electricity, (ii) inadequate and insufficient electrical grid capacity, (iii) construction of new power plants and demand-response facilities and (iv) the need to connect new renewable energy generation plants, which are typically built in remote areas, to consumption centers. Due to the unique need to locate renewable power plants in remote areas, new renewable power plants will require additional electric transmission infrastructure to bring electrical power to consumption centers.

Electric Transmission in Brazil

In Brazil, the National Interconnected System, or Sistema Interligado Nacional, SIN, provides electricity to consumers. According to Operador Nacional do Sistema Eletrico, only 1.7% of energy required is managed outside the SIN in isolated systems in the Amazonia region.

The SIN is divided into south, southeast, center-west, northeast and north regions. According to Agencia Nacional de Energia Eletrica, the electric transmission system in Brazil is very large due to the long distance from hydropower plants, which are the key energy source for the country, to consumption centers.

Although the Brazilian electric power industry is deregulated, most major companies involved in electric transmission are state-owned. According to Eletrobras, which is partially state-owned, it is responsible for 38,235 miles of transmission lines and 257 substations, representing nearly 55% of the total of electric transmission lines in Brazil. Eletrobras directly owns 36,187 miles of transmission lines and the remaining transmission were won in auctions through special purpose entities. According to Cemig, which is controlled by the State of Minas Gerais, it operates a 4,664-mile transmission network through its controlled and associated electric energy transmission companies.

 

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Key participants in the regulation, expansion and management of the transmission sector in Brazil are:

 

•

the National System Operator, or Operador Nacional do Sistema Eletrico, which is responsible for the operation, coordination and control of the generation and transmission activities within the SIN;

 

•

the Brazil Electricity Regulatory Agency, or Agencia Nacional de Energia Eletrica, the Brazilian electricity regulatory agency, which seeks to provide favorable conditions for the electric power market and to develop a balance between market participants and the benefit of society;

 

•

the Electric Power Commercialization Chamber, or Camara de Comercializacao de Energia Eletrica, which is responsible for the commercialization of electric power in the Brazilian power market;

 

•

the Power Research Company, or Empresa de Pesquisa Energetica, which carries out studies and research services in the planning of the energy sector; and

 

•

the Ministry of Energy and Mines, or Ministerio de Minas e Energia, which has the overall responsibility for policy setting in the electricity sector.

The energy needs of an expanding middle class in Brazil are driving rising consumption and has resulted in strong growth in demand for transport fuels and a doubling of electricity consumption. Meeting this demand requires substantial and timely investment throughout the energy system of $90 billion per year on average. According to World Energy Outlook 2013, the system of auctions for new electricity generation and transmission capacity will continue to be vital in bringing new capital to the power sector and in reducing pressure on end-user prices.

Electric Transmission in Peru

In Peru, the National Interconnected Electric System, or Sistema Electrico Interconectado Nacional, SEIN, provides electricity to most consumers and stand-alone systems cover the rest of the country.

The SEIN is divided in fifteen different operative areas that are consolidated into the north, center and south regions. Power lines in these regions belong to three categories:

 

•

National Transmission System, or Sistema de Transmision Troncal Nacional, with 500kV electric transmission lines or electric transmission lines connecting two operative areas;

 

•

Regional Transmission System, or Sistema de Transmision Troncal Regional, with electric transmission lines with voltages between 138–220kV inside an operative area; and

 

•

the Local Transmission System, or Sistema de Transmision Local, with electric transmission lines connecting power plants or loads to the SEIN.

Transmission activities are carried out by ten main private companies including ATN and ATS, according to COES SINAC—Comite de Operacion Economica del Sistema Interconectado Nacional.

The most important entities in the regulation, expansion and management of the transmission sector in the country are:

 

•

the National Interconnected System Economic Operation Committee, or COES SINAC, Comite de Operacion Economica del Sistema Interconectado Nacional, composed of all of the agents of the SEIN to coordinate the operation of the transmission system;

 

•

the Energy and Mining Ministry, or Ministerio de Energia y Minas, MEM, with the Electricity General Direction (Direccion General de Electricidad, DGE, in charge of developing policies and analysis, evaluating and awarding electricity rights (including electric transmission and distribution concessions)); and

 

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•

the Investment Supervisor Entity for Energy and Mining, or Organismo Supervisor de la Inversion en Energia y Mineria, which is responsible for regulating and supervising the electric, mining and hydrocarbons companies.

Peru recently approved a transmission plan to improve the SEIN between 2013 and 2022. The plan includes both new electric transmission lines and re-powering of already-built electric transmission lines. MEM estimates that total investment is $1,240 million. We believe this transmission plan will continue to generate opportunities for growth.

Electric Transmission in Chile

The existing transmission system in Chile consists of two interconnected electrical systems or markets: the Central Interconnected System, or SIC, and the Northern Interconnected System, or SING. Historical development in both systems has been conditioned by their distinctive geographic, economic and commercial traits.

The majority of the SIC transmission facilities have been linked to the development of public generation and distribution services that serve most of the population in the country. A significant portion of the SING transmission facilities have been developed by larger customers in the Chilean mining industry, which own 32% of operating power lines when measured in kilometers. The longitudinal geographic orientation of Chile and distance of the hydroelectric generation facilities from the consumption centers have differentiated transmission in both systems. The SIC has facilities with transmission capacity intended to carry the hydroelectric energy from South-central Chile through a 500kV system.

The ownership of the transmission systems is distributed through agents that operate in all segments, including mining and industrial clients. The main participant in the electricity transmission sector in Chile is Transelec.

In Chile, the transmission sector is considered to be a natural monopoly, which means that the revenues and access conditions are subject to regulation. Although a concession model with long-term contracted revenue is not mandatory, contracted concessions have become the most used modality in the transmission business, since its implementation is necessary either to use public national assets or to enforce easements upon private property.

The most important entities in the regulation, expansion and management of the transmission sector in Chile are:

 

•

the Department of Economy, or Ministerio de Economia, MINECOM, which grants permanent transmission concessions, formalizes the administrative acts of regulation and sets prices and transmission toll fees;

 

•

Superintendent’s Office of Electricity and Fuels, or Superintendencia de Electricidad y Combustibles, the sector’s monitoring entity that oversees quality and service safety compliance;

 

•

National Board of Energy, or Comision Nacional de Energia, which develops the technical reports that support administrative acts carried out by MINECOM; and

 

•

Economic Load Dispatch Center, or Centro de Despacho Economico de Cargas, the entity in charge of coordinating short-term operation, determining payments coming from energy and power transfers in the spot market between companies.

We believe that growth in transmission lines in Chile will continue to be driven by (i) the need to transport power from the hydropower resources in southern Chile to the consumption centers; (ii) the interconnection of both SIC and SING systems; and (iii) the growth of energy demand by mining projects in northern Chile.

 

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Water

Although we do not own any assets in the water sector as of the date of this prospectus, we intend to evaluate and potentially purchase water assets in the future, particularly in the field of desalination and water transportation.

We expect the water sector to experience significant growth globally driven by the following long-term trends:

 

•

Growing water demand and water scarcity: As demand for water grows in areas with limited resources, driven by increasing world population, the need to develop new assets to produce water (i.e., desalination and potabilization) and to transport water will grow as well. In fact, the increase in demand for water has surpassed population growth by a factor of two as a result of the increased income per person and growth in water use for agricultural purposes and industrial development.

 

•

Regulation of water management and enforcement of those regulations will continue to intensify: As public awareness and concerns about water grow, we expect a corresponding increase in governmental attention, legislation, regulatory controls and overview and enforcement.

 

•

Pressure to deliver better performance: Water utility companies are under pressure to maximize operating efficiencies and performance, and we believe that infrastructure and technologies that will allow them to do so will be in high demand.

 

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BUSINESS

About Abengoa Yield

We are a dividend growth-oriented company formed to serve as the primary vehicle through which Abengoa will own, manage and acquire renewable energy, conventional power and electric transmission lines and other contracted revenue-generating assets, initially focused on North America (the United States and Mexico) and South America (Peru, Chile, Uruguay and Brazil), as well as Europe (Spain). In the future, we intend to expand this presence to selected countries in Africa and the Middle East.

We believe we are well positioned to be a premier company for investors seeking a total return based on stable and growing dividend income from a diversified portfolio of low-risk, high-quality assets, and for investors with a key objective of accretive dividend growth.

We intend to take advantage of favorable trends in the power generation and electric transmission sectors globally, including energy scarcity and a focus on the reduction of carbon emissions. To that end, we believe that our cash flow profile, coupled with our scale, diversity and low-cost business model, will offer us a lower cost of capital than that of a traditional engineering and construction company or independent power producer and provide us with a significant competitive advantage with which to execute our growth strategy.

With this business model, our objective is to pay a consistent and growing cash dividend to holders of our shares that is sustainable on a long-term basis. We expect to target a payout ratio of 90% of our cash available for distribution and will seek to increase such cash dividends over time through organic growth and as we acquire assets with characteristics similar to those in our current portfolio. We will focus on high-quality, newly-constructed and long-life facilities with creditworthy counterparties that we expect will produce stable, long-term cash flows.

Upon consummation of this offering, we will own eleven assets, comprising 710 MW of renewable energy generation, 300 MW of conventional power generation and 1,018 miles of electric transmission lines and an exchangeable preferred equity investment in ACBH. Each of the assets we own has a project-finance agreement in place. Our project-level debt was approximately $2,830 million as of March 31, 2014. When we refer to these assets as our assets or being owned by us throughout this prospectus, we mean that they will be transferred to us by Abengoa and owned by us immediately prior to the consummation of the offering.

We have signed an exclusive agreement with Abengoa, which we refer to as the ROFO Agreement, which provides us with a right of first offer on any proposed sale, transfer or other disposition of any of Abengoa’s contracted renewable energy, conventional power, electric transmission or water assets in operation and located in the United States, Canada, Mexico, Chile, Peru, Uruguay, Brazil, Colombia and the European Union, as well as four assets in selected countries in Africa and the Middle East. We refer to the contracted assets subject to the ROFO Agreement as the “Abengoa ROFO Assets.” See “Related Party Transactions—Right of First Offer.” Based on the acquisition opportunities available to us, which include the Abengoa ROFO Assets as well as any third-party acquisitions we pursue, we believe that we will have the opportunity to grow our cash available for distribution in a manner that would allow us to further increase our cash dividends per share over time. Prospective investors should read “Cash Dividend Policy,” including our financial forecast and related assumptions, and “Risk Factors,” including the risks and uncertainties related to our forecasted results, acquisition opportunities and growth plan, in their entirety.

Pursuant to our cash dividend policy, we intend to pay a cash dividend each quarter to holders of our shares. Our initial quarterly dividend will be set at $0.2592 per share, or $1.04 per share on an annualized basis. See “Cash Dividend Policy.”

Together with the quarterly dividend corresponding to the third quarter of 2014, we expect to pay an additional dividend of $0.2592 per share, pro-rated to the number of days elapsed from the completion of this offering until the end of the second quarter of 2014.

 

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Upon consummation of this offering (assuming no exercise of the underwriters’ over-allotment option), Abengoa will own indirectly         % of our shares.

Purpose of Abengoa Yield

Through this offering, Abengoa and Abengoa Yield intend to create enhanced value for holders of our shares by seeking to achieve the following objectives:

 

•

offer an investment vehicle with predictable, recurrent and growing dividends to investors valuing long-term contracted assets;

 

•

create a vehicle with a competitive source of equity capital to benefit from the acquisition of long-term contracted assets developed by Abengoa and other third-party assets; and

 

•

align strategic interests, with Abengoa maintaining a majority shareholding in Abengoa Yield.

Current Operations

We own a diversified portfolio of renewable energy, conventional power and electric transmission line contracted assets in North America (the United States and Mexico) and South America (Peru, Chile, Uruguay and Brazil), as well as in Spain. Our portfolio consists of five renewable energy assets, a cogeneration facility and several electric transmission lines, all of which are fully operational, with the exception of Palmatir, construction of which is complete and which we expect to be fully operational in May 2014, and Mojave, construction of which is substantially complete and which we expect to be fully operational by October 2014. In addition, we own an exchangeable preferred equity investment in Abengoa Concessoes Brasil Holding, or ACBH, a subsidiary holding company of Abengoa that is engaged in the development, construction, investment and management of contracted concessions in Brazil, consisting mostly of transmission lines. All of our assets have contracted revenues (regulated revenues in the case of the Spanish assets) with low-risk offtakers, and collectively have an average remaining contract life of approximately 26 years as of December 31, 2013. Over 90% of cash generated each year and available for distribution from these assets in the next four years will be in U.S. dollars or indexed to the U.S. dollar, and our policy is to use currency coverage contracts if required to maintain that ratio. Over 90% of our project-level debt is hedged against changes in interest rates through an underlying fixed rate on the debt instrument or through interest rate swaps, caps or similar hedging instruments.

Our renewable energy assets consist of: (i) two Concentrating Solar Power plants in the United States, Solana and Mojave, each with a gross capacity of 280 MW; (ii) one on-shore wind farm in Uruguay, Palmatir, with a gross capacity of 50 MW; and (iii) two Concentrating Solar Power plants in Spain, Solaben 2 and Solaben 3, each with a gross capacity of 50 MW. We have selected these assets because they represent a diversified portfolio in terms of technology and geography, are relatively mature and have an attractive cash generation profile.

Our conventional power asset consists of Abengoa Cogeneracion Tabasco, or ACT, a 300 MW cogeneration plant in Mexico.

Our electric transmission assets consist of: (i) two lines in Peru, ATN and ATS, spanning a total of 931 miles; (ii) three lines in Chile, Quadra 1, Quadra 2 and Palmucho, spanning a total of 87 miles; and (iii) an exchangeable preferred equity investment in ACBH.

 

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Our forecasted cash available for distribution for the twelve months ending June 30, 2016, which reflects the first full twelve-month period when all of our eleven current assets, including Mojave, which are expected to distribute cash on a recurrent basis, is as set forth below by business sector and geography after deducting general and administrative expenses allocated proportionally across geographies and business sectors:

 

Our annual forecasted cash available for distribution for the twelve months ending June 30, 2015 and the twelve months ending June 30, 2016 based on our current assets and without any acquisitions are as set forth below:

 

 

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The following table provides an overview of our current assets (excluding our exchangeable preferred equity investment in ACBH):

 

Our Assets

Type

Ownership

Location

Currency

Capacity (Gross)

Status

Offtaker

Counterparty Credit Ratings(3)

COD/ Expected COD

Contract Years Left

Solana

Renewable (CSP)

100% Class B(1)

Arizona (USA)

USD

280 MW

Operational

APS

A-/A3/BBB+

4Q 2013

29

Mojave

Renewable (CSP)

100%

California (USA)

USD

280 MW

Startup and Production Testing

PG&E

BBB/A3/BBB+

4Q 2014

25

ACT

Conventional Power

100%

Mexico

USD

300 MW

Operational

Pemex

BBB+/Baa1/BBB+

2Q 2013

19

ATN

Transmission Line

100%

Peru

USD

362 Miles

Operational

Peru

BBB+/Baa2/BBB+

1Q 2011

27

ATS

Transmission Line

100%

Peru

USD

569 Miles

Operational

Peru

BBB+/Baa2/BBB+

1Q 2014

30

Quadra 1 & Quadra 2

Transmission Line

100%

Chile

USD

81 Miles

Operational

Sierra Gorda

N/A

2Q2014 & 1Q 2014

21

Palmucho

Transmission Line

100%

Chile

CLP

6 Miles

Operational

Endesa Chile

BBB+/Baa2/BBB+

4Q 2007

23

Palmatir

Renewable (Wind)

100%

Uruguay

USD

50 MW

Startup and Production Testing

Uruguay

BBB-/Baa3/BBB-

2Q 2014

20

Solaben 2 & Solaben 3

Renewable (CSP)

70%(2)

Spain

Euro

2x50 MW

Operational

Spain

BBB-/Baa2/BBB+

2Q 2012 & 4Q 2012

24

 

(1)	On September 30, 2013, Liberty Interactive Corporation agreed to invest $300 million in Class A membership interests in exchange for a share of the dividends and the taxable loss generated by Solana. See Note 1 to our Annual Combined Financial Statements for more information.

(2)	Itochu Corporation holds 30% of the economic rights to each of Solaben 2 and Solaben 3.

(3)	Reflects the counterparty’s issuer credit ratings issued by S&P, Moody’s and Fitch.

Our assets and operations are organized into the following three business sectors:

Renewable Energy: Our renewable energy assets include two Concentrating Solar Power plants in the United States, Solana and Mojave, each with a gross capacity of 280 MW and located in Arizona and California, respectively. Solana is a party to a long-term power purchase agreement, or PPAs, with Arizona Public Service Company and Mojave is a party to a PPA with Pacific Gas & Electric Company. Solana reached its Commercial Operations Date, or COD, on October 9, 2013 and Mojave has substantially completed construction and we expect to enter the startup and production testing stage by May 2014, with expected COD by October 2014.

Additionally, we own an onshore wind farm in Uruguay, Palmatir, with a gross capacity of 50 MW. The wind farm is subject to a 20-year U.S. dollar-denominated PPA with a state-owned utility company in Uruguay. The construction of Palmatir is complete and COD is expected in May 2014.

Finally, Solaben 2 and Solaben 3 are two Concentrating Solar Power plants each with a gross capacity of 50 MW and located in Spain. Both projects have been in operation since mid-2012 and receive regulated revenues under the framework for renewable energy projects in Spain.

Conventional Power: Our conventional power asset consists of ACT, a 300 MW cogeneration plant in Mexico. ACT is a party to a 20-year take-or-pay contract with Petroleos Mexicanos S.A. de C.V., or Pemex, for the sale of electric power and steam. Pemex also supplies the natural gas required for the plant at no cost to ACT, which insulates the project from natural gas price variations.

Electric Transmission: Our electric transmission assets consist of (i): two lines in Peru, ATN and ATS, spanning a total of 931 miles; (ii) three lines in Chile, Quadra 1, Quadra 2 and Palmucho, spanning a total of

 

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87 miles; and (iii) an exchangeable preferred equity investment in ACBH, a subsidiary holding company of Abengoa that is engaged in the development, construction, investment and management of contracted concessions in Brazil, comprised mostly of transmission lines.

Peru. ATN and ATS are core lines in the Peruvian electric transmission system. Each line is subject to a U.S. dollar-denominated 30-year contract with the Ministry of Energy of the Government of Peru that is indexed to the U.S. Finished Goods Less Food and Energy Index. ATN reached COD in 2011 and ATS reached COD on January 17, 2014.

Chile. Quadra 1 and Quadra 2 are two electric transmission lines that are subject to a concession contract with Sierra Gorda SCM, a mining company owned by Sumitomo Corporation, Sumitomo Metal Mining and KGHM Polska Mietz. Quadra 1 and Quadra 2 have been in operation since December 2013 and January 2014, respectively. Quadra 1 reached COD in April 2014 and Quadra 2 reached COD in March 2014. The concession contract is denominated in U.S. dollars and has a remaining term of 21 years. Palmucho is a six-mile electric transmission line and substation subject to a private concession agreement with a utility, Endesa Chile, with a remaining term of 23 years. Palmucho reached COD in October 2007.

Brazil. In addition to the assets listed above, we own a preferred equity investment in ACBH, a subsidiary holding company of Abengoa that is engaged in the development, construction, investment and management of contracted concessions in Brazil, consisting mostly of transmission lines (see “—Our Operations—Electric Transmission—Exchangeable Preferred Equity Investment in Abengoa Concessoes Brasil Holding” for details on the transmission assets held by ACBH).

This preferred equity investment grants us the following rights:

 

•

During the five-year period commencing on July 1, 2014, we will receive, in four quarterly installments, a preferred dividend of $18.4 million per year.

 

•

Following the initial five-year period, we will have the option to (i) remain as preferred equity holder receiving the first $18.4 million in dividends per year that ACBH is able to distribute, or (ii) convert the preferred equity into ordinary shares of specific project companies owned by ACBH.

Our Growth Strategy

We intend to grow our cash available for distribution and, in turn, dividend per share, by optimizing the operations of our existing assets, achieving COD of our Mojave facility by October 2014 and by acquiring new contracted revenue-generating assets from Abengoa under the ROFO Agreement, and from parties other than Abengoa. Abengoa has informed us of its intention, which is reflected in the ROFO Agreement, for Abengoa Yield to serve as its primary vehicle for owning, managing and acquiring contracted assets in our primary geographies (North America, Chile, Peru, Uruguay, Brazil, Colombia and the European Union) and four assets to be mutually agreed in other selected regions. Abengoa will assist us in pursuing such acquisitions by presenting acquisition opportunities to us. In general, we expect to acquire only assets that are developed and operational, and we expect Abengoa to continue to pursue construction and development opportunities for its own account. Under the ROFO Agreement, Abengoa will not be obligated to offer or sell any of the Abengoa ROFO Assets to us by any date or at all. As a result, we do not know when, if ever, Abengoa will offer us any Abengoa ROFO Assets. In addition, in the event that Abengoa elects to sell such assets, Abengoa will not be required to accept any offer we make for any Abengoa ROFO Asset.

We will leverage the ability of Abengoa to develop, build and operate assets in our target sectors and secure contracted concessions that we expect to generate accretive growth for our shareholders once purchased by Abengoa Yield. We intend to use the following investment guidelines in evaluating prospective acquisitions in order to successfully execute our accretive growth strategy:

 

•

high quality offtakers, with long-term contracted revenue, ideally longer than 20 years;

 

•

project financing in place at each project;

 

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•

operations and maintenance contract in place at each project;

 

•

management and operational systems and processes at the Abengoa Yield level, while leveraging Abengoa’s support and capabilities;

 

•

focus on regions and countries that provide growth opportunities while balancing security and risk considerations, which regions and countries include the United States, Canada, Mexico, Chile, Peru, Uruguay, Brazil, Colombia and the European Union; and

 

•

preference for U.S. dollar-denominated revenues, in the absence of which, we will implement a cost-effective, ad-hoc hedging policy that will support stability of cash flows.

Abengoa has contracted assets with an equity book value of approximately $4.5 billion in its concession-type infrastructure activity, including the assets described in “—Our Current Operations.” A significant portion of these assets are currently in operation and Abengoa may elect to offer such assets for sale to us in the future. In addition, Abengoa has announced its intention to invest approximately $440 million in additional concession-type infrastructure assets per year from 2014. If these investments are made, they will further add to the pool of assets that Abengoa may elect to offer to sell to us in the future.

The ROFO Agreement will provide us with a right of first offer to acquire Abengoa’s contracted renewable energy, conventional power, electric transmission or water assets operating in our primary geographies (North America, Chile, Peru, Uruguay, Brazil, Colombia and the European Union) and four assets to be mutually agreed in other selected regions. The following table presents the projects that, based on their maturity stage and cash generation profile, we expect Abengoa to propose to us for evaluation for acquisition in 2015 and 2016:

 

Expected ROFO Assets

Type

Ownership

Location

Currency

Capacity

Status

Offtaker

Counterparty Credit Ratings(1)

COD/ Expected COD

Contract Years Left

2015

Cadonal

Renewable (wind)

100%

Uruguay

USD

50 MW

Construction

Uruguay

BBB-/Baa3/BBB-

1Q 2015

20

Solacor 1 & 2

Renewable (CSP)

74%(2)

Spain

Euro

2x50 MW

Operational

Spain

BBB-/Baa2/BBB+

2012

23

Shams

Renewable (CSP)

20%

U.A.E.

USD(3)

100 MW

Operational

Abu Dhabi

AA/Aa2/AA

3Q 2013

25

Honaine

Water

25.5%

Algeria

USD

7M ft3/day

Operational

Sonatrach

N/A

2012

23

2016

3T

Conventional Power

100%

Mexico

USD

220 MW

Construction

Several

N/A

4Q2016

20-25

ATN3

Transmission Line

40%

Peru

USD

220 Miles

Construction

Peru

BBB+/Baa2/BBB+

3Q 2016

30

Helioenergy 1 & 2

Renewable (CSP)

50%

Spain

Euro

2x50 MW

Operational

Spain

BBB-/Baa2/BBB+

2011

23

SPP1

Conventional Power

51%

Algeria

Euro

150 MW

Operational

Sonatrach

N/A

3Q 2011

22

 

(1)	Reflects the counterparty’s issuer credit ratings issued by S&P, Moody’s and Fitch.

(2)	Abengoa has the right to receive 83% on average of the cash available for future distribution from Solacor 1 & 2 due to having 100% of the subordinated debt of the project.

(3)	Shams’ revenues are denominated in United Arab Emirates dirham, which has been pegged to the U.S. dollar since 1997.

We expect that, pursuant to the ROFO Agreement, Abengoa will from time to time present us with acquisition opportunities that are expected to fulfill our investment guidelines. If Abengoa offers an Abengoa ROFO Asset to us, we will have 60 days to complete due diligence and negotiate the acquisition of the asset. If we do not agree to purchase the applicable asset after such period, Abengoa will be free to pursue the sale with

 

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other potential buyers. Under the ROFO Agreement, Abengoa will not be obligated to offer or sell any of the Abengoa ROFO Assets to us by any date or at all. As a result, we do not know when, if ever, Abengoa will offer any Abengoa ROFO Assets. In addition, in the event that Abengoa elects to sell such assets, Abengoa will not be required to accept any offer we make for any Abengoa ROFO Asset. Abengoa also may, following the completion of good-faith negotiations with us during the 60-day period mentioned above, choose to sell such assets to a third party or not to sell the assets at all. However, if we do not reach an agreement, any sale to a third party within 18 months following such 60-day period must be on terms and conditions generally no less favorable to Abengoa than those offered to us. After such 18-month period, the asset will cease to be an Abengoa ROFO Asset. We will pay Abengoa a fee of 1% of the equity purchase price of any Abengoa ROFO Asset that we acquire as consideration for Abengoa granting us the right of first offer.

In addition to the potential acquisition targets for 2015 and 2016 listed above, the following table presents some of the longer term opportunities that Abengoa may present to us for acquisition in the future:

 

Other Possible ROFO Assets		Type		Location		Capacity		Status
Palen		Renewable (CSP)		United States		250 MW		Development
Pahrump		Renewable (PV)		United States		90 MW		Development
Water SA(1)		Water		United States		50 million gallons/day		Development
Zapotillo		Water		Mexico		112 Miles		Pre-Construction
Chile Solar Tower		Renewable (CSP)		Chile		110 MW		Development
Leasing		Renewable (Wind)		Uruguay		70 MW		Pre-Construction
Manaus		Transmission Line		Brazil		364 Miles		Operational
Norte		Transmission Line		Brazil		1,476 Miles		Construction
ATE IV-VIII		Transmission Line		Brazil		354 Miles		Operational
ATE XVI-XXII		Transmission Line		Brazil		3,593 Miles		Pre-Construction
Ashalim		Renewable (CSP)		Israel		110 MW		Pre-Construction
Kaxu		Renewable (CSP)		South Africa		100 MW		Construction
Khi		Renewable (CSP)		South Africa		50 MW		Construction
Tenes		Water		Algeria		7M ft3/day		Construction
Skikda		Water		Algeria		3.5M ft3/day		Operational

 

(1)	Abengoa is currently in exclusive final stages of negotiation for award of this contract.

Our agreements with Abengoa will not prohibit Abengoa from acquiring or operating contracted assets that fulfill our principles. See “Risk Factors” and “Related Party Transactions—Project-Level Management and Administration Agreements” for further information.

Our Business Strategy

Our primary business strategy is to increase the cash dividends that we intend to pay to holders of our shares over time while ensuring the ongoing stability of our business. Our plan for executing this strategy includes the following key components:

Focus on contracted renewable energy, conventional power generation and electric transmission lines. We intend to focus on owning and operating these types of assets, for which we possess deep know-how, extensive experience and proven systems and management processes, as well as the critical mass to benefit from operating efficiencies and scale. We expect that this will allow us to maximize value and cash flow generation going forward. We intend to maintain a diversified portfolio in the future, as we believe these technologies will undergo significant growth in our targeted geographies.

Increase cash available for distribution and dividends by optimizing our existing assets. Some of our assets are newly operational and we believe that we can increase the cash flow generation of these assets through further management and optimization initiatives and, in some cases, through repowering. Additionally, once

 

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Mojave achieves COD, which is expected to occur by October 2014, we will have a new revenue-generating asset that we expect will result in a significant increase to our cash flow generation. Finally, our Palmatir facility has completed construction with COD expected in May 2014 and also is expected to generate increased cash flows. See “Risk Factors—Risks Related To Our Assets—Certain of our facilities are newly constructed and may not perform as expected.”

Increase cash available to grow our dividend per share through the acquisition of new assets in renewable energy, conventional power and electric transmission. We expect the ROFO Agreement with Abengoa will provide us with access to a large number of acquisition opportunities that will allow us to achieve accretive growth over the next few years. Abengoa expects to have over thirty contracted assets in our target sectors under construction or operation immediately following this offering and is developing many others. This, together with the fact that Abengoa acts as a greenfield developer, should allow us to access a large pipeline of contracted assets going forward. Additionally, we intend to analyze other potential acquisitions from third parties. We believe that our know-how and operating expertise in our key markets, together with a critical mass of assets in several geographic areas and the access to capital provided by being a listed company, will permit us to successfully realize our growth plans.

Increase available cash by expanding into water assets. We believe that contracted water assets, which include desalination plants, water treatment facilities and transportation facilities, constitute a high-growth market. Moreover, the water market offers attractive acquisition opportunities and is one in which Abengoa enjoys a strong market position. Accordingly, our target list of opportunities that we expect to be under the ROFO Agreement includes five water assets, two of which are in operation. We expect these assets to help us achieve growth and potentially achieve a critical mass if we acquire any of them from Abengoa pursuant to the ROFO Agreement.

Maintain geographic diversification across two principal geographic areas. Our focus on two main markets, North America and South America, helps to ensure exposure to markets in which we believe the renewable energy, conventional power and electric transmission sectors will continue growing significantly. We believe that a strategic exposure to international markets will allow us to pursue greater growth opportunities and achieve higher returns than if we only focus on assets located in the United States.

Enjoy a shareholder-oriented financial strategy. We intend to focus on maximizing the cash generation potential of the assets currently held in our portfolio. With cash received from our contracted concessions, we intend to distribute quarterly dividends of substantially all cash available following the deduction of a provision to allow for the prudent management of our business. Additionally, as our controlling shareholder, Abengoa has a strategic interest to create a vehicle that focuses exclusively on cash flow generation from contracted assets and this offering is a key component of this strategy. Accordingly, Abengoa, as our controlling shareholder, will seek to actively support our strategy to maximize dividend distribution, subject to the boundaries of prudent management.

Foster a low-risk approach. We intend to maintain, over time, a portfolio of contracted assets with a low-risk profile due to creditworthy offtake counterparties, long-term contracted revenues, over 90% of cash available for distribution in or indexed to the U.S. dollar and proven technologies in which we have deep expertise and significant experience, located in countries where we believe conditions to be stable and safe.

Additionally, our policies and management systems include thorough risk analysis and risk management processes that we apply whenever we acquire an asset, and which we review monthly throughout the life of the asset. Our policy is to insure all of our assets whenever economically feasible.

Maintain financial strength and flexibility. We intend to maintain a solid financial position through a combination of cash on hand and credit facilities. This prudent strategy provides the required flexibility to maintain our dividend throughout the year in spite of the inherent seasonality of our business. Additionally, conservative cash management may help us to mitigate any unexpected downturns that reduce our cash flow generation.

 

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Our Competitive Strengths

We believe that we are well positioned to execute our business strategies because of the following competitive strengths:

Stable and predictable long-term U.S. and international cash flows with attractive tax profiles. We believe that our young asset portfolio has a highly stable, predictable cash flow profile consisting of predominantly long-life electric power generation and electric transmission assets that generate revenues under long-term fixed priced contracts or pursuant to regulated rates with creditworthy counterparties and with long-term O&M contracts in place. Additionally, our facilities have minimal to no fuel risk. The offtake agreements for our assets have a weighted average remaining duration of approximately 26 years (based on the relevant technical indicator by type of asset), providing long-term cash flow stability. Additionally, our business strategy and hedging policy is intended to ensure a minimum of 90% of cash available for distribution in or indexed to the U.S. dollar. Furthermore, due to the fact that we are a UK resident company we should benefit from a more favorable treatment than would apply if we were a corporation in the United States when receiving dividends from our subsidiaries that hold our international assets because they should generally be exempt from UK taxation due to the UK’s distribution exemption. Based on our current portfolio of assets, which include renewable assets that benefit from an accelerated tax depreciation schedule, and current tax regulations in the jurisdictions in which we operate, we do not expect to pay significant income tax for a period of at least ten years due to existing NOLs, except for ACT in Mexico, where we do not expect to pay significant income taxes until the fifth or sixth year after this offering once we use existing NOLs. See “Risk Factors—Risks Related to Taxation—Our future tax liability may be greater than expected if we do not utilize Net Operating Losses, or NOLs, sufficient to offset our taxable income,” “Risk Factors—Risks Related to Taxation—Our ability to use U.S. NOLs to offset future income may be limited,” and “Risk Factors—Risks Related to Taxation—Changes in our tax position can significantly affect our reported earnings and cash flows.” Furthermore, based on our current portfolio of assets, we believe that there is minimal repatriation risk in all of the jurisdictions in which we operate. See “Risk Factors—Risks Related to Our Business and the Markets in Which We Operate—We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties.”

Experienced and incentivized management team. Abengoa Yield’s management team has significant and valuable expertise in developing, financing, operating and managing renewable energy, conventional power and electric transmission assets. Their financial and tax management skills will help us achieve our financial targets and continue to grow on a cash accretive basis over the medium- to long-term. Additionally, we intend to encourage our executives to ensure that they focus on cash generation and long-term value creation for our shareholders.

Our relationship and our agreements with Abengoa. We believe our relationship with Abengoa, including Abengoa’s expressed intention to maintain a controlling stake in us, provides us with significant benefits, including managerial and operational expertise and a sustainable source of future growth opportunities based on Abengoa’s greenfield development capabilities and construction expertise. Moreover, Abengoa provides a significant pipeline of opportunities in our targeted sectors and geographies. Abengoa usually targets an internal rate of return for its projects that is higher than the expected cost of equity of Abengoa Yield, thus both parties could benefit from a contribution of assets from Abengoa to us.

Specifically, the various agreements we have in place with Abengoa allow us to access:

 

•

Abengoa Management and Operational Expertise. We will monitor and oversee operations in each asset and will continue implementing Abengoa standards required in key areas like reporting, management, quality, health and safety and compliance.

 

•

Abengoa Asset Development Track Record. Over the last ten years, Abengoa has successfully developed approximately 2,000 MW of renewable power assets, 673 MW of conventional power plants and over 7,700 miles of electric transmission lines.

 

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•

Abengoa Financing Experience. Over the last ten years, Abengoa has financed through non-recourse project financing more than $15 billion worth of projects, mostly in North America and South America as well as in Europe, Africa and the Middle East. We expect that we will realize significant benefits from Abengoa’s financing and structuring expertise, as well as its relationships with financial institutions and other lenders.

 

•

Abengoa Construction Expertise. Abengoa has built approximately 10,000 MW of power generation facilities (renewable and conventional), over 21,800 miles of electric transmission lines and water desalination plants with capacity in excess of 329 million cubic feet per day, as well as many infrastructure assets in other markets. Many of these projects have been built for third parties pursuant to the standards of these third parties. Abengoa was recently ranked by Engineering News Record as the largest international power facility contractor (previously ranked among the top three during the preceding five years) and the largest electric transmission contractor for the seventh consecutive year.

 

•

Abengoa Operation and Maintenance Expertise. Abengoa currently provides operation and maintenance services to renewable energy plants with an aggregate capacity of approximately 1,000 MW, conventional power plants with an aggregate capacity of approximately 1,000 MW, approximately 7,700 miles of electric transmission lines and water treatment facilities with an aggregate capacity of 21.7 million of cubic feet per day.

 

•

Abengoa Technical Expertise in Our Key Technologies and Presence in Our Key Geographies. Abengoa currently has deep know-how and expertise in the technologies that we use in our assets and has an important presence and experience in our key geographies.

Multi-technology portfolio of assets that is strategically positioned. Our portfolio of assets uses technologies that we expect to benefit from long-term trends in the electricity sector. Our renewable energy generation assets generate low or no emissions and serve markets where we expect growth in demand in the future. Additionally, our electric transmission lines connect electricity systems to key areas in their respective markets and we expect significant electric transmission investment in our geographies. As a result, we believe that we may be able to benefit from opportunities to repower some of our assets during the lives of our existing PPAs and to extend the terms of those contracts after current PPAs expire. We expect our well-diversified portfolio of assets by technology and geography to maintain cash flow stability.

Our Operations

Revenues

Our revenues for the years ended December 31, 2013 and 2012 amounted to $211 million and $107 million, respectively.

Our total revenue in North America for the years ended December 31, 2013 and 2012 amounted to $114 million and $20 million, respectively. Our total revenues in South America for the years ended December 31, 2013 and 2012 amounted to $25 million and $17 million, respectively. Our total revenue in Europe for the years ended December 31, 2013 and 2012 amounted to $72 million and $28 million, respectively.

Our total revenue from renewable energy for the years ended December 31, 2013 and 2012 amounted to $83 million and $28 million, respectively. Our total revenues from conventional power for the years ended December 31, 2013 and 2012 amounted to $103 million and $20 million, respectively. Our total revenue from electric transmission lines for the years ended December 31, 2013 and 2012 amounted to $25 million and $17 million, respectively.

 

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Renewable energy

The following table presents our renewable energy assets:

 

Asset

Type

Location

Capacity

Status

Offtaker

Currency

Counterparty Credit Ratings(1)

COD/ Expected COD

Contract Years Remaining

Solana

Solar

Arizona

280 MW

Operational

APS

USD

A-/A3/BBB+

4Q 2013

29

Mojave

Solar

California

280 MW

Startup and Production Testing

PG&E

USD

BBB/A3/BBB+

4Q 2014

25

Palmatir

Wind

Uruguay

50 MW

Startup and Production Testing

Uruguay

USD

BBB-/Baa3/BBB-

2Q 2014

20

Solaben 2

Solar

Spain

50MW

Operational

Spain

Euro

BBB-/Baa2/BBB+

2Q 2012

24

Solaben 3

Solar

Spain

50 MW

Operational

Spain

Euro

BBB-/Baa2/BBB+

4Q 2012

24

 

(1)	Reflects counterparty’s issuer credit ratings issued by S&P, Moody’s and Fitch.

Solana

Overview. The Solana Solar Project, or Solana, is a 250 MW net (280 MW gross) solar electric generation facility located in Maricopa County, Arizona, approximately 70 miles southwest of Phoenix. Arizona Solar One LLC, or Arizona Solar, owns the Solana project. Solana includes a 22-mile 230kV transmission line and a molten salt thermal energy storage system. The construction of Solana commenced in December 2010 and Solana reached COD on October 9, 2013.

Solana relies on a conventional parabolic trough Concentrating Solar Power system to generate electricity. The parabolic trough technology has been utilized for over 25 years at the Solar Electric Generating Systems, SEGS, facilities located in the Mojave Desert in Southern California. Abengoa’s thirteen 50 MW parabolic trough facilities in Spain, including Solaben 2 and Solaben 3, have also used this technology since 2010. Solana produces electricity by means of an integrated process using solar energy to heat a synthetic petroleum-based fluid in a closed-loop system that, in turn, heats water to create steam to drive a conventional steam turbine. Solana employs a two-tank molten salt thermal energy storage system that provides an additional six hours of solar dispatchability to increase its efficiency. This type of storage system has been in operation in several commercial plants in Spain since March 2009 and is also similar to the Abengoa’s demonstration plant at its Solucar Platform in Seville that has been in operation since February 2009.

Abengoa Solar One Holdings, Inc., the entity through which we indirectly invest in Solana, is not expected to pay U.S. federal income taxes for the foreseeable future due to the relevant NOLs and NOL carryforwards generated by the application of tax incentives established in the United States, in particular MACRS accelerated depreciation.

Power Purchase Agreement. Solana has a 30-year, fixed-price PPA with Arizona Public Service Company, or APS, for at least 110% of the output of the project. The PPA provides for the sale of electricity at a fixed base price approved by the Arizona Corporation Commission with annual increases of 1.84% per year. The PPA includes on-going performance obligations and is intended to provide Arizona Solar with consistent and predictable monthly revenues that are sufficient to cover operating costs and debt service and to earn an equity return.

APS is a load serving utility based in Phoenix, Arizona. APS has senior unsecured credit ratings of A3 from Moody’s, A- from S&P and BBB+ from Fitch.

The PPA was initially executed in February 2008 and received final approval from the Arizona Corporation Commission in December 2008. The PPA was most recently amended and restated in December 2010. The PPA expires on October 9, 2043.

 

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Engineering, Procurement and Construction Agreements. The construction of Solana was carried out by subsidiaries of Abengoa under an arm’s-length, fixed-price and date-certain engineering, procurement and construction contract, or an EPC contract, that was executed on December 20, 2010. Abengoa completed construction of Solana on October 9, 2013. The EPC contract contains warranties that protect Arizona Solar against defects in design, materials and workmanship for one year after completion and provides a three-year performance guarantee for the benefit of financing parties. Abengoa constructed Solana using equipment from leading suppliers, including two 140 MW (gross) steam turbines supplied by Siemens.

Transmission and Interconnection. Solana interconnects to the existing 230kV APS panda substation via a newly-constructed 230kV transmission line between the facility switchyard and the APS panda substation. A large generator interconnection agreement, or LGIA, was executed with APS to govern the interconnection. The Federal Energy Regulatory Commission, or FERC, approved the LGIA on August 31, 2010.

Operations & Maintenance. ASI Operations Inc., or ASI Operations, a wholly-owned subsidiary of Abengoa, provides operations and maintenance, or O&M, services for Solana. The senior staff of ASI Operations has experience managing and operating SEGS plants. Solana also benefits from Abengoa’s overall experience operating 781 MW of solar projects worldwide as of December 31, 2013. ASI Operations has agreed to operate the facility in accordance with prudent utility practices, to ensure compliance with all applicable government and agency permits, licenses, approvals and PPA terms, and to assist Arizona Solar in connection with the procurement of all necessary support and ancillary services. The Operations and Maintenance Agreement, or an O&M agreement, between ASI Operations and Arizona Solar is a 30-year cost-reimbursable contract with a fixed fee of $480,000 per year, which is indexed to U.S. CPI, and a variable fee that Arizona Solar will pay in periods when the project’s annual net operating profits exceed the target annual net operating profit. We expect that the variable fee will provide ASI Operations with a significant long-term interest in the success of the project, which we expect will align its interests with those of Arizona Solar.

Project Level Financing. Arizona Solar executed a loan guarantee agreement with the DOE on December 20, 2010 to provide a loan guarantee in connection with a two-tranche loan of approximately $1.445 billion from the Federal Financing Bank, or FFB. The FFB loan has a short-term tranche that Arizona Solar has repaid with the proceeds from the Investment Tax Credit Cash Grant, or ITC Cash Grant, that the project has received from the U.S. Treasury. The principal balance of this tranche was $450 million as of December 31, 2013. The FFB loan has a long-term tranche payable over a 29-year term with the cash generated by the project. The principal balance of this tranche was $968 million as of December 31, 2013. Each tranche is denominated in U.S. dollars. The FFB loan has a fixed average interest rate of 3.56%.

The financing arrangement permits dividend distributions on a semi-annual basis after the first principal repayment of the long-term tranche, as long as the debt service coverage ratio for the previous four fiscal quarters is at least 1.2x and the projected debt service coverage ratio for the next four fiscal quarters is at least 1.2x.

Partnerships. On September 30, 2013, Abengoa entered into an agreement with Liberty Interactive Corporation, or Liberty, pursuant to which Liberty agreed to invest $300 million in Class A membership interests of ASO Holdings Company LLC, the parent of Arizona Solar, in exchange for a share of the dividends and the taxable loss generated by the project. See Note 1 to our Annual Combined Financial Statements for more information. All figures in this prospectus take into account Liberty’s share of dividends. Abengoa Yield indirectly owns 100% of the Class B membership interests in ASO Holdings Company LLC.

Mojave

Overview. The Mojave Solar Project, or Mojave, is a 250 MW net (280 MW gross) solar electric generation facility located in San Bernardino County, California, approximately 100 miles northeast of Los Angeles. Abengoa commenced construction of Mojave in September 2011. Mojave has substantially finished construction and we expect it to enter the start-up and production testing stage by May 2014. We expect that the project will reach COD by October 2014. Mojave Solar LLC, or Mojave Solar, owns the Mojave project.

 

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Mojave relies on a conventional parabolic trough Concentrating Solar Power system to generate electricity and is similar to Solana with respect to technology and general design. The main difference between Solana and Mojave is that Mojave does not have a molten salt storage system, as the offtaker did not require one.

Mojave’s total project investment is expected to be approximately $1,540 million, of which approximately $159 million was pending as of December 31, 2013. $40 million of the $159 million will be paid with equity contributions from a restricted account with funds already available and the balance of the $159 million will be paid from the DOE guaranteed loan.

Mojave is not expected to pay federal income tax for the foreseeable future due to the relevant NOLs and NOL carryforwards generated by the application of tax incentives established in the United States, in particular MACRS accelerated depreciation.

Power Purchase Agreement. Mojave has a 25-year, fixed-price PPA with Pacific Gas & Electric Company, or PG&E, for 100% of the output of Mojave. The PPA will begin on COD. The PPA provides for the sale of electricity at a fixed base price with seasonal adjustments and adjustments for time of delivery. Mojave Solar can deliver and receive payment for at least 110% of contracted capacity under the PPA. The PPA includes on-going performance obligations of up to 140% of annual contract quantity (approximately 617 GWh) in any 24-month period. The PPA is intended to provide Mojave Solar with consistent and predictable monthly revenues sufficient to cover operating costs and debt service and to earn an equity return.

PG&E, a utility based in San Francisco, is one of the largest integrated natural gas and electric utilities in the United States. PG&E has senior unsecured credit ratings of A3 from Moody’s, BBB from S&P and BBB+ from Fitch.

Engineering, Procurement and Construction Agreement. The construction of Mojave is being carried out by subsidiaries of Abengoa, or the contractor, under an arm’s-length, fixed-price EPC contract that was executed on September 12, 2010. Mojave issued a “full notice to proceed” on March 7, 2012. We expect Mojave to achieve COD by October 2014.

The EPC contract includes a one-year warranty by the EPC contractor for defects among other typical equipment guarantees. Additionally, the EPC contractor provides a three-year performance guarantee linked to energy production. Mojave’s key equipment has been supplied by leading companies, including two twin turbines from General Electric.

Transmission and Interconnection. Mojave interconnects to the existing transmission system through Southern California Edison, or SCE, transmission lines. The interconnection to SCE’s existing 220kV Kramer-Coolwater transmission line at Kramer substation is essentially complete and the existing transmission line will allow the project to begin to deliver output to PG&E. However, additional upgrades to the network are required to achieve the full contractual requirements in the PPA and resource adequacy. The additional upgrades, which are under the responsibility of SCE, require the construction of a new 59-mile transmission line between Coolwater and Lugo, which is scheduled to be completed in 2018. Failure to meet the schedule for such upgrades may temporarily block dividend distributions and may cause the project to suffer penalties for failure to achieve resource adequacy.

Operations & Maintenance. ASI Operations provides O&M services for Mojave. Under the terms of the O&M agreement between ASI Operations and Mojave Solar, ASI Operations has agreed to operate the facility in accordance with prudent utility practices, to ensure compliance with all applicable government and agency permits, licenses, approvals and PPA terms, and to assist Mojave Solar in connection with the procurement of all necessary support and ancillary services. The O&M agreement is a cost-reimbursable contract with a combination of fixed and variable fees. The fixed fee is $500,000 per year starting in the second year of full operations and will increase by 2.5% per year. The fixed fee will be $1.0 million during the start-up year and will be $750,000 during the first year of full operations. Mojave Solar will pay the variable fee in periods when the

 

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project’s annual net operating profits exceed the target annual net operating profit. We expect that the variable fee will provide ASI Operations with a significant long-term interest in the success of the project, which we expect will align its interests with those of Mojave Solar.

Project Level Financing. Mojave Solar executed a Loan Guarantee Agreement with the DOE on September 12, 2011 to provide a loan guarantee in connection with a two-tranche FFB loan of approximately $1.202 billion. The FFB loan has a short-term tranche that Mojave Solar expects to repay with the proceeds from the ITC Cash Grant that the project expects to receive from the U.S. Treasury. The principal balance of this tranche was $229 million as of December 31, 2013. The FFB loan has a long-term tranche payable over a 25-year term with the cash generated by the project. The principal balance of this tranche was $819 million as of December 31, 2013. Each tranche is denominated in U.S. dollars. The FFB loan has an average fixed interest rate of 2.75% and each disbursement is linked to the Treasury bond with the maturity of that disbursement.

The financing arrangement permits dividend distributions on a semi-annual basis after the first principal repayment of the long-term tranche, as long as the debt service coverage ratio for the previous four fiscal quarters is at least 1.2x and the projected debt service coverage ratio for the next four fiscal quarters is at least 1.2x.

Partnerships. We own 100% of the equity interests in the Mojave project.

Palmatir

Overview. Palmatir is an on-shore wind farm facility in Uruguay with nominal installed capacity of 50 MW. Palmatir has 25 wind turbines and each turbine has a nominal capacity of 2 MW. UTE, Uruguay’s state-owned electricity company, has agreed to purchase all energy produced by Palmatir pursuant to a 20-year PPA. Construction is complete and we expect to reach COD by May 2014.

The wind farm is located in Tacuarembo, 170 miles north of the city of Montevideo. Gamesa, a global leader in the manufacture and maintenance of wind turbines, supplied the turbines from its U.S. subsidiary.

Palmatir is not expected to pay significant corporate taxes in the foreseeable future due to the specific tax exemptions established by the Uruguayan government for renewable assets.

Power Purchase Agreement. Palmatir initially signed a PPA with UTE on September 14, 2011 for 100% of the electricity produced. The PPA requires us to connect Palmatir to UTE’s electrical grid by September 2014. After Palmatir is connected to the electrical grid, UTE will purchase all electricity produced during the 20-year term of the PPA. UTE will pay a fixed tariff under the PPA, which is denominated in U.S. dollars and will be partially adjusted in January of each year based on a formula referring to U.S. CPI and the Uruguay’s Indice de Precios al Productor de Productos Nacionales and the applicable UYU/USD exchange rate.

Uruguay has senior unsecured credit ratings of Baa3 from Moody’s, BBB- from S&P and BBB- from Fitch.

Engineering, Procurement and Construction Agreement. The construction of Palmatir was carried out by subsidiaries of Abengoa under a fixed price EPC contract that includes customary guarantees, such as a one-year warranty by the EPC contractor for defects plus a two-year performance guarantee linked to energy production.

Transmission and Interconnection. Palmatir connects to UTE’s grid at the Bonete substation via a newly-built 21-mile overhead line.

Operations & Maintenance. Palmatir signed an agreement with Epartir, a subsidiary of Omega that is in turn a wholly-owned Abengoa subsidiary, for the provision of O&M services for a 20-year term. The O&M agreement covers scheduled and unscheduled turbine maintenance, a supply of spare parts, wind farm monitoring and reporting services. The O&M agreement contains customary guarantees, such as two-year guarantee and repairs. Epartir subcontracted with the wind turbine manufacturer, Gamesa, for the wind turbine O&M services. According to Gamesa, it has more than 20,800 MW of installed wind turbines and operates and maintains over 13,600 MW of wind turbines.

 

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Project Level Financing. Palmatir signed a financing agreement on April 11, 2013 for a 20-year loan in two tranches in connection with the project. Each tranche is denominated in U.S. dollars. The first tranche is a $73 million loan from the U.S. Export Import Bank with a fixed interest rate of 3.11%. The second tranche is a $40 million loan from the Inter-American Development Bank with a floating interest rate of LIBOR plus 4.125%. The project hedged 80% of the floating rate loan with a swap at a rate of 2.22% with the financing bank. The combined principal balance of both tranches as of December 31, 2013 was $107 million.

Cash distributions are permissible every six months subject to a historical debt service coverage ratio for the previous twelve-month period and a projected debt service coverage ratio for the following twelve-month period of at least 1.25x.

Solaben 2 and Solaben 3

Overview. The Solaben 2 and Solaben 3 projects are two 50 MW Concentrating Solar Power facilities and are part of Abengoa’s Extremadura Solar Complex. The Extremadura Solar Complex consists of four Concentrating Solar Power plants, Solaben 1, Solaben 2, Solaben 3 and Solaben 6, and is located in the municipality of Logrosan, Spain. Abengoa commenced construction of Solaben 2 and Solaben 3 in August 2010. Solaben 2 reached COD in June 2012 and Solaben 3 reached COD in October 2012. Solaben Electricidad Dos, S.A., or SE2, owns Solaben 2 and Solaben Electricidad Tres, S.A., or SE3, owns Solaben 3.

Solaben 2 and Solaben 3 each rely on a conventional parabolic trough Concentrating Solar Power system to generate electricity. The technology is similar to the technology used at Solana, Mojave and the eleven other 50 MW Concentrating Solar Power plants that Abengoa owns in Spain.

According to the tax accelerated depreciation regime established by the Spanish Corporate Income Tax Act, Solaben 2 and Solaben 3 are not expected to pay significant income taxes in the next ten years.

Regulation. Renewable energy projects in Spain sell the power they produce into the wholesale electricity market and receive additional payments from the Comision Nacional de los Mercados y de la Competencia, or CNMC, the Spanish state-owned regulator. According to the Electricity Sector Law, the addition of expected revenues from the wholesale market and from regulated payments should allow all renewable energy installations to obtain a project internal rate of return of 7.5%. This return can be reviewed by the regulator and government every six years, based on the cost of Spanish long-term sovereign bonds and a 300 basis points spread.

Concentrating Solar Power plants receive, in addition to the revenues from the sale of electricity in the market, two monthly payments in order to achieve the specific rate of return. These payments are comprised of: (i) a fixed monthly payment based on installed capacity and (ii) a variable payment based on net electricity produced. There is a maximum number of production hours per year beyond which no variable payment is received. The regulation also includes a minimum number of yearly hours of generation, under which the plant would receive no regulated payments and another higher threshold below which regulated payments would be reduced for a certain year. Those numbers are 35% and 60% of the maximum yearly hours, respectively. We expect that a plant would fail to achieve these thresholds only in cases of major breakdowns.

Engineering, Procurement and Construction Agreement. The construction of Solaben 2 and Solaben 3 was carried out by subsidiaries of Abengoa under an arm’s-length, fixed-price and date-certain EPC contract executed on December 16, 2010. The EPC contract provides a three-year performance guarantee by the EPC contractor for the benefit of financing parties starting six months after the applicable COD.

Transmission and Interconnection. Solaben 2 and Solaben 3, together with two other Abengoa Solaben projects and three plants owned by other companies, are connected to the electrical grid via common interconnection facilities that were jointly developed and are jointly owned. The interconnection facilities connect Solaben 2 and Solaben 3 from the SET Mesa de la Copa substation, which is located next to the Solaben

 

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projects, to the Valdecaballeros substation. The installation consists of a nodal transformer substation 220/400kV with a capacity of 600 MVA at SET Mesa de la Copa and a transmission line at 400kV of about 12 miles, which connect the nodal substation with a post of 400kV in the Valdecaballeros substation.

Spain has senior unsecured credit ratings of BBB- from S&P, Baa2 from Moody’s and BBB+ from Fitch.

Operations & Maintenance. Abengoa Solar Espana, S.A., or ASE, is the contractor for O&M services at Solaben 2 and Solaben 3. ASE has operated Concentrating Solar Power plants since 2007 and currently operates 681 MW of installed capacity, including Solaben 2 and Solaben 3, in four solar complexes across the south of Spain. ASE has agreed to operate the facility in accordance with prudent utility practices, ensure compliance with all applicable government and agency permits, licenses and approvals, and feed-in tariff terms, and to assist Solaben 2 and Solaben 3 in connection with the procurement of all necessary support and ancillary services.

Each O&M agreement is a 20-year, all-in contract that expires on the 20^th anniversary of the COD. Each contract provides for the payment of a fixed fee of €3.5 million for the equivalent of 75% of the annual targeted output in the O&M agreement and a variable fee thereafter equivalent to approximately €39 per MWh until 100% of the target output is reached and €90 per MWh for any production above 100%. All amounts are indexed annually to Spanish CPI.

Project Level Financing. SE2 and SE3 each entered into a 20-year loan agreement with a syndicate of banks formed by the Bank of Tokyo-Mitsubishi, Mizuho, HSBC and Sumitomo Mitsui Banking Corporation on December 16, 2010. Each loan is denominated in euro. The loan for Solaben 2 was for €169.3 million and the loan for Solaben 3 was for €171.5 million. The banks providing these loans obtained commercial and political risk insurance from Nippon Export and Investment Insurance, which allowed for lower financing costs. The interest rate for each loan is a floating rate based on EURIBOR plus a margin of 1.5%. Each loan was initially 80% hedged with the same banks providing the financing. The hedge was structured 50% through a swap set at approximately 3.7% and 50% through a cap with a 3.75% strike. In November 2013, SE2 and SE3 hedged through 2017 the remaining 20% exposure through a cap with a 0.75% strike.

The outstanding amount of these loans as of December 31, 2013 was €164 million for Solaben 2 and €167 million for Solaben 3.

The financing arrangements permit cash distribution to shareholders once per year if the audited financials for the prior fiscal year indicate a debt service coverage ratio of at least 1.10x.

Partnerships. Itochu Corporation, a Japanese trading company, purchased a 30% stake in the economic rights of each of Solaben 2 and Solaben 3 in December 2010.

Conventional Power

The following table provides an overview of our sole conventional power asset:

 

Asset

Location

Capacity

Status

Currency

Offtaker

Offtaker Credit Rating(1)

COD

Contract Years Remaining

ACT

Mexico

300 MW

Operational

USD

Pemex

BBB+/Baa1/BBB+

2Q 2013

19

 

(1)	Reflects the counterparty’s issuer credit ratings issued by S&P, Moody’s and Fitch.

Abengoa Cogeneracion Tabasco

Overview. Abengoa Cogeneracion Tabasco, or the ACT Plant, is a gas-fired cogeneration facility located inside the Nuevo Pemex Gas Processing Facility near the city of Villahermosa in the State of Tabasco, Mexico. It has a rated capacity of approximately 300 MW and between 550 and 800 metric tons per hour of steam. The plant includes a substation and an approximately 52 mile and 115 kilowatt transmission line. Abengoa commenced construction of the ACT Plant in October 2009 and it reached COD on April 1, 2013. Abengoa Cogeneracion Tabasco, S. de R.L. de C.V., or Abengoa Cogeneracion Tabasco, owns the ACT Plant.

 

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The ACT Plant utilizes mature and proven gas combustion turbines and heat recovery technology. Specifically, the ACT Plant utilizes two GE Power & Water “F” technology natural gas-fired combustion turbines and two Cerrey, S.A. de C.V., or Cerrey, heat recovery steam generators. According to GE, as of May 2013, GE Power & Water has supplied or received orders for more than 10,000 gas turbines, representing over 600,000 MW of installed capacity. As of May 2013, GE’s “F” technology gas turbines have accumulated over 47 million combined operating hours worldwide. Cerrey designs, manufactures, installs and maintains steam generating systems.

ACT is not expected to pay significant income taxes until the fifth or sixth year after this offering due to the NOLs generated during the construction phase.

Conversion Services Agreement. On September 18, 2009, ACT entered into the Pemex Conversion Services Agreement, or the Pemex CSA, with Petroleos Mexicanos, or Pemex, under which ACT is required to sell all of the plant’s thermal and electrical output to Pemex. The Pemex CSA has an initial term of 20 years from the in-service date and will expire on March 31, 2033. The parties may mutually extend the Pemex CSA for an additional 20-year period. The Pemex CSA requires Pemex to supply the facility, free of charge, with the fuel and water necessary to operate the ACT Plant and the latter has to produce electrical energy and steam requested by Pemex based on the expected levels of efficiency. The Pemex CSA is denominated in U.S. dollars. The price is fixed and will be adjusted annually, part of it according to inflation and part according to a mechanism agreed in the contract that on average over the life of the contract reflects expected inflation.

Pemex has a corporate credit rating of BBB+ by S&P, Baa1 by Moody’s and BBB+ by Fitch.

Engineering, Procurement and Construction Agreement. The construction of the ACT Plant was carried out by subsidiaries of Abengoa, which were responsible for the design, engineering, equipment procurement and construction under a turnkey EPC contract. CFE, Mexico’s Federal Electricity Commission and Pemex supervised the engineering, procurement and construction work. Under the applicable EPC contract guarantee, an affiliate of Abengoa will continue to perform works for the project for warranty repairs during the applicable warranty period.

Transmission and Interconnection. The Transferred Transmission Line that connects the ACT Plant to the CFE transmission grid system includes seven outgoing lines connected to the Cactus Switcheo substation. On April 1, 2013, pursuant to the terms of the Pemex CSA and as required by Mexican laws and regulations, Abengoa Cogeneracion Tabasco transferred ownership of the Transferred Transmission Line and the Cactus Switcheo substation to the CFE for no consideration.

Operations & Maintenance. GE International provides services for the maintenance, service and repair of the gas turbines as well as certain equipment, parts, materials, supplies, components, engineering support test services and inspection and repair services. GE International, an indirect subsidiary of GE, is one of the world’s largest third-party providers of operation and maintenance services to simple and combined-cycle combustion turbine facilities with over 25 years of experience. According to GE International, it had maintenance agreements covering almost 2,200 units on approximately 750 customer sites in seventy-seven countries with capacity over 250,000 MW as of April 2013.

In addition, NAES Mexico, S. de R.L. de C.V., or NAES, is responsible for the O&M of the ACT Plant. NAES has experience operating 173 power-generating facilities in North America and eighteen facilities in Central and South America, including four facilities utilizing GE “F” turbine technology in Mexico as of May 2013, according to NAES. The O&M agreement with NAES expires upon the expiration of the Pemex CSA, although we may cancel it after five years with no penalty. Abengoa Cogeneracion Tabasco pays NAES for its reimbursable costs, operating costs and a $230,000 annual management fee.

 

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Project Level Financing. On December 19, 2013, Abengoa Cogeneracion Tabasco signed a $680 million senior loan agreement with a syndicate of banks led by Banco Santander, Banobras and Credit Agricole Corporate & Investment Bank. Each tranche of the loan is denominated in U.S. dollars. The financing consists of a $333 million tranche and a $327 million tranche plus an additional $20 million for the issuance of a letter of credit. No repayment of principal has occurred as of the date of this prospectus.

The first tranche has a 10-year maturity, the second tranche has an 18-year maturity and the letter of credit may be convertible into additional principal that will be added to the first tranche. The interest rate on each tranche is a floating rate based on the three-month LIBOR plus a margin of 3.0% until December 2018, 3.5% from January 2019 to December 2023 and 3.75% from January 2024 to December 2031. The senior loan agreement requires Abengoa Cogeneracion Tabasco to hedge the interest rate for a minimum amount of 75% of the outstanding debt amount during at least 75% of the debt term. In January 2014, ACT closed a swap for a notional amount of $322.5 million at a rate of 3.53% and the remaining $172 million was closed in early April 2014 at a rate of 2.77%.

The senior loan agreement permits cash distributions to shareholders after six months provided that the debt service coverage ratio is at least 1.2x, or at any time provided that the last four quarters had a debt service coverage ratio of at least 1.2x.

Partnerships. After the acquisition of General Electric’s interests in ACT on March 21, 2014, we owned all of the shares of ACT except for two ordinary shares, which represent less than 0.01% of the total capital of ACT. The other ordinary shares are owned by Abengoa subsidiaries.

Electric Transmission

The following table provides an overview of our electric transmission assets:

 

Asset

Location

Length

Status

Currency

Offtaker

Counterparty Credit Ratings(1)

COD/ Expected COD

Contract Years Remaining

ATN

Peru

362 miles

Operational

USD

Peru

BBB+/Baa2/BBB+

1Q 2011

27

ATS

Peru

569 miles

Operational

USD

Peru

BBB+/Baa2/BBB+

1Q 2014

30

Quadra 1&2

Chile

81 miles

Pre-Operation/ Operational

USD

Sierra Gorda

N/A

2Q 2014/ 1Q 2014

21

Palmucho

Chile

6 miles

Operational

USD

Endesa Chile

BBB+/Baa2/BBB+

4Q 2007

23

 

(1)	Reflects counterparty’s issuer credit ratings issued by S&P, Moody’s and Fitch.

In addition to the assets listed above, we own an exchangeable preferred equity investment in ACBH, which is a subsidiary of Abengoa that holds entities involved in the development and construction of contracted assets, which are substantially all electric transmission lines, in Brazil. This investment is described further below.

Abengoa Transmision Norte

Overview. Abengoa Transmision Norte, or the ATN Project, in Peru is part of the Guaranteed Transmission System, or Sistema Garantizado de Transmision, SGT, and is comprised of the following facilities:

 

(i)

the approximately 356 mile, 220kV line from Carhuamayo-Paragsha-Conococha-Kiman-Ayllu-Cajamarca Norte;

 

(ii)

the 4.3 mile, 138kV link between the existing Huallanca substation and Kiman Ayllu substations;

 

(iii)

the 1.9 mile, 138kV link between the 138kV Carhuamayo substation and the 220kV Carhuamayo substation;

 

(iv)

the new Conococha and Kiman Ayllu substations; and

 

(v)

the expansion of the Cajamarca Norte, 220kV Carhuamayo, 138kV Carhuamayo and 220kV Paragsha substations.

 

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Abengoa started construction of the ATN Project in May 2008 and reached COD for each line as set forth below:

 

Line		kV		Beginning		End		COD
1		220		Carhuamayo		Paragsha		January 11, 2011
2		220		Paragsha		Conococha		February 24, 2011
3		220		Conococha		Kiman Ayllu		December 28, 2011
4		220		Kiman Ayllu		Cajamarca Norte		June 26, 2011

Credititulos Sociedad Titulizadora S.A., or Credititulos, acting as trustee for the senior bond holders of the project, owns the ATN Project.

Concession Agreement. Pursuant to the initial concession agreement, the Ministry of Energy, on behalf of the Peruvian Government, granted ATN a concession to construct, develop, own, operate and maintain the ATN Project. The initial concession agreement became effective on May 22, 2008 and will expire 30 years after the COD of Line 1, which was achieved on January 11, 2011.

Pursuant to the initial concession agreement, we own all assets that we acquired to construct and operate the ATN Project for the duration of the concession. The ownership of these assets will revert to the Ministry of Energy upon termination of the initial concession agreement.

The ATN Project has a 30-year, fixed-price tariff base denominated in U.S. dollars that is adjusted annually after the COD for each line in accordance with the U.S. Finished Goods Less Food and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations related to the ATN Project. The tariff base is intended to provide the ATN Project with consistent and predictable monthly revenues sufficient to cover the ATN Project’s operating costs and debt service and to earn an equity return.

Peruvian law requires the existence of a definitive concession agreement to perform electricity transmission activities where the transmission facilities cross public land or land owned by third parties. On February 20, 2010, the Ministry of Energy granted the project a definitive concession agreement to transmit electricity using the transmission lines of the ATN Project. The Ministry of Energy also approved the execution of the concession agreement between the Ministry of Energy and ATN, which was executed on February 23, 2010 and formalized by Public Deed dated March 9, 2010.

ATN has generated and will generate relevant NOL carryforwards that we expect to use to offset future taxable income. According to our estimates, ATN is not expected to pay income tax for a period of more than ten years.

Peru has a long-term credit rating of BBB+ from S&P, BBB+ from Fitch and Baa2 from Moody’s.

Engineering, Procurement and Construction Agreements. The construction of the ATN Project was carried out by subsidiaries of Abengoa under arm’s-length, fixed-price and date-certain EPC contracts. The procurement contract and the construction contract were executed on June 1, 2008 and all lines were completed by December 28, 2011. The guarantee period of the EPC contracts has expired.

Operations & Maintenance. Credititulos, as trustee, has an O&M agreement in the process of being assigned to Omega Peru, a subsidiary of Abengoa, specialized in O&M services for electric transmission lines across South American countries. The O&M agreement has a five-year term that renews automatically for an additional five-year period until the termination of the Concession agreement, unless either party exercises its right not to renew the O&M agreement. The O&M agreement provides for a fixed price of $3.35 million per year and is adjusted yearly with the variation of the U.S. Finished Goods Less Food and Energy Index.

 

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Project Level Financing. On September 26, 2013, ATN completed the issue of a project bond in three tranches. To implement the bond issuance, ATN created a trust holding all of the assets and economic rights arising out of the definitive concession agreement. Each tranche is denominated in U.S. dollars. The first tranche has a principal amount of $15 million with a five-year term with quarterly amortization and bears interest at a rate of 3.84375% per year. The second tranche has a principal amount of $50 million with a fifteen-year term with quarterly amortization and bears interest at a rate of 6.15% per year. The second tranche also has a five-year grace period for principal repayment. The third tranche has a principal amount of $45 million with a 26-year term and bears interest at a rate of 7.53% per year. The third tranche has a 15-year grace period for principal repayments. As of December 31, 2013, $108 million in aggregate was outstanding.

Cash distributions are subject to a historical debt service coverage ratio for the last six months of at least 1.10x.

Abengoa Transmision Sur

Overview. The Abengoa Transmision Sur, or ATS Project, in Peru is part of the SGT, and consists of:

 

(i)

one 500kV electric transmission line and two short 220kV electric transmission lines, which are linked to existing substations;

 

(ii)

three new 500kV substations; and

 

(iii)

the expansion of three existing substations (two existing 220kV substations and one existing 550/220kV substation), through the development of new transformers, line reactors, series reactive compensation and shunt reactions in some substations.

The transmission lines span approximately 569 miles and cross over the Lima, Ica, Arequipa and Moquegua districts. The new substations are located in the district of Poroma (Marcona), Ocona and Moquegua. Abengoa Transmision Sur, S.A., or ATS, owns the ATS Project.

Construction of the transmission lines and related substations required for operation of the ATS Project is complete. Pursuant to the concession agreements, the Ministry of Energy granted ATS the right to operate the ATS Project for 30 years from COD, which we achieved on January 17, 2014. As part of the initial concession agreement, we agreed to construct the Montalvo substation second bus bar, which was not required for operation of the ATS Project. A bus bar is a strip or bar of copper, brass or aluminum that conducts electricity within an electrical system. We anticipate the procurement, engineering, construction, testing and commissioning of the Montalvo substation second bus bar will cost approximately $700,000. We have funding in place for the costs associated with the second bus bar.

ATS has generated, and will generate, relevant NOL carryforwards that we expect to use to offset future taxable income. According to our estimates, ATS is not expected to pay income tax for a period of more than ten years.

Concession Agreement. Pursuant to the initial concession agreement, the Ministry of Energy, on behalf of the Peruvian Government granted ATS a concession to construct, develop, own, operate and maintain the ATS Project. The initial concession agreement became effective on July 22, 2010 and will expire 30 years after the COD.

Pursuant to the initial concession agreement, we will own all assets we acquired to construct and operate the ATS Project for the duration of the concession. These assets will revert to the Ministry of Energy upon termination of the initial concession agreement.

The ATS Project has a 30-year, fixed-price tariff base denominated in U.S. dollars and is adjusted annually after the COD in accordance with the U.S. Finished Goods Less Food and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base will be independent from the effective utilization of the

 

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transmission lines and substations related to the ATS Project. The tariff base is intended to provide the ATS Project with consistent and predictable monthly revenues sufficient to cover the ATS Project’s operating costs and debt service and to earn an equity return.

Peruvian law requires market participants to enter into a definitive concession agreement to perform electricity transmission activities where the transmission facilities cross public land or land owned by third parties. On June 6, 2012, the Ministry of Energy granted ATS a definitive concession agreement to transmit electricity using the transmission lines of the ATS Project. The Ministry of Energy approved the execution of the concession agreement between the Ministry of Energy and ATS, which was executed on June 7, 2012 and formalized by Public Deed dated August 1, 2012.

Peru has a long-term credit rating of BBB+ from S&P, BBB+ from Fitch and Baa2 from Moody’s.

Engineering, Procurement and Construction Agreements. The construction of the ATS Project was carried out by subsidiaries of Abengoa under arm’s-length, fixed-price and date-certain EPC contracts. The procurement contract and the construction contract were executed on July 22, 2010 and August 24, 2010, respectively, and COD was reached on January 17, 2014, except for the equipment related to the Montalvo substation second bus bar. The procurement contract provides warranties that protect ATS against defects in design, materials and workmanship for one year after the COD. The project also benefits from a full guarantee from Abengoa in favor of the financing parties of all of the EPC contractor’s obligations under the EPC contracts.

Operations & Maintenance. Omega Peru, a wholly-owned subsidiary of Abengoa, is in the process of being assigned a contract to provide O&M services for the ATS Project. The senior staff of Omega Peru has experience managing and operating transmission lines in Peru and additionally the project benefits from Abengoa’s overall experience in operating transmission lines projects worldwide and South America in particular. Omega Peru has agreed to operate the facility in accordance with prudent utility practices, ensure compliance with all applicable government and agency permits, licenses, approvals and concession agreement terms. The O&M agreement provides for a fixed fee of $2.0 million per year and is adjusted annually on the anniversary of the execution of the O&M agreement to reflect the variation in the U.S. Finished Goods Less Food and Energy Index. The O&M agreement has a five-year term that renews automatically for an additional five-year period until the termination of the initial concession agreement, unless either party exercises its right not to renew the O&M agreement.

Project Level Financing. On April 8, 2014, ATS issued a project bond in one tranche denominated in U.S. dollars. The project bond has a principal amount of $432 million with a 29-year term with semi-annual amortization and bears a fixed interest rate of 6.875%. The bond has a two-year grace period for principal repayment.

Cash distributions may be made every six months subject to a trailing historical debt service coverage ratio for the previous two quarters of at least 1.20x.

Partnerships. On December 5, 2012, Abengoa reached an agreement with Fondo para Inversiones en el Exterior represented by Compania Espanola de Financiacion del Desarrollo, Cofides, S.A., or Cofides, pursuant to which Cofides invested €25 million of shares of ATS in exchange for a share of the dividends and the taxable loss generated by the ATS Project. Prior to the consummation of the offering, we will exercise an option to purchase Cofides’ stake in ATS and will indirectly own 100% of ATS. The purchase price, in accordance with the call option, will be $38 million and will be paid after consummation of the offering with cash at hand at the Abengoa Yield plc level.

Quadra 1 & Quadra 2

Overview. Transmisora Mejillones, or Quadra 1, is a transmission line project consisting of a 220kV double circuit transmission line that begins at the Encuentro electrical substation that is owned by Transelec and is

 

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located in the commune of Maria Elena. Quadra 1 connects to the Sierra Gorda substation owned by Sierra Gorda SCM, a mining company and is located in the commune of Sierra Gorda. The project covers approximately 49 miles. It is comprised of 232 metallic galvanized structures and 293 miles of installed conductors.

Transmisora Baquedano, or Quadra 2, is a transmission line project that provides electricity to the seawater pump stations owned by the Sierra Gorda SCM. It consists of a simple circuit 220kV electric transmission line that begins at the Angamos electrical substation owned by EE Cochrane, an electrical company, and is located in the commune of Mejillones. Quadra 2 connects to the PS1 transformer substation. This section of Quadra 2 covers approximately seven miles. This section is comprised of 29 metallic galvanized structures and has 21 miles of installed conductors. The existing pumps, which are owned by Sierra Gorda, feed from the PS1 substation and the energy is converted by a transformer from 220/110/13.2kV to 110kV to continue through a simple circuit 110kV transmission line up to the PS2 substation. This section of Quadra 2 covers approximately 25 miles. This section is comprised of 165 metallic galvanized structures and has 75 miles of installed conductors.

Abengoa Chile S.A., or Abengoa Chile, began constructing Quadra 1 and Quadra 2 in September 2012 and started operations in December 2013 and January 2014, respectively. Quadra 1 reached COD in April 2014 and Quadra 2 reached COD in March 2014.

Concession Agreement. Both projects have concession agreements with the Sierra Gorda SCM mining company, which is owned by Sumitomo Corporation, Sumitomo Metal Mining and KGHM Polska Mietz. The concession agreement is denominated in U.S. dollars and has a 21-year term that began on the COD. The contract price is indexed to the U.S. CPI.

Sierra Gorda SCM requested additional work on Quadra 2 not initially foreseen, which required an additional capital expenditure of approximately $22 million. Construction of the additional work is substantially finished and has resulted in an increased tariff under the concession agreement with Sierra Gorda SCM.

Engineering, Procurement and Construction Agreements. The construction of both projects has been carried out by Abengoa Chile S.A. under arm’s-length, fixed-price and date-certain EPC contracts. Following the standard Abengoa model, the EPC contracts provide warranties that protect the project against defects in design, materials and workmanship for one year after COD. The project also benefits from a full guarantee from Abengoa in favor of the financing parties of all of the EPC contractor’s obligations under the EPC contracts.

Operations and Maintenance. Quadra 1 and Abengoa Chile S.A. executed an agreement for O&M services at Quadra 1. Abengoa Chile, in turn, subcontracted the O&M of the two land strips at the Encuentro substation to Transelec. This also includes the use of its communication channels down to the CDEC-SING.

Quadra 2 and Abengoa Chile executed an agreement for the provision of O&M services at Quadra 2, subject to certain exceptions. First, the O&M for the land strip that is within the EE Cochrane property will be undertaken by EE Cochrane under an agreement with Abengoa Chile S.A. Second, Gasatacama will undertake the operational representation against the CDEC-SING under an agreement with Abengoa Chile S.A.

Each O&M agreement with Abengoa Chile has a 252-month maturity and is denominated in U.S. dollars and indexed to Chilean CPI and to the average exchange rate.

Project Level Financing. On July 6, 2012, Quadra 1 signed a financing contract for $40.2 million with Credit Agricole Corporate and Investment Bank, or CA-CIB, Corpbanca, Banco BICE and the Inter-American Investment Corporation. The loan is denominated in U.S. dollars. The term of the loan is 16 years and the loan matures on July 30, 2028. The loan has a semi-annual amortization schedule. As of December 31, 2013, Quadra 1 has not made any principal payments. The interest rate is a variable rate based on the six-month LIBOR plus 3.80% for the first seven years after COD and 4.0% thereafter. Quadra 1 signed an interest rate cap hedging contract with CA-CIB that covers 75% of the debt and fixed the six-month LIBOR to a maximum rate of 2.5% per year until maturity.

 

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On November 20, 2012, Quadra 2 signed an initial financing contract for $34.4 million with CA-CIB and Corpbanca. The term of the loan is 16 years and the loan matures on August 31, 2028 and has a semi-annual amortization schedule. As of December 31, 2013, Quadra 2 has not made any principal payments. The interest rate is a variable rate based on the six-month LIBOR plus 3.80% for the first seven years after COD and 4.0% thereafter. Quadra 2 signed an interest rate swap hedging contract with Corpbanca that covers 75% of the debt and fixed the six-month LIBOR to 2.5175% until maturity. Due to the additional work required by Sierra Gorda SCM, an additional debt tranche for a total of $17 million is pending. An additional hedging contract will also be required in connection with the additional $17 million credit. As of December 31, 2013, $67.4 million in aggregate was outstanding in respect of Quadra 1 and Quadra 2.

With respect to Quadra 1 and Quadra 2, the financing arrangements restrict cash distribution to shareholders unless a distribution test of 1.20x historical debt service coverage ratio for the previous six months is met.

Palmucho

Palmucho is a short transmission line in Chile that is approximately 6 miles. It delivers energy generated by the Palmucho Plant, which is owned by Endesa Chile, to the SIC. The Palmucho Plant connects to the number 2 circuit of the 220kV Ralco—Charrua transmission line at the 66/220kV Zona de Caida substation. The Palmucho project has been in operation since October 2007. Palmucho has a 14-year concession contract with Endesa Chile. Both parties are obliged to enter into a four-year valid toll contract at the end of the term of the concession contract and the valid toll contract will be renewed for three periods of four years each until one of the parties decides not to renew. Endesa Chile operates the Palmucho project and Abengoa Chile maintains the project. On October 24, 2008, Palmucho signed a long-term debt facility with Corpbanca for $7 million. The loan is denominated in U.S. dollars. The term of the loan is 13 years and the loan matures on October 25, 2021. The loan has a quarterly amortization schedule and the outstanding balance as of December 31, 2013 was $6.5 million. Endesa Chile has a senior unsecured credit rating of BBB+ from S&P, Baa2 from Moody’s and BBB+ from Fitch.

Exchangeable Preferred Equity Investment in Abengoa Concessoes Brasil Holding

In addition to the assets listed above, we hold an exchangeable preferred equity investment in ACBH, a subsidiary holding company of Abengoa that is engaged in the development, construction, investment and management of contracted concessions in Brazil, comprised mostly of transmission lines in various stages of development. Abengoa holds 100% of the ordinary shares of ACBH.

Pursuant to a shareholders agreement to be entered into among us, ACBH and the ordinary shareholders of ACBH, we have the following rights under the exchangeable preferred equity investment:

 

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During the five-year period commencing on July 1, 2014, we have the right to receive, in four quarterly installments, a preferred dividend of $18.4 million per year. The board of directors and shareholders of ACBH will approve the distribution of the preferred dividend for the five-year period prior to the consummation of the offering. The cash corresponding to such preferred dividends for the five-year period will be initially deposited for this purpose in an account in New York City in U.S. dollars in the amount of $92 million.

 

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Following the initial five-year period, we will have the option to (i) remain as a preferred equity holder with the right to receive, in U.S. dollars or Brazilian reais, the first $18.4 million that ACBH is able to distribute, if any, or (ii) during a specified period of time exchange the preferred equity interest into ordinary shares of one or several project companies owned by ACBH at the time of the exchange that yield, based on the then-prevailing conditions, an aggregated recurrent dividend of at least $18.4 million. ACBH and Abengoa will propose specified projects that fulfill the above-described criteria, and which may include minority and/or majority stakes in various operational projects. Our independent board members will then approve or reject the proposal. Any exchange of shares would be subject to relevant approvals, including from regulatory bodies, financing banks or equity partners at the project level. If ACBH cannot secure such approvals following

 

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Abengoa’s best efforts, the preferred equity interest will not be exchanged and we will retain the right to receive the first $18.4 million dividend that ACBH approves for distribution, if any. We cannot guarantee, after the initial five-year period, that the $18.4 million distribution will be made, as any distribution will depend, among others, on the actual performance of ACBH or of the project companies into which the preferred equity interest has converted, as the case may be. Furthermore, any such future payments will not be backed by any escrow arrangements.

Pursuant to the terms of a deed we will enter into with an Abengoa subsidiary holding our shares in its capacity as our shareholder prior to the consummation of the offering, generally, in the event the annual dividend paid by ACBH to us as holder of ACBH’s preferred equity is below $18.4 million in any given year, the Abengoa subsidiary holding our shares will agree that Abengoa Yield can defer the payment of a portion of the dividend from Abengoa Yield to that Abengoa subsidiary in an amount equal to such shortfall (similar arrangements will apply if that Abengoa subsidiary transfers any of our shares to its subsidiaries (other than Abengoa Yield or subsidiaries of Abengoa Yield), any holding company of that Abengoa subsidiary or any other subsidiaries of such holding companies (the “ACI Group”)). However, any such deferral will be made only if and to the extent that the Abengoa subsidiary holding our shares (or, where relevant, another member of the ACI Group) continues to be a shareholder of ours as of the relevant date. If the ACI Group’s ownership of us falls below a level such that the attributable share of our dividends to the ACI Group falls below $18.4 million, we have the option of requiring the relevant member or members of the ACI Group to purchase part or all of our preferred interest in ACBH so that the preferred dividend payable to us from ACBH following such purchase is equivalent to (but does not exceed) the ACI Group’s share of our dividend going forward.

The deed will cease to be in force when: (i) we cease to hold any exchangeable preferred equity investment in ACBH; (ii) we elect to exchange all of our preferred equity in ACBH for shares in ACBH’s projects; or (iii) the aggregate amount of dividends from projects owned by ACBH and paid to ACBH and which are freely distributable by ACBH to Abengoa Yield reaches a minimum of $36 million per financial year for three consecutive financial years (provided that at that time: (a) all assets held by ACBH have entered into commercial operation and (b) ACBH’s cash flow projections for the following 12 months indicate that ACBH will be able to pay the preferred dividend of $18.4 million to Abengoa Yield for the current fiscal year).

The following table summarizes the electric transmission lines owned by the ACBH project companies:

 

Project		Miles		Abengoa Ownership		Concession- Type Contract		Concessionaire		Status (Historical or Expected Operational Start Date)
ATE IV (Sao Mateus)		53		75%		BOOT		ANEEL		Operational (Sept 10)
ATE V (Londrina)		82		100%		BOOT		ANEEL		Operational (Oct 10)
ATE VI (Campos Novos)		81		100%		BOOT		ANEEL		Operational (Jan 10)
ATE VII (Foz do Iguacu)		71		100%		BOOT		ANEEL		Operational (Aug 09)
Manaus		364		50.5%		BOOT		ANEEL		Operational (Mar 13)
ATE VIII		67		50%		BOOT		ANEEL		Operational (Jan 14)
Norte Brasil		1,476		51%		BOOT		ANEEL		Construction (Q3 2014)
Linha Verde(1)		613		51%		BOOT		ANEEL		Construction (Q4 2014)
ATE XVI		1,128		100%		BOOT		ANEEL		Pre-Construction (Q3 2016)(2)
ATE XVII		178		100%		BOOT		ANEEL		Pre-Construction (Q2 2016)(2)
ATE XVIII		238		100%		BOOT		ANEEL		Pre-Construction (Q1 2016)(2)
ATE XIX		391		100%		BOOT		ANEEL		Pre-Construction (Q3 2016)(2)
ATE XX		336		100%		BOOT		ANEEL		Pre-Construction (Q3 2016)(2)
ATE XXI		1,094		100%		BOOT		ANEEL		Pre-Construction (Q3 2016)(2)
ATE XXII		228		100%		BOOT		ANEEL		Pre-Construction (Q1 2017)(2)
Total		6,401

 

(1)	ACBH and Electrobras are in advanced discussions for the latter to acquire the 51% of Linha Verde owned by ACBH. This transaction is not subject to the ROFO Agreement.

 

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(2)

The pre-construction projects will require ACBH to secure all permits required by Brazilian law. See “Risk Factors—Risks Related to Our Business and the Markets in which We Operate—We are subject to extensive governmental regulation in a number of different jurisdictions, and our inability to comply with existing regulations or requirements or changes in applicable regulations or requirements may have a negative impact on our business, results of operations or financial condition.”

Each project has a 30-year concession agreement, and each concession agreement provides for indemnification and compensation at replacement value of non-depreciated assets at the end of the concession. ANEEL granted the concession agreements to the different project companies through an auction process. The revenues paid by ANEEL are denominated in Brazilian reais and indexed to the IPCA, which is the Brazilian consumer price index.

Projects ATE IV, ATE V, ATE VI, ATE VII, Manaus and Norte each received project financing from the National Bank for Economic and Social Development, or Banco Nacional de Desenvolvimento Economico e Social, and Norte and Manaus received project financing from Superintendencia do Desenvolvimento da Amazonia, a development institution for projects in certain regions of Brazil.

Manaus, Norte Brasil and Linha Verde are partnerships with different subsidiaries of Electrobras, the Brazilian utility.

ACBH also holds an ownership interest in a hospital facility.

ACBH will not participate in any additional tender of projects, consequently, once the projects listed in the table above are completed, all of ACBH’s portfolio will be operational.

Customers and Contracts

We derive our revenue from selling electricity and electric transmission capacity. Our customers are comprised of governments and electrical utilities, the latter with which we typically have entered into power purchase agreements. We also employ concession contracts, typically ranging from 20 to 30 years.

See the description of each asset under “—Our Operations” for more detail on each concession contract.

Our main contracts in our business also include the non-recourse project finance contracts with banks or financial institutions and the operation and maintenance contracts of each of our assets. See description of financing and operation and maintenance contracts under “—Our Operations.”

Additionally, we have entered into a ROFO Agreement, an Executive Services Agreement, a Support Services Agreement, a Financial Support Agreement and a Trademark License Agreement with Abengoa. See “Related Party Transactions” for more detail on these contracts.

Competition

Renewable energy, conventional power and electric transmission are all capital-intensive and significantly commodity-driven businesses with numerous industry participants. We compete based on the location of our assets and ownership of portfolios of assets in various countries and regions; however, because our assets typically have 20- to 30-year contracts, competition with other asset operations is limited until the expiration of the PPAs. Power generation and transmission are highly regulated businesses in each country in which we operate and are currently highly fragmented and have a diverse industry structure. Our competitors have a wide variety of capabilities and resources. Our competitors include, among others, regulated utilities and transmission companies, other independent power producers and power marketers or trading companies and state-owned monopolies.

Intellectual Property

We will enter into a licensing agreement with Abengoa pursuant to which Abengoa will grant us a non-exclusive, royalty-free license to use the name “Abengoa” and the Abengoa logo. Other than under this

 

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limited license, we will not have a legal right to use the “Abengoa” name or the Abengoa logo. Abengoa will commit to transfer, sell or assign three web domains to us, including www.abengoayield.com and www.abengoayield.co.uk. Abengoa will be entitled to terminate the licensing agreement in the circumstances described under “Related Party Transactions—Trademark License Agreement.”

Regulatory and Environmental Matters

See “Regulation.”

Insurance

We maintain the types and amounts of insurance coverage that we believe are consistent with customary industry practices in the jurisdictions in which we operate. Our insurance policies cover employee-related accidents and injuries, property damage, machinery breakdowns, fixed assets, facilities and liability deriving from our activities, including environmental liability. We maintain business interruption insurance for interruptions resulting from incidents covered by insurance policies. Our insurance policies also cover directors’ and officers’ liability and third-party insurance. We have not had any material claims under our insurance policies that would either invalidate our insurance policies or cause a material increase to our insurance premiums. We cannot assure you, however, that our insurance coverage will adequately protect us from all risks that may arise or in amounts sufficient to prevent any material loss. See “Risk Factors—Risks Related to Our Business and the Markets in which We Operate—Our insurance may be insufficient to cover relevant risks and the cost of our insurance may increase.”

Seasonality

Our operating results and cash flows can be significantly affected by weather in some of our most relevant projects, such as the Concentrating Solar Power plants. We expect to derive a majority of our annual revenues in the months of May through September, when demand for electricity is generally at its highest in the majority of our markets and when some of our offtake arrangements provide for higher payments to us.

Employees

Most of our project companies and intermediate holdings have no employees. Only Palmatir and ATN had employees as of December 31, 2013. In 2014, all ATN employees have been transferred to other Abengoa subsidiaries as they are related to activities to be performed by them. As a result, as of the date of this prospectus, we have four employees at Palmatir. Additionally, all members of our management team are currently employees of Abengoa and expect to remain so after the consummation of this offering. Within one year following the consummation of this offering, we expect to employ directly ten senior managers currently employed by Abengoa who we expect will be transferred to Abengoa Yield from Abengoa. For a discussion of the individuals from Abengoa’s management team that are expected to be involved in our business, see “Management.”

Properties

See “—Our Operations.”

Legal Proceedings

We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are party to various administrative and regulatory proceedings that have arisen in the ordinary course of business. While we do not expect these proceedings, either individually or in the aggregate, to have a material adverse effect on our financial position or results of operations, because of the nature of these proceedings we are not able to predict their ultimate outcomes, some of which may be unfavorable to us.

 

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REGULATION

Overview

We operate in a significant number of highly regulated markets. The degree of regulation to which our activities are subject varies by country. In a number of the countries in which we operate, regulation is carried out mainly by national regulatory authorities. In others, such as the United States and, to a certain degree, Spain, there are various additional layers of regulation at the state, regional and/or local level. In countries with these additional layers of regulatory agencies, the scope, nature and extent of regulation may differ among the various states, regions and/or localities.

While we believe the requisite authorizations, permits and approvals for our assets have been obtained and that our activities are operated in substantial compliance with applicable laws and regulations, we remain subject to a varied and complex body of laws and regulations that both public officials and private parties may seek to enforce. The following is a description of the primary industry-related regulations applicable to our assets that are currently in force in the principal markets in which we operate.

Regulation in the United States

In the United States, our electricity generation project companies are subject to extensive federal, state and local laws and regulations that govern the development, ownership, business organization and operation of power generation facilities. The federal government regulates wholesale sales, operation and interstate transmission of electric power through FERC and through other federal agencies, certain environmental, health and safety matters. State and local governments regulate the siting, permitting, construction and operation of power generation facilities, the retail sale of electricity and certain other environmental, health, safety and permitting matters.

United States Federal Regulation of the Power Generation Facilities and Electric Transmission

The United States federal government regulates the wholesale sale of electric power and the transmission of electricity in interstate commerce through FERC, which draws its jurisdiction from the FPA and from other federal legislation such as the Public Utility Regulatory Policies Act of 1978, or PURPA, the Energy Policy Act of 1992, and the Energy Policy Act of 2005, or EPACT 2005. EPACT 2005 repealed the Public Utility Holding Company Act of 1935 and replaced it with the Public Utility Holding Company Act of 2005, or PUHCA.

Federal Regulation of Electricity Generators

The FPA provides FERC with exclusive ratemaking jurisdiction over all public utilities that engage in wholesale sales of electricity and/or the transmission of electricity in interstate commerce. The owners of renewable energy facilities selling at wholesale are therefore generally subject to FERC’s ratemaking jurisdiction. FERC may authorize a public utility to make wholesale sales of electric energy and related products at negotiated or market-based rates if the public utility can demonstrate that it does not have, or that it has adequately mitigated, horizontal and vertical market power and that it cannot otherwise erect barriers to market entry. Entities granted market-based rate approval face ongoing filing and compliance requirements. Failure to comply with such requirements may result in a revocation of market-based rate authority, disgorgement of profits, civil penalties or other remedies that FERC finds appropriate based on the specific facts and circumstances. In granting market-based rate approval to a wholesale generator, FERC also typically grants blanket authorizations under Section 204 of the FPA and FERC’s regulations for the issuance of securities and the assumption of debt liabilities.

If the criteria for market-based rate authority are not met, FERC has the authority to impose conditions on the exercise of market rate authority in order to mitigate market power or to withhold or rescind market-based rate authority altogether and require sales to be made based on cost-of-service rates, which could in either case

 

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result in a reduction in rates. FERC also has the authority to assess substantial civil penalties (up to $1 million per day per violation) for failure to comply with tariff provisions or the requirements of the FPA.

FERC approval under the FPA may be required prior to a change in ownership or control of a 10% or greater voting interest, directly or through one or more subsidiaries, in any public utility (including one of our U.S. project companies) or any public utility assets. FERC approval may also be required for individuals to serve as common officers or directors of public utilities or of a public utility and certain other companies that provide financing or equipment to public utilities.

FERC also implements the requirements of PUHCA applicable to “holding companies” having direct or indirect voting interests of 10% or more in companies that (among other activities) own or operate facilities used for the generation of electricity for sale, which includes renewable energy facilities. PUHCA imposes certain record-keeping, reporting and accounting obligations on such holding companies and certain of their affiliates. However, holding companies that own only exempt wholesale generators, or EWGs, foreign utility companies, and certain qualifying facilities under PURPA are exempt from the federal access to books and records provisions of PUHCA. EWGs are owners or operators of electric generation facilities (including producers of renewable energy, such as solar projects) that are engaged exclusively in the business of owning and/or operating generation facilities and selling electricity at wholesale. An EWG cannot make retail sales of electricity, may only own or operate the limited interconnection facilities necessary to connect its generation facility to the grid, and faces restrictions in transacting business with affiliated regulated utilities. Both Solana and Mojave have been granted EWG status and market-based rate authority by FERC.

Regulation of Electricity Sales

Electricity transactions in the United States may be bilateral in nature, whereby two parties contract for the sale and purchase of electricity subject to various governmental approval processes or guidelines that may apply to the contract, or they may take place within a single, centralized clearing market for purchases and sales of energy, electric generation capacity and ancillary services. Given the limited interconnections between electric transmission systems in the United States and differences among market rules, regional markets have formed as part of the electric transmission systems operated by regional transmission organizations, or RTOs, or independent system operators, or ISOs, in places such as California, the Midwest, New York, Texas, the Mid-Atlantic region and New England.

Federal Reliability Standards

 

EPACT 2005 amended the FPA to grant FERC jurisdiction over all users, owners and operators of the bulk power system for the purpose of enforcing compliance with certain standards for the reliable operation of the bulk power system. Pursuant to its authority under the FPA, FERC certified the North American Electric Reliability Corporation, or NERC, as the entity responsible for developing reliability standards, submitting them to FERC for approval, and overseeing and enforcing compliance with them, subject in each case to FERC review. NERC, in turn, has delegated certain monitoring and enforcement powers to regional reliability organizations. Users, owners, and operators of the bulk power system meeting certain materiality thresholds are required to register with the NERC compliance registry and comply with FERC-approved reliability standards.

In the western United States, NERC has a delegation agreement with the Western Electricity Coordinating Council, or WECC, whose service territory extends from Canada to Mexico and includes the provinces of Alberta and British Columbia, the northern portion of Baja California, Mexico, and all or portions of the 14 western states in between. WECC is the regional entity responsible for coordinating, promoting and enforcing bulk power system reliability in its service territory. Any entity that owns, operates or uses any portion of the bulk power system must comply with NERC or WECC’s mandatory reliability standards. Failure to comply with these mandatory reliability standards may subject a user, owner or operator to sanctions, including substantial monetary penalties, which range from $1,000 to $1 million per day per violation for the most severe cases, where companies show negligence and lack evidence of adequate compliance.

 

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Federal Environmental Regulation, Permitting and Compliance

Construction and operation of power generation facilities, including solar power plants, and the generation and electric transmission of renewable energy from such facilities are subject to environmental regulation at the federal, state and local level. State and local regulatory processes are discussed separately in a subsequent section. At the federal level, environmental laws and regulations typically require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a generation project or electric transmission facilities. Prior to development, permitting authorities may require that project developers consider and address, among other things, the impact on water resources and water quality, endangered species and other biological resources, compatibility with existing land uses and zoning, agricultural resources, archaeological, paleontological, recreational and cultural considerations, environmental justice and cumulative and visual impacts. In an effort to identify and minimize the potential impacts to these resources, power generation facilities may be required to comply with a myriad of federal regulatory programs and applicable federal permits under the National Environmental Policy Act, or NEPA, the Endangered Species Act, the Clean Water Act, the National Historic Preservation Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation, and Liability Act, the Environmental Protection and Community Right-to-Know Act and the National Wilderness Preservation Act, among other federal laws.

Solana and Mojave successfully completed all of their permitting requirements with regard to federal laws and regulations. The NEPA designation of a finding of no significant impact, or FONSI, was granted by the DOE (acting as lead federal agency for both projects) to Solana and Mojave on May 6, 2010 and July 8, 2011, respectively. Because a FONSI designation under NEPA is a declaration of environmental compatibility rather than an operating permit, the designation carries no conditions or stipulations that could present an operational risk to Solana or Mojave.

In addition, various federal environmental, health and safety regulations applicable during the construction phase are also applicable to the operational phase of power generation facilities. During the operational phase, obtaining certain federal permits or federal approval of certain operating documents (e.g., O&M plans, the spill prevention, control and countermeasure plan, and an emergency and preparedness response plan), as well as maintaining strict compliance with such permits or operating documents, is mandatory. Failure to maintain compliance may result in the revocation of any applicable permit or authorization, civil and criminal charges and fines or potentially the closure of the plant.

U.S. Federal Income Tax Incentives and Other Federal Considerations for Renewable Energy Generation Facilities

The United States provides various federal, state and local tax incentives to stimulate investment in renewable energy generation capacity, including solar power. These tax incentives are subject to change and, possibly, elimination in the future. Certain U.S. federal income tax incentives are described below.

Section 1603 U.S. Treasury Grant Program

In lieu of claiming certain U.S. federal income tax credits, in particular, the ITC, owners of eligible solar energy property may be eligible to receive a cash grant from U.S. Treasury equal to 30% of the tax basis of the eligible property. Among other requirements, to be eligible for a 1603 Cash Grant, the eligible property must have been placed in service in 2009, 2010 or 2011 or, for property not placed in service during that period, the construction of the specified energy property must have begun after December 31, 2008 and before January 1, 2012. In addition, in order to qualify, eligible solar energy property must be placed in service by January 1, 2017. Applicants who began construction after December 31, 2008 and before January 1, 2012, but who did not place the eligible solar energy property in service prior to October 1, 2012, were required to file a preliminary 1603 Cash Grant application prior to October 1, 2012. These applicants are further required to file a final or “converted” 1603 Cash Grant application no later than 180 days after the eligible solar energy property is placed in service. The preliminary 1603 Cash Grant application for Solana was filed in September 2012, and the final

 

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1603 Cash Grant application for Solana was filed on November 14, 2013 with additional information being provided to the U.S. Treasury on an ongoing basis. The preliminary 1603 Cash Grant application for Mojave was filed on September 14, 2012. Because Mojave has not yet been placed in service, no final 1603 Cash Grant application has been filed or currently is due.

The risks associated with the 1603 Cash Grant program are as follows:

 

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Disqualified Persons: Certain persons, “disqualified persons,” are ineligible to receive the 1603 Cash Grant and are prohibited from owning a direct or indirect interest in otherwise 1603 Cash Grant-eligible solar energy property, unless the indirect interest is held through an entity taxable as a C corporation for U.S. federal income tax purposes. 1603 Cash Grants are subject to recapture during the five-year period beginning on the date the eligible solar energy property is placed in service. The amount of the 1603 Cash Grant subject to recapture decreases ratably over the five-year recapture period. Among other events, failure of the eligible property to be used for its intended purpose or the direct or indirect transfer to a disqualified person (as described above) will cause recapture of the 1603 Cash Grant.

 

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Sequestration of Cash Grant Funds: Certain legislation required a mandatory sequestration of discretionary spending if the U.S. Congress failed to reach an agreement on a deficit-reducing budget by March 1, 2013. Because the U.S. Congress did not approve the requisite budget by that deadline, President Obama signed a sequestration order. Under the current sequestration rules, every final decision by U.S. Treasury in respect of a 1603 Cash Grant, evidenced by an award letter that is delivered to a 1603 Cash Grant applicant on or after October 1, 2013 through September 30, 2014, will reflect a 7.2% reduction in the 1603 Cash Grant award amount. This reduction applies regardless of the date on which the application for a 1603 Cash Grant was received by U.S. Treasury. For fiscal year 2015, which starts on October 1, 2014, certain legislation requires the White House’s Office of Management and Budget to recalculate the sequestration percentage for 1603 Cash Grants awarded in Fiscal Year 2015.

Federal Loan Guarantee Program

The DOE, in an effort to promote the rapid deployment of renewable energy and electric transmission projects, is currently authorized to grant guarantees with respect to certain loans to renewable energy projects and related manufacturing facilities and electric transmission projects under Section 1703 of EPACT 2005. Previously, the DOE also granted guarantees with respect to certain loans made under Section 1705 of EPACT 2005. In order to have qualified for the Section 1705 program, physical construction must have commenced at the primary site of the project on or before September 30, 2011. NEPA review must have been completed prior to the issuance of a loan guarantee. In May 2011, the Section 1705 program expired by statute, and the DOE announced that it would no longer accept new applications under that program. On September 30, 2011, the Section 1705 loan guarantee program closed with no further loan guarantees to be issued.

Solana was issued a loan guarantee under section 1705 of EPACT 2005 on December 20, 2010. Mojave was issued a loan guarantee under section 1705 of EPACT 2005 on September 12, 2011. Because of their respective loan guarantees, both projects must pay prevailing wages under the Davis-Bacon Act of 1931.

Accelerated Depreciation under Federal Regulation

Owners of eligible solar energy property also benefit from accelerated depreciation of the property over a five-year period under the MACRS under the IRC. Most of the equipment used in Concentrating Solar Power projects, such as Solana and Mojave, qualifies for five-year depreciation under MACRS. In addition, some equipment used in Concentrating Solar Power projects may qualify for bonus depreciation for equipment placed in service.

 

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State and Local Regulation of the Electricity Industry in the United States

State regulatory agencies in the United States have jurisdiction over the rates and terms of electricity service to retail customers. Regulated investor-owned utilities often must obtain state approval for the contracts through which they purchase electricity, including renewable energy, if they seek to pass along the costs of these contracts to their retail ratepayers. Municipal utilities and electric cooperatives are typically governed on these matters by their city councils or elected boards of directors. Different states apply different standards for determining acceptable prices for utility procurement contracts, including PPAs. Our electricity generation project companies operate or are near operation in Arizona and California. Information about the regulatory frameworks in Arizona and California is provided below.

State and Local Incentives

In addition to federal legislation, many states have enacted legislation, principally in the form of RPS, which generally require electric utilities to generate or purchase a certain percentage of their electricity supplied to consumers from renewable resources. Depending upon the state, various certifications, permits, contracts and approvals may be required in order for a project to qualify for particular RPS programs. Although there is currently no federal RPS program, there have been proposals to create a federal RPS standard for renewable energy.

Renewable Energy Certificates, or RECs, are typically used in conjunction with RPS programs as tradable certificates demonstrating that a certain number of kWh have been generated from renewable resources. Under many RPS programs, a utility may generally demonstrate, through its ownership of RECs, that it has supported an amount of renewable energy generation equal to its state-mandated RPS percentage. The sale of RECs can represent a significant additional revenue stream for renewable energy generators.

Effective December 10, 2011, California enacted legislation that increases its existing RPS to 25% by 2016 and 33% by 2020, and expands the program to cover publicly-owned utilities, in addition to investor-owned utilities. In addition, the California Solar Initiative, or CSI, sets a goal of 1,940 MW of solar capacity by the end of 2016. Arizona set an RPS of 15% by 2025, with 30% of the RPS to be met from distributed generation.

Other incentives that states and localities have adopted to encourage the development of renewable resources include property and state tax exemptions and abatements, state grants and rebate programs. California offers a property tax incentive for certain solar energy systems installed between January 1, 1999 and December 31, 2016. The Arizona Department of Revenue provides a corporate tax credit based on production for solar, wind or biomass systems that are 5 MW or larger and are installed on or after December 31, 2010 and before January 1, 2021.

Solar generation may also be incentivized by state greenhouse gas, or GHG, emission reduction measures, such as California’s cap and trade scheme, which caps and reduces GHG emissions. The California cap and trade program went into effect with respect to the electricity and other sectors starting in 2013.

Arizona

Regulation of Retail Electricity Service in Arizona

The Arizona Corporation Commission, or ACC, has complete and exclusive jurisdiction over the rates and terms under which regulated utilities may provide electricity service to retail customers in Arizona. Under the Arizona Constitution, the ACC has unilateral authority over all utility regulation, including electric and natural gas utilities. The ACC also oversees all rate cases for its jurisdictional utilities, and as such has oversight of renewable energy procurement contracts by regulated electric utilities. Under Arizona’s Renewable Energy Standard & Tariff, or REST, regulated electric utilities must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. The renewable energy requirement is 4.5% of retail electric sales in 2014 and increases annually until it reaches 15% in 2025.

 

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Unlike many other state regulatory commissions, the ACC does not approve PPAs executed by regulated utilities, nor does it issue rulings of “prudency” regarding PPAs. This practice leaves a utility somewhat at risk of recovering its costs until a successful rate case finding is rendered by the ACC. Rate recovery requests may not be filed until the utility begins to make actual expenditures for power procurement. In the case of Solana, however, the power purchaser, Arizona Public Service Company, or APS, voluntarily sought a hearing before the ACC to request its informal opinion of the prudency of the Solana PPA. After ACC staff conducted an analysis of the costs and benefits of Solana to Arizona ratepayers, it recommended to the ACC commissioners that the PPA should be deemed “a reasonable means” by which APS could meet its requirements under the REST. The ACC affirmed the staff’s recommendation on September 30, 2008, thereby providing greater assurance of APS’s successful rate recovery request. APS is expected to file its full rate recovery request in 2016.

Performance and Operational Provisions of Solana’s PPA

The PPA executed between APS and Solana’s project company, Arizona Solar, contains provisions related to guarantees of performance (e.g., provision of minimum annual renewable energy certificates, or REC, eligible energy quantities to APS). The provisions are largely intended to protect APS’ ability to meet its mandatory requirements under the REST, and to prevent APS from having to procure REC eligible power elsewhere at an unknown, and presumably higher cost than the PPA price.

Siting and Construction of New Power Generation Facilities in Arizona

The Arizona Power Plant & Transmission Line Siting Committee, or Siting Committee, oversees utility and private developer applications to build power plants (of 100 MW or more) or transmission projects (of 115,000 volts or more) within Arizona. The Siting Committee holds public meetings and evidentiary hearings to determine whether a proposed generation or transmission project is compatible with preservation of the state’s environmental protection interests, and if the finding is affirmative, makes a recommendation to the ACC to grant a Certificate of Environmental Compatibility, or CEC, to the applicant. The ACC then has authority to approve, decline or modify the Siting Committee’s recommendation.

The ACC granted CECs to Solana on December 11, 2008, for both the 280 MW solar generation project and its associated 20.8-mile, 230 kilovolt transmission line. Both the generation facility and transmission line CECs contain obligatory conditions and stipulations, none of which could present a risk to Solana during the operational phase.

Other Arizona Permitting and Compliance Frameworks

Various state and county regulations, mostly related to the environment, public health and safety, are applicable during the operational phase of a solar power plant located in Maricopa County, Arizona. Such regulations include the Arizona Aquifer Water Quality Standards and Aquifer Protection Permit Rules, the Maricopa County Special Use Permit Stipulations, the Maricopa County Air Pollution Control Regulations, and the Maricopa County Zoning Ordinances and Regulations. Obtaining a permit or requesting the approval of certain operating plans, as well as strict compliance to such permits and plans, is mandatory. Failure to comply may result in the revocation of the permit or authorization, civil and criminal charges and fines, or potentially the closure of Solana.

In addition, in accordance with the NEPA designation of a FONSI issued by the DOE, Solana must comply with certain water requirements due to the reduction in tail water runoff being contributed to a wash located near the site. In coordination with Arizona Game & Fish Department and the U.S. Fish and Wildlife Service, Solana must provide 447 acre-feet of water annually as a direct off-set to the reduction in tail water runoff from the site. This requirement is for the duration of Solana, and failure to comply would trigger an administrative procedure that could cause temporary closure of the plant until the non-compliance condition is cured.

 

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Regulations Affecting Operating Generation Facilities in Arizona

Many of the permits obtained for Solana carry specific conditions that must be complied with during the operational phase of the facility and which are continuously monitored, measured, and documented by the Solana plant operators. The primary obligations that commenced during commissioning and/or commercial operation are those related to reliability, emergency response, potential hazards of waste disposal, and human health and safety. These requirements originate with federal laws, and in many cases are enforced via delegated authority from the appropriate federal agency to a state or county agency. These include:

 

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NERC Reliability Standards and Critical Infrastructure Plans, delegated to WECC as the regional authority;

 

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Emergency Planning and Community Right-to-Know Act, delegated to the Arizona Division of Emergency Management;

 

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Resource Conservation and Recovery Act, delegated to EPA Region 9 in San Francisco, California; and

 

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Occupational Safety and Health Administration federal requirements.

California

Regulation of Retail Electricity Service in California

The California Public Utilities Commission, or CPUC, governs, among other entities, California’s three large investor-owned utilities, including Pacific Gas & Electric Company, or PG&E. PG&E is required to file an RPS procurement plan annually with the CPUC. Once the CPUC approves the plan, PG&E issues a request for offers, or RFO, for renewable energy. It then evaluates all of the bids using a “least-cost, best-fit” evaluation process approved by the CPUC and develops a short list of acceptable bids. In August 2008, Mojave was submitted as a renewable solar thermal project in response to PG&E’s 2008 RFO solicitation and placed on their short list. After two years of negotiations, PG&E and Mojave Solar executed a final PPA, for which PG&E filed with the CPUC an advice letter requesting approval of the PPA in July 2011. The CPUC reviewed the PPA and approved the contract by issuing a formal decision in November 2011. The terms of the PPA will govern Mojave during its development, construction and operating period. The CPUC historically does not retroactively apply new regulations or rulings to previously approved PPAs that would result in any economic impact.

Performance and Operational Provisions of Mojave’s PPA

The PPA executed between PG&E and Mojave’s project company, Mojave Solar, contains provisions related to guarantees of performance (e.g., provision of minimum annual REC eligible energy quantities to PG&E). The provisions are largely intended to protect PG&E’s ability to meet its mandatory requirements established by the CPUC, and to prevent PG&E from having to procure REC eligible power elsewhere at an unknown, and presumably higher cost than the PPA price.

Siting and Construction of New Power Generation Facilities in California

The California Energy Commission, or CAEC, is the lead agency for licensing thermal power plants 50 MW and larger under the California Environmental Quality Act and has a certified regulatory program under such Act. The EC is comprised of five commissioners, two of which oversee all hearings, workshops and related proceedings on a specific project. The CAEC’s siting process evaluates Applications for Certification, or AFCs, to ensure that only power plants which are actually needed will be built, provides review by independent staff with technical expertise in public health and safety, environmental sciences, engineering and reliability, ensures simultaneous review and full participation by all state and local agencies, as well as coordination with federal agencies resulting in issuance of one regulatory permit within a specific time frame, with full opportunity for participation by public and interest groups.

 

 

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On August 10, 2009, Mojave’s AFC for its nominal 250 MW project was filed with the CAEC. The CAEC approved Mojave’s AFC with the CAEC decision issued on September 8, 2010. The CAEC monitors the power plant’s construction, operational phase and eventual decommissioning through a compliance proceeding.

Regulations Affecting Operating Generation Facilities in California

Mojave must maintain compliance with the CAEC decision conditions of certification. These concern, among others, biological resources, health and safety, cultural resources, fire safety, and water. The conditions require Mojave to provide plans, notifications, and other reports on an ongoing basis. As noted above, such compliance is monitored by CAEC staff. Per the CAEC decision, “[f]ailure to comply with any of the Conditions of Certification or the compliance conditions may result in reopening of the case and revocation of Energy Commission certification; an administrative fine; or other action as appropriate.” Additional regulations are administered by the California Independent System Operators and under the terms of the federally administered Large Generator Interconnection Agreement.

Regulation in Mexico

Overview

The following is a description of the regulation of the Mexican power industry applicable to the conventional generation of electricity. Such regulation remains subject to all future reforms, which may be promulgated pursuant to the amendments to articles 25, 26, and 28 of the Mexican Constitution, Constitucion Politica de los Estados Unidos Mexicanos.

Pursuant to the Mexican Constitution, the electricity industry in Mexico is controlled by the federal government, acting through the Federal Electricity Commission, Comision Federal de Electricidad, or CFE, an entity wholly owned and controlled by the Mexican government, and legally independent from the Ministry of Energy, Secretaria de Energia. CFE is the only entity authorized to provide electricity directly to the public and to supply services to the Mexican wholesale market. CFE is also responsible for the construction and maintenance of infrastructure necessary for the delivery of electricity, such as the national electric grid.

As a result of Mexico’s Energy Reform Bill enacted on December 21, 2013, articles 25, 27 and 28 of the Mexican Constitution were amended in order to end the long-standing state monopoly in the oil, petrochemical and power sectors, and allow private investment in these areas for their development in an open market. Hence, the power generation sector will be open to full private participation and investment, creating a competitive spot market in power generation, although electric transmission and distribution will remain public services to be provided exclusively by CFE. Once secondary legislation is enacted to implement the constitutional reform (expected by May 2014), generation, transmission and distribution of power in Mexico will be governed by a new legal framework which will likely improve the development of the sector.

Notwithstanding the anticipated legal changes, we do not expect any negative consequences for Abengoa Cogeneracion Tabasco, or ACT, or for the power generated and delivered to Pemex Gas y Petroquimica Basica.

Until the recent constitutional reform on December 21, 2013, the laws and regulations governing the generation, transmission and distribution of power for public use were considered areas of national strategic importance. As a result, such activities were carried out exclusively by CFE. The national electric grid is also controlled by CFE through the Centro Nacional de Control Electrico, or the CENACE, which operates the national electric grid and controls delivery of all electricity generated by CFE and private generators connected to the grid. CFE is a vertically-integrated state monopoly that serves the whole country, and CENACE is a semi-independent agency that is part of CFE. As a result of the energy reform passed in December 2013 in Mexico, CENACE will become a decentralized public agency, which will continue to be responsible for the operation and control of the national electric grid with the aim of having an impartial third party (not CFE) operate the wholesale electricity market, guaranteeing open access to the national electric grid for both transmission and distribution of electricity.

 

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The generation, transmission and distribution of electricity is currently regulated by the Ley del Servicio Publico de Energia Electrica, or Electricity Law enacted in 1975 and amended in 1992. Since the implementation of the 1992 amendment to the Electricity Law, private entities have been allowed to participate in the following activities not considered public utility services, as defined by such law:

 

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Cogeneration—The electricity produced is used to supply power to the establishments associated with the cogeneration process and/or the shareholders of the cogeneration company;

 

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Self-supply generation—The electricity produced is used for the self-supply purposes of the holder of the relevant self-supply power generation permit and/or its shareholders;

 

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Independent power production—All the electricity produced is delivered to CFE;

 

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Small-scale production—The electricity produced does not exceed 30 MW and is used for export purposes or the supply of all power output is sold to CFE;

 

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Exports—The electricity produced is exported in its entirety; and

 

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Imports for independent consumption—The import of power for self-supply purposes.

Conventional Electricity Generation in Mexico

The current legal framework for conventional electricity generation in Mexico includes the regulation of fossil fuels, such as carbon, diesel, fuel oil, and natural gas, as well as nuclear fission regulation, which includes nuclear power plants and all related activities.

Accordingly, power generation under independent power production or self-supply schemes is not considered a public utility service and, therefore, may be performed by private companies and individuals pursuant to permits issued by the Energy Regulatory Commission, Comision Reguladora de Energia, or CRE. The CRE is a federal agency created in 1995 in order to enforce the laws and regulations relating to natural gas and electricity, and has the authority to issue permits, set tariffs, supervise, ensure adequate supply and, in the case of gas, promote competition.

As previously indicated, the Mexican federal government, acting through CFE, controls the entire chain of activities related to electric power, including generation, sale, distribution and transmission. The energy reform allows the private sector to openly participate in two portions of the production chain: the generation and the sale of electricity.

Pursuant to the reform, the private energy sector will be able to invest in electricity generation with the requisite permits. While the sale of electricity by private parties has not yet begun in Mexico, it is anticipated that privately sold electricity will be produced and transmitted by CFE.

The reforms are expected to have positive effects on the electricity industry in Mexico, allowing the private sector to play an active role where a government monopoly once existed, generating greater investment and better technology.

Permits and Authorizations

Permits are granted for indefinite periods of time, except for independent power producer permits, which are granted for 30-year renewable terms. In addition to the legal and technical requirements established by law to obtain such permits, CFE’s approval is required as part of CRE’s permit approval process.

Consequently, the Mexican power industry has been divided into two main areas: (a) the electric power public utility service under CFE’s control, and (b) the activities where private parties may be involved (such as where CFE actively promoted private investment in the construction and operation of power plants for supplying CFE and private parties under self-supply and cogeneration schemes).

 

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While power generated in Mexico is still predominantly generated by CFE, there is a large amount of electricity generated by private energy producers, which generally fall under the categories of independent power production and self-supply generation, although cogeneration has started to become a relevant source of power as a result of amendments enacted in 2006 which allowed Pemex to develop new cogeneration projects independently and in collaboration with CFE. These amendments allowed Pemex to enter into the Pemex conversion services agreement and to receive the power generated by ACT.

As a result of the reforms, the issuance of a new class of permit available to those interested in generating electricity is anticipated. This permit would expand the ways in which entities are allowed to participate as energy producers under the Electricity Law and is within the scope of the CRE’s regulatory control.

Transmission and Distribution of Electricity in Mexico

Regarding conventional energy generation, there are no regulatory limitations that would interfere with a private generator engaging in transmission activities. Distribution, however, may only be performed by CFE. Although the recent reform contemplates the participation of private investors in electricity transmission and distribution activities, these activities will remain under the purview of the Mexican federal government through CFE.

Under the existing system, CFE transmits and distributes electricity generated under any of the methods allowed under the Electricity Law. Once the reform is fully implemented, the intention is for the private sector to be involved in transmission and distribution activities, jointly with CFE, through contractual arrangements.

CFE is required by law to provide its wheeling (the transfer of electrical power through transmission and distribution lines to another utility), dispatch and backup services to all permit holders whenever the requested service is technically feasible under the principle of first-come, first-served. CFE’s wheeling services are provided pursuant to an interconnection agreement and a transmission services agreement entered into between CFE and the relevant permit holder (in ACT’s case, these were executed by Pemex). Those agreements follow model contracts approved by the CRE, which also approves the methodology used to calculate the applicable tariffs. The permit holders must build their own transmission lines for self-use in order to connect to the power grid. In addition, permit holders are required to enter into a back-up services agreement with CFE, which also follow a model agreement approved by the CRE.

Regulatory Framework

The following includes constitutional, legal, and administrative provisions applying to the development of cogeneration projects in Mexico:

 

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The Mexican Constitution. Pursuant to articles 25, 27, and 28 of the Mexican Constitution, the supply of electricity, a public service in Mexico, including its generation, transmission, transformation, distribution and sale are activities expressly reserved to the Mexican federal government.

 

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Electricity Law. Along with its regulations, this law provides the main legal framework through which the Mexican federal government, acting through CFE, provides the public its electricity supply, as well as the regulations applicable to power generation, sale, and purchase for the private sector.

 

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Law of the Energy Regulatory Commission, Ley de la Comision Reguladora de Energia. This regulates the manner in which the CRE operates.

 

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Resolution number RES/146/2001, issued by the CRE: Fee Calculation Methodology for Electricity Transmission Services, Metodologia para la determinacion de los cargos por servicios de transmision de energia electrica. This regulation provides the mechanism pursuant to which CFE will calculate the appropriate charges for the requests of transmission services.

 

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Interconnection Agreement, Contrato de Interconexion issued by the CRE.

 

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Transmission Agreement, Convenio de Transmision issued by the CRE.

 

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Methodology and criteria for high-efficiency cogeneration, Metodologia y criterios de cogeneracion eficiente.

 

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Guidelines for the validation as high-efficiency cogeneration systems, Disposiciones para acreditar sistemas de cogeneracion eficiente).

Regulation in Peru

Below is a general overview of certain Peruvian electricity sector regulations. This overview should not be considered a full description of all regulations.

The Electric Transmission Sector

The Peruvian electric system serves energy to a large area of the country through the SEIN that has transmission lines and substations operating at 500, 220, 138, 69 and 33-kV levels that are located mainly in the coastal area, from the border of Ecuador to the border of Chile and eastward near the border of Bolivia.

Pursuant to Law 28832, which is applicable to any transmission project commissioned after July 2006, the transmission facilities integrating the transmission grid are classified as those belonging to: either (i) the SGT for transmission facilities that are included in the transmission plan and developed pursuant to a concession agreement granted by the Peruvian government to the winner of a public tender, or (ii) the Complementary Transmission System, or Sistema Complementario de Transmision, or SCT, for transmission facilities that are either (a) included in the transmission plan and developed by the private entity that was awarded a concession as a result of the successful review of a private initiative proposal, or (b) not included in the transmission plan.

The projected expansions of the transmission system identified in the Peruvian transmission plan are now part of the SGT. The government also introduced tender procedures to call private investors interested in building the projected lines of the SGT. Under SGT concession agreements, the concessionaire shall build the lines and be responsible for their operation and maintenance. Recovery of the investment during the term of the contract (30 years) is guaranteed thereunder. The concessionaire owns the transmission assets during the term of the contract. Upon expiry of the contract the assets return to the State which shall call a new tender if the lines are required at such time for the operation of the system.

Transmission lines of interest to generation plants, distribution networks or large consumers are part of the SCT. The lines of the SCT included in the Transmission Plan and certain projects that exclusively serve the demand, as defined by the government, may be subject to tenders for the granting of SCT concession agreements for 30 years. The rest of the SCT projects are subject to the general regime in which the owners of the SCT lines (for example, the generation companies building them to connect their plants to the system) are the holders of the respective definitive transmission concession and own the transmission assets through the term of the concession.

Open Access Regime

The electricity transmission is a public service according to Peruvian law; such service is subject to open access regulations, which imply that the owner of the infrastructure where the connection to the SEIN will take place is obliged to allow the third parties to connect to the SEIN through its transmission facilities. However, third parties requesting access to a transmission system have the obligation to assume the costs of any additional investment required to increase the connection capacity, if required to make the interconnection feasible. The terms and conditions of the required new investments shall be negotiated in the interconnection agreement.

If a private interconnection agreement is not reached through private negotiation, a request for an interconnection mandate can be filed before the Organismo Supervisor de la Inversion en Energia y Mineria, or

 

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OSINERGMIN, who will determine the conditions applicable to the connection, if it is technically feasible. To that end an assessment of the different connection possibilities shall be submitted to OSINERGMIN by the applicant to determine the most efficient technical solution.

The participation of OSINERGMIN shall guarantee and enforce compliance with the legal principle of open access to transmission and distribution networks. An interconnection mandate establishes the conditions under which the interconnection shall take place. The parties usually prefer to reach an agreement establishing those conditions. However, in cases where an agreement is not feasible due to the pre-existence of previous interconnection commitments with other companies, OSINERGMIN has been willing to grant new interconnection mandates as long as there is available capacity.

Tariff Regime

The SGT is compensated through the tariff base, which is the authorized annual remuneration for facilities belonging to the SGT. The tariff base is established in annual amounts and includes the following: (i) remuneration of investments (including adjustments), which is calculated based on a 30-year recovery period applying a 12% rate of return, (ii) efficient operating and maintenance costs, and (iii) the liquidation of imbalances between the authorized tariff base for the previous year and the proceeds obtained during that year.

The tariff base will be paid through the (i) tariff income and (ii) the transmission toll. The tariff income is paid monthly by the electricity generation companies in proportion to their respective capacity income. The transmission toll is paid by the electricity generation companies based on their collection of the transmission toll paid by their respective customers pursuant to Article 26 of Law 28832 and Article 27 of the Transmission Rules, or Reglamento de Transmision, approved by the Supreme Decree No. 027-2007-EM.

The electricity generation companies are paid by customers via capacity charges and energy charges established in their respective supply contracts. These capacity charges include a transmission toll per unit of peak demand ($ per kW-month). Customers pay a monthly demand charge determined by multiplying this capacity charge by the peak demand. This demand charge includes the amount needed to cover the costs to be paid for the SGT.

The monthly payments to be made by electricity generation companies to the transmission companies are calculated by the COES, taking into account the actual demand of their customers. A portion of the amount collected by the electricity generation companies from customers is allocated to the transmission companies that own facilities in the SGT. As such, electricity generation companies collect the money required to pay the SGT facilities from customers.

Non-regulated customers and distribution companies that supply electricity to non-regulated customers pay these demand charges when they buy energy in the short-term market. Non-regulated customers include large electricity consumers with a power demand of over 2,500 kW and customers with power demands between 200 kW and 2500 kW that may choose to be regulated customers or not. Non-regulated customers may freely negotiate their energy prices with suppliers.

The SCT and the lines of the old STS are remunerated on the basis of the annual average cost approved by OSINERGMIN. The applicable tariffs and their respective actualization formulas are approved by OSINERGMIN every four years.

Penalties

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power services approved by Supreme Decree No. 020-97-EM and the National Power Code, may result in the imposition of penalties, fines and restrictions. In addition to these penalties, fines and restrictions, if our concession is terminated due to the breach of obligations under the Concession Agreements, the Ministry of Energy may appoint an intervenor to supervise the operations related to the concession to ensure the continuity in the provision of the service, and the compliance with applicable laws and regulations.

If the concessionaire suspends or interrupts the service for reasons other than regular maintenance, repairs, force majeure events or breaches by customers under their contracts, the concessionaire may be required to indemnify our customers for the damages caused by any such service interruption, in accordance with applicable regulations. In addition, the OSINERGMIN could impose penalties, including, among others, (a) admonishment, (b) successive fines, depending on the nature and effect of the interruption and its frequency, (c) temporary suspension of activities, and (d) definitive suspension of activities and the provisional administration of operations by an intervenor, if a termination event occurs and the Ministry of Energy notifies of its desire to terminate the SGT concession agreement.

Electricity Legal Framework

The principal laws and regulations governing the Peruvian power sector, or the Power Legal Framework, are: (i) the Power Concessions Law, or Ley de Concesiones Electricas, PCL), approved by Law No. 25844, and its rules (Supreme Decree No. 09-93-EM); (ii) the Law to Ensure the Efficient Development of Electricity Generation, or Ley para Asegurar el Desarrollo Eficiente de la Generacion Electrica, approved by Law No. 28832, or Law No. 28832; (iii) the Transmission Rules, or Reglamento de Transmision, approved by the Supreme Decree No. 027-2007-EM, or the Transmission Rules; (iv) the General Environmental Law (Law No. 28611); (v) the Rules for the Environmental Protection in Power Activities (Supreme Decree No. 029-94-EM); (vi) the Power Sector Antitrust Law (Law No. 26876) and its regulations (Supreme Decree No. 017-98-ITINCI); (vii) the Laws creating the Supervisory Agency of Investment in Energy and Mining (Law No. 26734 and Law No. 28964); (viii) the Supervisory Agency of Investment in Energy and Mining Rules (Supreme Decree No. 054-2001-PCM); (ix) the Regulatory Agencies of Private Investment in Public Services Framework Law (Law No. 27332); and (x) the Legislative Decree that promotes investment in the generation of power through renewable resources (Legislative Decree No. 1002) and its regulations (Supreme Decree No. 012-2011-EM).

These laws regulate how to enter the electricity sector (applicable permits and licenses); the main obligations of the different participants of the electricity market (generators, transmission companies and distribution companies); remuneration systems for the different market participants; rights of electricity consumers and the attributions of the competent authorities.

Other relevant laws are: (i) the Public Consultation Law and its regulations (Law No. 29758 and Supreme Decree No. 001-2012-MC) for projects that may affect rights of indigenous and native communities and (ii) Law of National Patrimony (Law 28296) and relevant regulations (Supreme Resolution No. 004-2000-ED) for obtaining the CIRA which is issued by the Ministry of Culture, certifying there are no archaeological remains in an area. Prior to performance of any activity or construction works, titleholders shall obtain the corresponding CIRA.

Some of the main aspects of Peru’s regulatory framework concerning its power sector are: (i) the separation between the power generation, transmission and distribution activities; (ii) unregulated prices for the generation of power supplied to unregulated customers; (iii) regulated prices for the generation of power supplied to regulated customers; (iv) regulated prices applicable to transmission and distribution of power for both regulated and unregulated customers; and (v) the private administration of the SEIN, according to the principles of efficiency, cost reduction, guaranty of quality and reliability in the provision of services.

 

 

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All entities that generate, transmit or distribute power to third parties in Peru, including self-generators and co-generators that sell their excess capacity and energy in the SEIN, are regulated by the Power Legal Framework.

Although significant private investments have been made in the Peruvian power sector and independent entities have been created to regulate and coordinate its oversight, the Peruvian government still retains ultimate oversight and regulatory control. In addition, the Peruvian government owns and controls various generation and distribution companies in Peru.

The Guaranteed Transmission System—SGT Concession Agreement

ATN and ATS, as concessionaires, have SGT concession agreements granted by the Peruvian government as a result of a public tender.

Under the SGT concession agreement, the Ministry of Energy grants the concession necessary to construct, develop, own, operate, and maintain the transmission lines and substations comprising a project to provide electricity transmission services.

The SGT concessionaires are not obliged to pay the grantor any consideration for the SGT concession agreement or for the utilization of the contracted concessions.

The grantor is required to impose easements required for the execution of the project upon accordance with applicable laws, but it does not assume the costs associated with such easements.

Upon request, the grantor is also required to use its best efforts to assist in obtaining licenses, permits, authorizations, concessions and other rights when the owner of the project complies with the legal requirements to obtain them and they are not granted on a timely basis by the competent authorities.

In this case, the concessionaire shall build the lines and be responsible for their operation and maintenance. The recovery of the investment during the term of the contract (30 years) is guaranteed thereunder. The concessionaire owns the transmission assets during the term of the contract. Upon expiry of the contract the assets return to the state, which shall call a new tender if the lines are required at such time for the operation of the system.

Revenues

The revenues of the project are established under the terms of the SGT concession agreement. In addition, the revenues of the project are funded by the entire Peruvian electric transmission system.

In effect, the compensation for facilities that are part of the SGT is allocated to customers by OSINERGMIN according to the amounts of investment, operational and maintenance costs set forth in the SGT concession agreement. The SGT will receive monthly compensation from the generation companies that collect the tariff base from their customers. Their compensation will be paid on a monthly basis and these monthly payments are determined by the COES, following the compensation established annually by OSINERGMIN.

As of the commercial operation date, the owner of a project receives the revenue from payments of the tariff base pursuant to the SGT concession agreement. The calculation of the tariff base is based on: (i) an amount which represents a return on investment, including operation and maintenance costs and (ii) the amount determined on May 1 of each year by OSINERGMIN, in order to compensate for any intra-year difference between the compensation we should have received in the immediately preceding tariff year in U.S. dollars and the amount actually paid in Peruvian nuevos soles, determined at the exchange rate published in the Official Gazette “El Peruano” on the last working day prior to the fifteenth day of the month following the relevant month for which the services were charged to the electricity generation companies.

 

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Pursuant to the SGT concession agreement, the receipt of the tariff base will be (i) fixed for the entire life of the concession and (ii) indexed annually on May 1 to the U.S. Finished Goods Less Food and Energy Index, published by the U.S. Department of Labor (utilizing the last definitive index available on the last day of December of the previous year as the relevant base date for the first such adjustment). See “—Tariff Regime.”

Regulation in Spain

On November 26, 1997, the European Union published a report, or White Paper, which outlined a strategy and a community-wide action plan aimed at doubling energy production from renewable energy sources in the European Union from 6% in 1996 to 12% by 2010. The White Paper proposed a number of measures to promote the use of renewable energy sources, including measures designed to provide renewable energy sources better access to the electricity market. The Kyoto Protocol, ratified by the EU and its Member States on May 31, 2002, imposed a target of reducing EU emissions of greenhouse gases by 8%.

Directive 2009/28/EC on the Promotion of the Use of Energy from Renewable Sources of the European Parliament and of the Council of the European Union, or the 2009 Renewable Energy Directive, set mandatory national overall targets for each Member State consistent with at least 20% of EU total energy consumption coming from renewable energy sources by 2020. In order to comply with these mandatory renewable energy targets, all EU Member States, including Spain, were required to develop a national action plan, called a National Renewable Energy Action Plan, or NREAP. Spain’s NREAP was issued on June 30, 2010 and sent to the European Commission.

In its NREAP, Spain set a target of 22.7% for primary energy consumption to be supplied by renewable energy sources and a target of 42.3% of total electricity consumption to be supplied by renewable energy sources by 2020.

In 2011, a new Renewable Energies Plan, referred to as REP 2011-2020, was developed by the European Parliament and the Council of the European Union under the 2009 Renewable Energy Directive that added a new target to the 2009 Renewable Energy Directive, a minimum of 10% of transportation energy consumption to be supplied from renewable energy sources in each Member State by 2020.

In Spain, these targets mean that energy from renewable sources should represent at least 20% of total energy consumption by 2020, consistent with the EU target, with a minimum of 10% of transportation consumption to be derived from renewable sources by that same year.

Article 3.3.(a) of the 2009 Renewable Energy Directive states that in order to reach the targets set for 2020, Member States may apply support schemes and incentives for renewable energy. These support systems or incentives are different in each country, but the most common are:

 

(i)

Green certificates. Producers of renewable energy receive a “green certificate” for each MWh they generate and suppliers of energy have an obligation to purchase part of the energy that they supply from renewable sources.

 

(ii)

Investment grants and direct subsidies. These help defray the costs of installing renewable energy generation plants.

 

(iii)

Tax exemptions or relief. These include ITCs, cash grants in lieu of tax credits and accelerated depreciation, among others.

 

(iv)

System of direct support of prices. These include regulated tariffs and premiums and involve a regulatory guarantee to purchase energy generated by a renewable energy plant for an allotted period of time at a fixed tariff per kWh, for a maximum annual number of hours, so that the producer is ensured of a reasonable return on its investment.

 

 

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Solar Regulatory Framework Applicable to Concentrating Solar Power Plants Currently in Operation

The applicable legal framework for Concentrating Solar Power plants already in operation is set out in three primary legal instruments:

 

(i)

Law 24/2013, of December 26, 2013 the Electricity Sector Act, referred to as the Electricity Act;

 

(ii)

New Royal Decree, currently under approval process and expected to be approved in 2014, regulating electricity production from renewable energy sources, combined heat and power and waste, referred to as Proposed Royal Decree 2014; and

 

(iii)

New Ministerial Order, currently under approval process and expected to be approved in 2014 establishing the compensation criteria applicable to certain electricity generation plants using renewable energy sources, combined heat and power and waste, referred to as the Revenue Order.

Primary Rights and Obligations under the Electricity Act

The Electricity Act eliminates a previously existing distinction between ordinary electricity producers and those using renewable energy sources in their production of electricity, though it continues to recognize the following rights for producers with facilities that use renewable energy sources:

 

(i)

Priority off-take. Producers of electricity from renewable sources will have priority over conventional generators in transmitting to off-takers the energy they produce over conventional generators under equal market conditions, subject to the secure operation of the national electricity system and based on transparent and non-discriminatory criteria.

 

(ii)

Priority of access and connection to transmission and distribution networks. Producers of electricity from renewable energy sources will have priority in obtaining access and connecting to the grid, subject to the terms set forth in the regulations, on the basis of objective, transparent and non-discriminatory criteria.

 

(iii)

Entitlement to a specific payment scheme. Producers of electricity from renewable sources will receive specific reimbursement that shall not exceed the minimum amount necessary to cover their costs. This enables them to compete on a level playing field with the other, non-renewable technologies on the market while achieving a reasonable return on investment.

The significant obligations of the renewable energy electricity producers under the Electricity Act include a requirement to:

 

(i)

Offer to sell the energy they produce through the market operator even when they have not entered into a contract and so are excluded from the bidding system managed by the market operator.

 

(ii)

Maintain the plant’s planned production capacity. Power lines, which include connections with the transmission or distribution network and transformers, are considered part of the production facility.

 

(iii)

Contract and pay the corresponding fees, whether directly or through their representatives, to the transmission or distribution companies to which the renewable energy facilities are connected in order for their power to be fed into the grid.

Registration on Public Registers

The Electricity Act and Proposed Royal Decree 2014 require electricity generation facilities to be entered on the official register of electricity production plants maintained by the Ministry of Industry, Energy and Tourism.

The autonomous regions may keep their own registers of electricity generation plants they have authorized if such plants have a capacity of 50 MW or less. The registration details of these plants must be provided to the Ministry of Industry, Energy and Tourism electronically.

 

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Solaben 2 and Solaben 3 are on the register of the autonomous region Extremadura and the Ministry of Industry, Energy and Tourism register.

To receive their facility-specific reimbursement, renewable energy facilities are required under the Electricity Act and Proposed Royal Decree 2014 to be listed on a new register entitled the Specific Payment System Register, Registro de Regimen Retributivo Especifico. Unregistered plants will only receive the pool price.

The first transitional provision of Proposed Royal Decree 2014 states that power plants based on renewable sources recognized under the previous economic regime, as in the case of Solaben 2 and Solaben 3, will be automatically included in the Specific Payment System Register.

Change of Compensation System Applicable to Concentrating Solar Power Plants

Royal Decree 9/2013 introduced a change in the payment system applicable to existing electricity production facilities using renewable energy sources to guarantee the financial stability of the electric system. The purpose of Royal Decree 9/2013, which entered into force on July 14, 2013, was to adopt a series of measures to ensure the sustainability of the electric system and to combat the shortfalls between electricity system revenues and costs, referred to as the tariff deficit.

The measures adopted were focused primarily on the following areas: (i) the legal and financial regime for existing electricity production facilities using renewable energy sources, co-generation and residual waste; (ii) the remuneration regime for transport and distribution activities; (iii) Spain’s guarantee of the Securitization Fund to cover the tariff deficit; and (iv) certain aspects related to capacity payments, assumption of the cost of the subsidized tariff and a review of access charges.

Royal Decree 9/2013 established an entirely new remuneration system, abolishing the remuneration system based on a regulated tariff applicable to electricity production facilities using renewable energy sources (including facilities in operation at the time that Royal Decree 9/2013 entered into force).

Prior to the adoption of Royal Decree 9/2013, electricity production facilities using renewable energy sources received revenues tied to their electricity produced according to their power output. This involved receiving feed-in tariffs, in €/kWh, that were split into two components: (i) the pool price of electricity and (ii) an equivalent premium, consisting of the difference between the pool price and the set feed-in tariff for each type of plant (feed in tariff = pool price + equivalent premium). This revenue was received for a maximum annual number of hours and for a pre-determined number of years, depending on the technology used in each case. For any additional hours produced, producers received the pool price.

The repealed economic scheme was applied on a transitional basis until new provisions were approved to fully implement the new remuneration system. Settlements made after July 14, 2013 were made in accordance with the previous regime until the new implementing regulations have been adopted. However, following the implementation of these new regulations, payments made during this interim period will be recalculated in accordance with the new regulations. The difference between the amounts received under the prior regime and those calculated under the new regime will be deducted from the first six settlements that follow the approval of the new implementing regulations.

New System

Under the third final provision of the Electricity Act, at the proposal of Ministry for Industry, Energy and Tourism, or the Ministry, the Spanish Government will approve a new royal decree regulating the legal and economic framework for currently operating renewable energy power plants with Proposed Royal Decree 2014. This new remuneration model, based on the third final provision of the Electricity Act, is adjusted to the criteria set out in article 30.4 of the Electricity Act 1997, under Royal Decree 9/2013. We will continue to receive remuneration under the previous regime until the implementation of the Proposed Royal Decree 2014.

 

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According to these criteria, producers will now receive: (i) the pool price for the power they produce and (ii) a payment based on the standard investment cost for each kind of plant (without any relation whatsoever to the amount of power they generate). This payment based on investment (in €/MW of installed capacity) will be supplemented (in cases of technologies with running costs in excess of the pool price) with an “operating payment” (in €/MWh produced).

The principle driving the new economic regime is that the incentives that an electricity producer receives should be equivalent to the costs that they are unable to recover on the electricity market where they compete with non-renewable technologies. The new economic regime seeks to allow a “well-run and efficient enterprise” to recover the costs of building and running a plant, plus a reasonable return on investment (project internal rate of return). For plants eligible for a premium when Royal Decree 9/2013 entered into force, the reasonable return will be 7.503% pre-tax, and will apply until December 31, 2019.

According to Proposed Royal Decree 2014, the remuneration for investment in respect of plants that were already in operation during the first statutory period (from July 14, 2013 to December 31, 2019) is calculated as follows:

 

(i)

The “standard per-MW investment value” is added to the “standard per-MW operating cost” (both updated from July 2013 with a 7.503% rate of return); i.e., what it would have cost a well-run and efficient enterprise to build, maintain and run the facility from its start-up until the time Royal Decree 9/2013 came into force.

 

(ii)

From the resulting total, the “standard per-MW total revenue valued at the electricity pool price,” earned by each type of plant from its start-up through entry into force of Royal Decree 9/2013, also updated applying the 7.503% rate of return is subtracted.

 

(iii)

The result (the standard per-MW investment value plus standard per-MW operating cost minus standard per-MW total revenue) is the “net investment value,” i.e., the costs unrecovered by the plant owner as of July 14, 2013.

Accordingly, under Proposed Royal Decree 2014, the returns received by the owners of plants in excess of 7.503%, from start-up until Royal Decree 9/2013 took effect, would serve to reduce the unrecovered net investment value as of July 14, 2013.

Operating payments will only be available for those facilities whose costs exceed the estimated average pool price. However, the Ministry of Industry, Energy and Tourism can cap operating payments at a maximum number of hours.

Payment Factors for Concentrating Solar Power Plants

The payment system applicable for each plant is based on various criteria considered by the Ministry of Industry, Energy and Tourism and includes the specific technology used, amount of power produced relative to operating costs, age of the facility and any other differentiating factor deemed necessary to consider in applications of the payment system.

The regulations recognize six types of solar thermal plants: (i) parabolic trough collectors without a storage system, (ii) parabolic trough collectors with a storage system, (iii) central or tower receivers without a storage system, (iv) central or tower receivers with a storage system, (v) fresnel linear collectors and (vi) solar-biomass hybrids.

To determine the payment system applicable to each plant, the following factors are considered:

 

(i)

Net investment value. This consists of a standard amount per MW for each type of plant, calculated by the method set out in Proposed Royal Decree 2014, which is the amount invested in the plant and not depreciated as of July 14, 2013.

 

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(ii)

Useful life of the plant. For solar thermal plants this is 25 years.

 

(iii)

Return on investment. Considering the net asset value determined on the basis of a standard cost per MW built, an amount is set per unit of power, which enables investment costs that cannot be recovered through the pool price to be recouped over the useful life of the plant.

 

(iv)

Operating remuneration. An amount is set per unit of power and hour that, added to the pool price, enables the producer to recoup all the plant’s operating and maintenance costs. Operating expenses include the cost of land, electricity, gas and water bills, management, security, corrective and preventive maintenance, representation costs, the Spanish tax on special immovable properties, insurance, applicable generation charges and a generation tax which is equal to 7% of total revenue.

 

(v)

Maximum number of operating hours. A maximum number of hours is set for which each plant type can receive the operating subsidy.

 

(vi)

Operating threshold. Plants must operate for more than a set number of hours per year to receive the return on investment and operating subsidy.

 

(vii)

Minimum operating hours. Plants that cross the operating threshold but operate for fewer hours than the annual minimum hours receive a lower subsidy.

The payment criteria established in respect of Solaben 2 and Solaben 3 are set forth below:

 

		Useful Life				Return on Investment 2014 (euros/MW)				Operating Remuneration 2014 (euros/GWh)				Maximum Hours				Minimum Hours				Operating Threshold
Solaben 2			25 years				403,216				37,491				2,040				1,224				714
Solaben 3			25 years				403,216				37,491				2,040				1.224				714

Regulatory Periods

Payment criteria are based on prevailing economic conditions in Spain, demand for electricity and reasonable profits for electricity generation activities and can be revised every six years. The first regulatory period commenced on July 14, 2013, the date on which Royal Decree 9/2013 came into force, and will end on December 31, 2019.

The definitions and values of all payment criteria can be changed at the end of each regulatory period, except for a plant’s useful life and the value of a plant’s initial investment that is recouped through the specific return on investment.

Unless reviewed, payment criteria will be considered to be extended for the subsequent regulatory period.

Reasonable Rate of Return

Article 14 of the Electricity Act provides that a reasonable return on investment is calculated on the basis of the average pre-tax yield of Spanish government 10-year bonds on the secondary market.

For plants that are already in operation, the reasonable return over the regulatory life of the plants is based on the average pre-tax yield on Spanish government 10-year bonds on the secondary market for the preceding 10 years, plus 300 basis points. The reasonable rate of return has been set at 7.503% during the first regulatory period from July 14, 2013 through December 31, 2019.

Under no circumstances will amounts received by producers for electricity generated before July 14, 2013 be required to be returned or reimbursed under the new system.

 

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Before the start of a new regulatory period, a revised reasonable return can be established for each plant type, calculated as the average yield on Spanish government 10-year bonds on the secondary market in the 24 months through the month of May preceding the new regulatory period, plus a spread.

This spread is based on the following criteria:

 

(i)

Appropriate profit for this specific type of renewable electricity generation and electricity generation as a whole, considering the financial condition of the Spanish electricity system and Spanish prevailing economic conditions; and

 

(ii)

Borrowing costs for electricity generation companies using renewable energy sources with regulated payment systems, which are efficient and well run, within Europe.

The next regulatory period will begin on January 1, 2020.

Funding the Tariff Deficit

The new Electricity Act also states that from January 1, 2014, tariff deficit amounts would no longer be paid for, as they had been previously, by the five major Spanish utilities. Instead, they will be paid by the companies that receive “regulated payments,” including distributors, transportation companies, producers of electricity from renewable plants, companies receiving capacity payments and others. Each of these entities will contribute to paying down the tariff deficit in proportion to the costs that they represent for the electricity system, and can recover these contributions in the following five years, plus interest at a market rate.

Access Fee

Royal Decree 14/2010 was passed in order to eliminate the shortfalls between electricity system revenues and costs, referred to as the tariff deficit in the electricity sector.

The First Transitional Provision of Royal Decree 14/2010 provided that the owners of electricity production facilities pay a fee for access to the grid to the transmission and distribution companies (this access previously having been provided at no cost) from January 1, 2011. During the interim period, the access fee payable is: (i) calculated at €0.5 per MWh delivered to the network or (ii) any other amount that the Ministry of Industry, Energy and Tourism establishes.

Royal Decree 1544/2011 implemented the First Transitional Provision of Royal Decree 14/2010 and confirmed the interim access fee imposed on electricity producers (€0.5 per MWh), subject to the adoption of a final method for calculating the access fee.

Electricity Sales Tax

On December 27, 2012, the Spanish Parliament approved Law 15/2012, which became effective on January 1, 2013, or Law 15/2012. The aim of Law 15/2012 is to try to combat the problem of the so-called tariff deficit, which reached approximately €28 billion as of December 2013.

Law 15/2012 provides for an electricity sales tax which is levied on activities related to electricity production. The tax is triggered by the sale of electricity and affects ordinary energy producers and those generating power from renewable sources. The tax, a flat rate of 7%, is levied on the total income received from the power produced at each of the installations, which means that every calendar year, Concentrating Solar Power plants will be required to pay 7% of the total amount which they are entitled to receive for production and incorporation into the electricity system of electric power, measured as the net output generated.

 

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Tax Incentive of Accelerated Depreciation of New Assets

Under provisions of the Spanish Corporate Income Tax Act, tax-free depreciation is permitted on investments in new material assets and investment properties used for economic activities acquired between January 1, 2009 and March 31, 2012.

Taxpayers who made or will make investments from March 31, 2012 through March 31, 2015 in new material assets and investment properties used for economic activities are permitted to take accelerated depreciation for those assets subject to certain limitations. The accelerated depreciation is permitted if:

 

•

40% of the tax base before the amortization or depreciation and before the offset of tax loss carryforwards for taxpayers (subject to requirements to keep up employment levels); or

 

•

20% of the tax base before the amortization or depreciation and before the offset of tax loss carryforwards for taxpayers (without employment requirements).

Most of the investment in Solaben 2 and 3 was undertaken within the regime that applied between January 1, 2009 and March 31, 2012.

These limitations do not apply in respect of companies that meet the requirements set forth in article 108.1 of the Spanish Corporate Income Tax Act related to the special rules for enterprises of a reduced size.

Regulation in Brazil

Electric transmission operations are subject to significant regulation in Brazil.

The Governmental Policy and Legislative Framework for the Electricity Sector

The electricity sector in Brazil has undergone two major institutional reforms in the last decades which results in its current form: the first in the 1990s and another in 2003, which aimed at modifying the rules applying to the SIN. The first change in the sector occurred after the enactment of Law No. 8,987 of 1995, as amended, which established the system for the concessions and permissions for rendering public services, or the Concessions’ General Act, and with the enactment of Law No. 9,074 of 1995, as amended, which sets forth specific rules for the concession of electricity public services. This law, inter alia:

 

•

established the granting, duration and extension of concessions and permissions;

 

•

set forth the free access principle for the electric transmission and distribution systems;

 

•

released free consumers (as defined below) from the commercial monopoly of distribution concessionaires, allowing them to choose their supplier; and

 

•

introduced the independent power producer and the cell producer agents.

Law No. 9,074 of 1995 is regulated by Decree No. 1,717 of 1995, which establishes the procedures for extending the concessions granted before the enactment of the Concessions’ General Act for a period up to twenty years, and by Decree No. 2,003 of 1996, governing the independent producers’ and self-producers’ system. In addition, Decree No. 7,805 of 2012, which regulates the Provisional Measure, or Medida Provisoria, No. 579 of 2012, later converted into Law No. 12,783 of 2013 sets forth the rules for further extending the concession contracts up to 30 years, for one period only.

Law No. 9,427 of 1996, as amended, inter alia, created ANEEL, the regulatory agency concerned with supervising the production, electric transmission, distribution and trading of electricity, and it is regulated by Decree No. 2,335 of 1997. Such law granted ANEEL the authority, inter alia, to run public tenders for concessions and permissions, as well as to execute and manage the agreements for delivering public services and to grant certain authorizations. Law No. 9,478 of 1997, as amended, created the National Committee on Energy Policy, or Conselho Nacional de Politica Energetica, chaired by the Minister of Mining and Energy with the duty of advising the President of the Republic on the national policies in this domain.

 

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The first phase of the reform was concluded with the enactment in May 1998 of Law No. 9,648, later amended, which regulates competition in the electricity sector. Among many other provisions, it sets forth rules for:

 

(i)

the trading, import and export of power;

 

(ii)

the division, into separate agreements, of the purchase and sale of energy, and the free access to the electric transmission and distribution systems;

 

(iii)

the creation of the Electric System National Operator, Operador Nacional do Sistema Eletrico, or ONS, a legal entity organized under the private law, in charge of the coordination and operational control of the facilities for the electric and power generation and power transmission of interconnected electric systems in Brazil; and

 

(iv)

the free negotiation of energy, within the scope of the Wholesale Market of Electricity, Mercado Atacadista de Energia Electrica, or MAE, to be created by a market agreement.

The second phase of the reform redefined the sector’s institutional model, mainly concerning the energy market, by setting forth as chief goals the need for the system’s expansion while keeping tariffs low and competition present in power generation.

The new institutional framework was established by Law No. 10,848 and Law No. 10,847 of 2004 in an effort to restructure the electricity industry to better provide consumers with a secure electricity supply combined with low tariffs by expanding electricity generation and services.

Law No. 10,848 created two co-existing energy markets: a regulated market, for the protection of customers, and a free market to encourage consumers which are able to buy directly from producers on a competitive basis, or free consumers. Law No. 10,848 authorized the creation of the Chamber of Electric Energy Trading, or Camara de Comercializacao de Energia Eletrica, a non-profit private entity, functioning under the supervision of ANEEL to manage the agreements for the purchase and sale of energy in the regulated contracting environment and the ascertainment and settlement of contractual differences in the free contracting environment. This law further authorized the creation of the Committee on the Monitoring of the Electricity Sector, or Comite de Monitoramento de Setor Energetico, under the aegis of the government, to monitor the supply conditions of the electricity market and the advising of preventive actions for guaranteeing this supply.

On May 28, 2009, Provisional Measure No. 450 of 2008 became Law No. 11,943, as amended, which authorizes the federal government to participate in the Guarantee Fund for Electric Energy Enterprises, or Fundo de Garantia a Empreendimentos de Energia Eletrica. Such fund aims to provide financial guarantees proportional to the participation, direct or indirect, of federal or state companies of the electric industry in special purpose companies, created for the development of electric-related projects in connection with the Growth Acceleration Program, or Programa de Aceleracao do Crescimento and other strategic programs appointed by an act of the Executive Branch.

More recently, the government passed Provisional Measure No. 577 of 2012, later converted into Law No. 12.767 of 2012, which establishes specific rules for the termination of concessions in the event of bankruptcy or forfeiture and for intervention by the granting authority, acting through ANEEL, in the management of concessionaires in order to ensure the adequate rendering of services and compliance with contractual, regulatory and legal provisions. The goal of this law is to ensure the continuation of the service and its rules on administrative intervention are stricter than the ones of the Concessions’ General Act.

In March 2014, the federal government announced new measures to help distribution concessionaires reduce the impact on consumers’ electricity bill caused by the use of electricity originated from thermal power plants and by the higher cost of energy in the spot market. The aid amount is estimated to be R$12.4 billion for this year and will be borne by the federal government, consumers and agents. One of the measures recently put in place

 

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has enabled distribution concessionaires to obtain loans from the CCEE, who will get the needed funds through loans from private or public entities. Such funding is intended to allow concessionaires to cover for the immediate higher cost of energy, which shall not be reverted to the consumers until 2015. Further details of this operation are yet to be announced. Another measure already implemented is a new energy auction, scheduled for April 25, in which the distributors will be able to purchase electricity for immediate supply. Before the enactment of the MP 641 of 2014, as regulated by Decree No. 8.213 of 2014 and Portaria MME No. 118 of 2014, there was a minimum one year gap between the purchase and the supply of energy. That gap in some cases resulted in concessionaries being forced to pay more for energy in the spot market.

The Governmental or Administrative Authorizations Required for the Construction and Operation of Electric Transmission Networks

Before the auction for the concession of electric transmission lines, the environmental impact assessment and environmental impact reports shall be conducted and must be approved by the proper environmental agency. After the auction, the concession is granted by a presidential decree, followed by the execution of the concession agreement, which is signed by and registered and filed with ANEEL. Next, the concessionaire should apply for ANEEL’s approval of the Basic Project for Power Transmission Facilities relating to the concession. The previous license (licenca previa), which is the first environmental permit that allows the development of the environmental studies, and the installation license (licenca de instalacao), which is the permit that authorizes the construction of the project, should be obtained at different stages from the environmental agencies. The Declaration of Public Interest from ANEEL, the tree cutting authorization and the operation license (licenca de operacao) issued by the environmental agency, as well as the release certificate issued by the ONS are also required.

The Requirements That Must Be Met to Obtain Access to such Public Service

The regulation in force sets forth that the rendering of transmission services shall be preceded by the execution of a Transmission Agreement and of an Agreement for the Rendering of Supplementary Services, or Contrato de Servicos Anciliares. There are three different types of Transmission Agreements: (i) Agreement for the Rendering of Transmission Services, or CPST; (ii) Agreement for the Use of the Transmission Networks, or CUST; and (iii) Connection Agreement. The CPST is executed between the ONS and the concessionaire. The CUST is executed among the ONS, the concessionaire, represented by the ONS, and the user of the transmission network. These users may be: (i) agents holding a concession or a permission for the distribution of electricity; (ii) power generation agents directly connected to the basic grid or not connected to the basic grid but operating centrally, whether concessionaires or authorized companies; (iii) consumers connected to the basic grid; and (iv) importers and exporters of electricity directly connected to the basic grid.

There are three types of Connection Agreements: (i) Agreement for the Connection to the Transmission Network, or Contrato de Conexao do Sistema de Transmissao; (ii) Agreement for Facilities’ Sharing, or Contrato de Compartilhamento de Instalacoes; and (iii) Agreement for the Connection to the Transmission Network—Adjustment Term, or Contrato de Conexao ao Sistema de Transmissao—Termo de Ajuste. These agreements are executed between the transmission concessionaires and the connecting agents, while the ONS is an interested third party to such agreements.

There is also the Financial Guarantee Contract, or Contrato de Constituicao de Garantia, which is an agreement between the ONS, acting on its own behalf and on behalf of the transmission concessionaire, and the custodian bank which provides ONS with access to funds available in user-designated bank accounts in the event the latter fails to satisfy payments owed to the transmission concessionaires and to ONS under the corresponding CUST.

 

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Governmental Incentives to Encourage Expansion of the Electric Transmission Grid

There are special credit lines available to entrepreneurs from the National Bank for Economic and Social Development, or Banco Nacional de Desenvolvimento Economico e Social. Also, Law No. 11,488 of 2007, as amended, created the Special Incentive Regimen for the Development of Infrastructure, or Regime Especial de Incentivos para o Desenvolvimento da Infraestrutura, or REIDI, a general tax incentive to infrastructure projects, which directly applies to the expansion of the electric transmission grids.

A recent innovation regarding the granting of the REIDI was established after the edition of Mines and Energy Ministerial Ordinance No. 274/2013, which stipulates all the data that is required in order to apply for this incentive, which includes, among other, the description of the project, technical and legal information, and the perspective of investment in equipment, materials and machines. All information required must be compiled in a specific petition and filed with ANEEL.

The Rates for the Provision of Electric Transmission Services

Electric transmission companies are remunerated through the Annual Authorized Revenue, or Receita Anual Permitida, or RAP, for the availability of their facilities to the ONS and for the rendering of transmission services to the users.

Charges and Tariffs Owed by Electric Transmission Concessionaires

The Electricity Services Inspection Fee, Taxa de Fiscalizacao de Servicos de Energia Eletrica, or TFSEE, was created by Law No. 9,427 of 1996, as amended, and regulated by Decree No. 2,410 of 1997. TFSEE is an annual fee payable directly to ANEEL in twelve monthly payments, and is calculated based on the type of service rendered by the concessionaire and in proportion to the size of the concession. It is equivalent to 0.4% of the annual economic benefit earned by the concessionaire. Electricity transmission concessionaires also must invest each year a minimum of 1% of their net operating revenues in electricity research and development.

Penalties

The regulation issued by ANEEL governs the imposition of sanctions against the participants of the energy sector and classifies the appropriate penalties based on the nature and importance of the breach (including warnings, fines, temporary suspension from the right to participate in public auctions for new concessions, licenses or authorizations and forfeiture). For each breach, the fine may be up to 2% of the concessionaire revenues (net of value-added tax and services tax) in the 12-month period preceding any assessment notice. In addition, electricity generation, distribution and electric transmission concessionaires are strictly liable for any direct or consequential damages caused to third parties as a result of inappropriate provision of electricity services at their facilities. In case ONS is incapable of determining liability for the damages to a particular concessionaire, permissionaire or authorized agent, or if the damages are caused by ONS, liability is proportionately allocated to the electric transmission, distribution and generation agents in accordance with the voting rights of each category under the ONS bylaws.

Reinforcements and Improvements

The granting authority may unilaterally amend the concession agreements, including in the event of alterations to the project or previously unforeseen specifications (such as a requirement to strengthen or to improve the current electric transmission facilities). A concessionaire is entitled to the economic and financial balance of the concession agreement and, therefore, receives additional revenues by way of amortization of its investments in the implementation of these reinforcements or improvements.

Until May 2005, a concessionaire’s obligation to implement strengthening actions, or Reinforcement, was subject to specific prior authorization from ANEEL, which would then set the corresponding additional revenues.

 

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Any improvement action, or Improvement, would not require prior authorization or additional revenues. The then-existing regulation, however, failed to clearly define Reinforcement and Improvement. Thus, on May 23, 2005, ANEEL issued Resolution No. 158, distinguishing the projects and installations that would be considered as reinforcements and those deemed to be classified as Improvements. In July 2011, Resolution No. 158 was replaced by Resolution No. 443.

Improvement is defined as any installation, replacement or remodeling of equipment in order to ensure regular, continued, safe and updated electricity transmission services, pursuant to the relevant concession agreement and network procedures. The costs incurred from improvements will not be taken into account in any subsequent revision of the RAP. Nonetheless, the concessionaire can claim for the reestablishment of economic and financial balance of the concession agreement.

Reinforcement is defined as the implementation of new electricity transmission facilities, or replacement or adjustment of existing facilities, as recommended in previously approved plans for the expansion of the power transmission network. It is subject to prior authorization by ANEEL and is intended to increase the electric transmission capacity or the reliability of the SIN, or to implement a physical alteration of the configuration of the electric grid or of a given facility. Through ANEEL Resolution No. 443, certain types of reinforcements may be implemented by transmission concessionaires directly, without prior authorization by ANEEL, provided that they are the result of a request by ONS aiming at expanding electric transmission capacity or the reliability of the SIN. In this case, however, ANEEL will not have previously established the additional revenues to which the concessionaire would be entitled for the implementation of such reinforcement. These revenues, therefore, are included in the annual revision of the RAP. In addition, Resolution No. 443 does not assure that all costs incurred by the concessionaire for the investments in reinforcements will be taken into account for establishing the relevant RAP.

Finally, concessionaires that are not subject to periodic revision of the RAP could be compelled to make investments within the scope of expansion plans or at the request of ONS, which would not require prior approval by ANEEL and, consequently, are not included in RAP. In such event, pursuant to Resolution No. 443, concessionaires will be entitled to apply for acknowledgement of the investments by means of a special revision of the RAP pursuant to a procedure and parameters not clearly defined by ANEEL, including time periods. The lack of a clear definition could result in mismatched investment disbursements and RAP payments. However, additional fixed revenues from revisions will be retroacted until the reinforcement operations begin.

 

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MANAGEMENT

Executive Officers and Directors

Below is a list of names and a brief account of the business experience of the persons appointed, or to be appointed, to serve as our executive officers and directors prior to the consummation of this offering.

 

Name		Age				Position
Manuel Sanchez Ortega			50			Director and Chairman of the Board
Santiago Seage			44			Chief Executive Officer and Director
Eduard Soler			35			Executive Vice President and Chief Financial Officer
Manuel Silvan			40			Vice President Taxes, Risk Management and Compliance
Emiliano Garcia			46			Vice President North America
Antonio Merino			47			Vice President South America
William B. Richardson			66			Director
Christopher Standlee			60			Director
Maria J. Esteruelas			42			Director
Eduardo Kausel			71			Director, independent
Daniel Villalba			66			Director, independent
Jack Robinson			72			Director, independent
Enrique Alarcon			71			Director, independent
Juan del Hoyo			69			Director, independent

Manuel Sanchez Ortega, Director and Chairman of the Board

Mr. Sanchez has served as our Chairman since our formation in December 2013. Mr. Sanchez joined Abengoa in 1989 as a software engineer. In 1995, he was named Executive Vice President in Mexico, where he was based for five years. In 2001, Mr. Sanchez was named general manager of Abengoa’s Information Technologies business, of which he was appointed the Chief Executive Officer in 2002 and Chairman in 2004, serving in that capacity until he was appointed Chief Executive Officer of Abengoa in October 2010, in which capacity he continues to serve. He holds a degree in Industrial Electrical Engineering from the ICAI in Madrid and has a Master’s degree in Business Administration from the Instituto Panamericano de Alta Direccion de Empresas (IPADE) in Mexico.

Santiago Seage, Chief Executive Officer and Director

Mr. Seage has served as our CEO since our formation. Prior to this appointment, he served as Abengoa Solar’s CEO beginning in 2006. Previously, Mr. Seage was Abengoa’s Vice President of Strategy and Corporate Development. Before joining Abengoa, he was a partner with McKinsey & Company. Mr. Seage holds a degree in Business Management from ICADE University in Madrid. Mr. Seage will remain an officer of Abengoa after this offering.

Eduard Soler, Executive Vice President and Chief Financial Officer

Mr. Soler has served as our Executive Vice President and CFO since our formation. Prior to that, he served as the corporate head of Abengoa’s concessions business and previously as Abengoa Solar’s head of strategy and business development. Prior to this, he was an engagement manager with McKinsey & Company in its corporate finance practice. Mr. Soler holds a Business Administration degree from Esade University in Barcelona and an MBA from Harvard University. Mr. Soler will remain an officer of Abengoa after this offering.

Manuel Silvan, Vice President Taxes, Risk Management and Compliance

Mr. Silvan has served as Vice President Taxes, Risk Management and Compliance since our formation. Prior to that, he served as Abengoa’s Vice President of Taxation beginning in 2007. Before joining Abengoa in

 

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1998, he worked for the legal and tax advisory firm of Garrigues. Mr. Silvan holds a degree in Economics and Business Science from Huelva University, a Master’s degree in Tax Consultancy from Cajasol Business Institute and an MBA from San Telmo International Institute. Mr. Silvan will remain an officer of Abengoa after this offering.

Emiliano Garcia, Vice President North America

Mr. Garcia currently serves as Vice President of our North American business. Based in Phoenix, Arizona, he is responsible for managing two of our key assets, Solana and Mojave. Mr. Garcia was previously the General Manager of Abengoa Solar in the United States and of the Solana Power Plant. Before that, he held a number of managerial positions in various Abengoa companies over two decades. Mr. Garcia holds a Bachelor’s degree in Engineering from Madrid Technical University.

Antonio Merino, Vice President South America

Mr. Merino currently serves as Vice President of our South American business. Previously, he was the Vice President of Abengoa’s Brazilian business, as well as the head of Abengoa’s commercial activities and partnerships in South America. Mr. Merino holds an MBA from San Telmo International Institute.

William B. Richardson, Director

Mr. Richardson was the 30th Governor of the State of New Mexico, from 2003 to 2011. He was U.S. Ambassador to the United Nations and Energy Secretary and has also served as a U.S. Congressman, chairman of the 2004 Democratic National Convention and chairman of the Democratic Governor’s Association. He is chairman of APCO Worldwide’s executive advisory service, Global Political Strategies and Special Envoy of the Organization of American States, Chairman of the International Council for Science and the Environment, as well as an advisor to Abengoa and member of Abengoa’s international advisory board.

Christopher Standlee, Director

Mr. Standlee currently serves as Executive Vice President of Global Affairs at Abengoa Bioenergy U.S. He also serves as co-chairman of the Biotechnology Industry Organization’s Industrial and Environmental Section Working Group. Mr. Standlee previously served as Vice President and General Counsel of Abengoa Bioenergy U.S., where he held operational responsibilities, until 2010. Before that, Mr. Standlee served as Vice President and General Counsel of the NASDAQ-listed company High Plains Corporation until its acquisition by Abengoa in 2002. He is a past chairman of the board of directors of the Renewable Fuels Association. Mr. Standlee received his undergraduate degree from Yale University in Political Science, and his Juris Doctorate from the University of Kansas.

Maria J. Esteruelas, Director

Ms. Esteruelas currently serves as the Executive Vice President of Latin America at Abengoa. Previously she was the Vice President of Concessions at one of Abengoa’s subsidiaries. Ms. Esteruelas has an Industrial Engineering degree from the Instituto Catolico de Artes e Industrias University and has a Master’s degree in Operations from the Instituto de Empresa in Madrid.

Eduardo Kausel, Director

Dr. Kausel is a Professor of Civil and Environmental Engineering at Massachusetts Institute of Technology, or MIT. Dr. Kausel is a senior member of various professional organizations and has extensive experience as consulting engineer. He is the author of more than a hundred technical papers and has a Doctorate and a Masters of Science from MIT, a post-graduate degree from Darmstadt University in Germany and a civil engineering degree from the University of Chile.

 

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Daniel Villalba, Director

Daniel Villalba was previously a Professor of Business Economics at the Universidad Autonoma de Madrid. He also previously served as the CEO of Inverban, a broker and investment bank, and independent board member of Vueling, an airline currently part of International Airlines Group, Abengoa and the Madrid Stock Exchange, as well as a board member of several private companies. He also has written more than fifty academic papers and books. Mr. Villalba holds a Master of Science in Operations Research from Stanford University, a Master of Science in Business Administration from the University of Massachusetts and a PhD in Economics from the Universidad Autonoma de Madrid.

Jack Robinson, Director

Mr. Robinson is a portfolio manager and partner at Brown Advisory, affiliates of which are investment advisers registered with the SEC. He also serves on the advisory board of several institutions including ACORE, Greener Capital Partners and Practically Green. He holds a Bachelor’s degree from Brown University.

Enrique Alarcon, Director

Dr. Alarcon has been a Professor of Engineering at several universities, as well as Chairman of the Spanish Royal Academy of Engineering and member of the Science and Engineering Sector of the “European Academy.” Dr. Alarcon holds a PhD in Engineering and a civil engineering degree from the Madrid Technical University and has written a dozen books and more than 100 articles and received many prizes in recognition of his work in the field of engineering.

Juan del Hoyo, Director

Dr. del Hoyo is a Professor of Economics at Madrid University. He has published several books and many articles on economy and finance. He holds a PhD in Economics, a Masters in Econometrics from the University of Southampton and is a telecommunications Engineer.

Board Practices

For purpose of the following disclosure, Mr. Sanchez, Mr. Seage, Mr. Richardson, Mr. Standlee and Ms. Esteruelas are considered Abengoa representatives.

Upon completion of this offering our board of directors will consist of ten directors, five of them independent. Under our articles of association, our board may consist of seven to thirteen members, and Abengoa will be entitled to nominate up to a majority of our directors for so long as Abengoa beneficially owns more than 50% of our outstanding shares.

We believe that this corporate governance structure of five independent directors out of a total of ten directors will help to avoid any potential conflicts of interest and will allow us to have stronger decision-making processes. Abengoa representatives will not vote on matters that represent or could represent a conflict of interests, including the evaluation of assets offered to us under the ROFO Agreement.

Our board of directors will be responsible for, among other things, overseeing the conduct of our business; reviewing and, where appropriate, approving, our long-term strategic, financial and organizational goals and plans; and reviewing the performance of our chief executive officer and other members of senior management.

Under English law, the board of directors of an English corporation is responsible for the management, administration and representation of all matters concerning the relevant business, subject to the provisions of the relevant constitution, statutes and resolutions adopted at general shareholder’s meetings by a majority vote of the shareholders. Under English law, the board of directors may delegate its powers to an executive committee or other delegated committee or to one or more persons, unless the shareholders, through a meeting, have specifically delegated certain powers to the board and have not approved the board’s delegation to others.

 

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Appointments and Remuneration Committee

The duties and functions of our Appointments and Remuneration Committee include, among others, the duty to inform our board of directors of appointments, re-elections, terminations and remuneration of the board and its members, as well as upon general remuneration and incentives policy for the board and senior management. The Appointments and Remuneration Committee meets as often as necessary in order to perform its functions and at least once every six months. The committee will inform and make proposals to the board.

Immediately following the consummation of this offering, our Appointments and Remuneration Committee will consist of Mr. Sanchez and two independent directors.

Audit Committee

The Audit Committee will be responsible for monitoring and informing the board on the work of external and internal auditors, control systems, key processes and procedures, security and risks.

The committee will consist initially of six members. Initially, it will be chaired by Mr. Villalba and will include Mr. Seage, Mr. Alarcon, Mr. Kausel, Mr. Robinson and Mr. del Hoyo. We believe that Mr. Villalba qualifies as our “audit committee financial expert,” as such term is defined in Item 407(d)(5)(i) of Regulation S-K. We expect Mr. Seage to resign from the committee prior to the first anniversary of the offering, whereupon the committee will consist of five independent directors.

The committee will meet as many times as required and a minimum of two times per year.

The Audit Committee is directly responsible for overseeing the work of the external auditor engaged for the purpose of preparing or issuing an auditor’s report or performing other audit, review or attest services, including the resolution of disagreements between the external auditor and management. The external auditor will report directly to the Audit Committee. The Audit Committee is also responsible for reviewing and approving our hiring policies regarding former employees of the external auditor. In addition, the Audit Committee pre-approves all non-audit services undertaken by the external auditor.

The Audit Committee is responsible for reviewing the adequacy and security of procedures for the confidential, anonymous submission by our employees or contractors regarding any possible wrongdoing in financial reporting or other matters. The Audit Committee is accountable to the board and will provide a report to the board after each regularly scheduled Audit Committee meeting outlining the results of the Audit Committee’s activities and proceedings.

Lead Independent Director

Our corporate governance guidelines will provide that one of our independent directors shall serve as a lead independent director at any time when an independent director is not serving as the chairman of the board of directors. Immediately prior to the consummation of this offering, our board of directors will appoint Mr. Villalba to serve as our lead independent director.

Management Team

We will have a senior management team with extensive experience in developing, financing, managing and operating contracted assets. This senior management team is being provided to us by Abengoa pursuant to the Executive Services Agreement. We intend to employ directly these individuals beginning prior to the first anniversary of the offering.

Once directly employed by us, the senior management team will provide management services to Abengoa. We expect that we will charge Abengoa approximately 40% of all personnel-related expenses in 2015, potentially decreasing in 2016 if we execute the acquisitions we expect to under the ROFO Agreement.

 

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Family Relationships

There are no family relationships among any of our executive officers or directors.

Benefits upon Termination of Employment

Neither we nor our subsidiaries maintain any director’s service contracts providing for benefits upon termination of service.

Corporate Governance Practices

For purposes of the NASDAQ rules, we expect to be a “controlled company.” Controlled companies under those rules are companies of which more than 50% of the voting power for the election of directors is held by an individual, a group or another company. We expect that Abengoa will continue to control more than 50% of the combined voting power of our shares upon completion of this offering and will continue to have the right to designate a majority of the members of our board of directors for nomination for election and the voting power to elect such directors following this offering. Accordingly, we expect to be eligible to, and we may, take advantage of certain exemptions from corporate governance requirements provided in the NASDAQ rules. Specifically, as a controlled company, we would not be required to have: (i) a majority of independent directors, (ii) a nominating/corporate governance committee composed entirely of independent directors, (iii) a compensation committee composed entirely of independent directors or (iv) an annual performance evaluation of the nominating/corporate governance and compensation committees. Therefore, following this offering if we are able to rely on the “controlled company” exemption, we will not be required to have a majority of independent directors, our Appointments and Remuneration Committee will not need to consist entirely of independent directors and such committees will not be required to be subject to annual performance evaluations; accordingly, you may not have the same protections afforded to shareholders of companies that are subject to all of the applicable NASDAQ rules.

We are also a “foreign private issuer” under the U.S. federal securities laws and the NASDAQ rules. The foreign private issuer exemption will permit us to follow home country corporate governance practices instead of certain of NASDAQ’s requirements, including in the event we are no longer eligible for the “controlled company” exemption. A foreign private issuer that elects to follow a home country practice instead of NASDAQ’s requirements must submit to NASDAQ a written statement from an independent counsel in such issuer’s home country certifying that the issuer’s practices are not prohibited by the home country’s laws. In addition to the requirements from which we are exempt as a controlled company, the foreign private issuer exemption exempts us from the requirement of having regularly scheduled meetings at which only independent directors are present.

These exemptions do not modify the independence requirements for the audit committee, and we intend to comply with the requirements of the Sarbanes-Oxley Act and the NASDAQ rules, which require that our audit committee be composed of at least three members, one of whom will be independent upon the listing of our shares on the NASDAQ Global Select Market, a majority of whom will be independent within 90 days of the date of this prospectus, and each of whom will be independent within one year of the date of this prospectus.

Compensation of Our Executive Officers

We are a newly-formed subsidiary of Abengoa consisting of portions of various parts of Abengoa’s business that are being contributed to us in connection with this offering. We have not incurred any cost or liability with respect to compensation of our executive officers prior to our formation. We do not currently directly employ any of the executives responsible for managing our business, but we plan to employ our executive management team, including Mr. Seage, Mr. Soler, Mr. Silvan, Mr. Garcia and Mr. Merino over the course of the next year.

 

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Our officers will manage the day-to-day affairs of our business and will be employed and compensated by us, including under long-term incentive plans, once they become our employees, although some of our executives may continue to participate in long-term incentive plans with Abengoa, provided that from January 1, 2015 these incentives can only be based on Abengoa Yield’s business objectives and Abengoa’s stock price. We expect that future compensation for our executive officers will be determined and structured in a manner similar to that then currently used by Abengoa to compensate its executive officers. Our officers, as well as the employees of Abengoa who provide services to us, may participate in employee benefit plans and arrangements sponsored by Abengoa, including plans that may be established in the future but their objectives can only be based on Abengoa Yield’s business objectives and approved by us.

Compensation of Our Directors

Our independent directors will receive compensation as “non-employee directors” as set by our board of directors.

Effective as of the consummation of this offering, each independent director will receive a total annual compensation of $100,000. As lead independent director and Chair of our Audit Committee, Mr. Villalba will receive an additional $35,000 per year. Directors representing Abengoa will not receive any compensation from us.

Each member of our board of directors will be indemnified for his actions associated with being a director to the extent permitted by law.

 

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RELATED PARTY TRANSACTIONS

Each of our assets typically has two contracts in place with Abengoa entities from the time of construction, including an operation and maintenance agreement and a services agreement that covers local administrative support.

Additionally, we have entered into a number of agreements with our controlling shareholder, Abengoa, that we believe will allow us to: (i) secure cost-effective administrative and financial support, (ii) ensure a smooth transition following completion of the offering, and (iii) access through the ROFO Agreement a pipeline of potential acquisitions that we believe will help us to grow in the future. In addition to the deed described under “Description of Share Capital—Brazil Dividend Policy” and the shareholders agreement described under “Business—Our Operations—Exchangeable Preferred Equity Investment in Abengoa Concessoes Brasil Holding,” we will enter into five agreements with Abengoa:

 

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ROFO Agreement;

 

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Trademark License Agreement;

 

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Financial Support Agreement;

 

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Support Services Agreement; and

 

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Executive Services Agreement.

Each of these agreements has been reviewed with external advisors and we believe that they comply with transfer pricing regulations. Each agreement is described below.

Project-Level Management and Administration Agreements

When our projects reach COD, we typically have in place two contracts for each project:

 

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an operations and maintenance contract, in most cases with an Abengoa subsidiary; and

 

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a services contract that typically covers areas like accounting, administration, payments management, local legal and tax support, local institutional relations, communications and other services. This contract is entered into with local Abengoa subsidiaries that have the required staff in the countries or states in which our assets are located.

Operation and Maintenance Contracts

Each of the assets in our portfolio have entered into an operation and maintenance agreement with an Abengoa subsidiary, with the exception of ACT, where the contract is with third-party providers.

 

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Term. Contract terms range from 20 to 30 years, typically mirroring the duration of financing contracts. The only exceptions are ATN and ATS, which are subject to shorter terms but have renewal clauses.

 

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Services. Contracts typically cover all day-to-day operation and maintenance services, including procurement of equipment, scheduling and performance of maintenance, operation of the facility, training and supervision of personnel, as well as compliance with laws and regulations, safety and security programs, environmental services and technical reporting.

 

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Termination. Typically, either party may terminate the agreement upon default by the counterparty. The relevant project-level company that owns the asset can typically terminate due to payment default, winding-up of the operator, failure of the operator to perform material obligations, termination of the PPA and, in some cases, for failure to reach certain performance ratios, the imposition of fines or penalties in excess of certain threshold amounts or force majeure. The operator can typically terminate in the event of payment default, winding-up of the project-level company, failure of the project-level company to perform material obligations and, in some cases, force majeure.

 

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Compensation. Operation and maintenance contracts in Solana and Mojave provide for a fixed fee of approximately $500,000 per plant per year, which is indexed to U.S. CPI and a variable fee paid in periods

 

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in which net operating profit exceeds the target. In addition, the operator is entitled to reimbursement of certain costs. In other projects, including ATN, ATS, Solaben 2 and Solaben 3, the operation and maintenance contract provides for an all-in fee by which the operator must bear substantially all costs for the operation and maintenance of the plant.

Services Agreement

Each of our project-level companies have entered into a services agreement with a local Abengoa subsidiary, which agreement typically provides for accounting, administration, payments management, local legal and tax support, local institutional, communications services and general support services.

 

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Term. The agreements relating to ATN and ATS expire after a year but include tacit renewal clauses, while Solana, Mojave, Solaben 2 and Solaben 3 are contracts with 20- to 30-year terms.

 

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Termination. The agreements can typically be terminated due to breach of obligations, insolvency, suspension of payments or winding-up of the counterparty, or mutual consent.

 

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Compensation. The compensation paid is typically approximately 1% of revenues, with the exception of Solaben 2 and 3, which provide for a fee of 2.5% of revenues.

Right of First Offer

We and Abengoa will enter into the ROFO Agreement, pursuant to which Abengoa and its affiliates will grant us and our affiliates a right of first offer on any proposed sale, transfer or other disposition of any of their contracted renewable energy, conventional power, electric transmission or water assets that are in operation and located in our primary geographies: (i) North America (the United States, Canada and Mexico); (ii) the following countries in South America: Chile, Peru, Uruguay, Brazil and Colombia; and (iii) the European Union. In addition, with respect to certain countries in Africa, the Middle East and Asia and Australia, which we refer to as our secondary geographies, we will agree with Abengoa within the first month following the consummation of this offering, on a list of four assets that will be thereafter considered Abengoa ROFO Assets. Whenever we acquire an asset from Abengoa in the secondary geographies, or, if after 60 days of negotiations we and Abengoa are unable to reach an agreement on an asset offered for sale to us, we will update the list to include a replacement asset. If we and Abengoa are unable to agree on the replacement asset, Abengoa will propose three additional assets in the secondary geographies and we will select one to replace the asset removed from the list. Thereafter, the selected asset will also be considered an Abengoa ROFO Asset. This right of first offer will not apply to a merger with or into, or sale of substantially all of Abengoa’s assets to, an unaffiliated third party, or to an internal restructuring. The right of first offer will not apply to a potential sale of Linha Verde, a Brazilian transmission line, which is currently under advanced discussions for a sale to a third party.

The ROFO Agreement will have an initial term of five years from the completion of this offering. We will be able to unilaterally extend the term of the ROFO Agreement as many times as desired for an additional three-year period; provided that we have executed at least one acquisition in the previous two years after having been offered at least four projects.

Prior to engaging in any negotiation regarding any disposition, sale or other transfer of any Abengoa ROFO Asset, Abengoa will deliver a written notice to us thereof, including all information that is relevant for us to make a determination regarding the Abengoa ROFO Asset including the price at which Abengoa proposes to sell it to us. Once that information is received and if we do not notify Abengoa within ten days that the information is insufficient, a 60-day negotiation period will start. If an agreement is not reached, Abengoa may, during the following 18 months, only sell, transfer, dispose or recontract such Abengoa ROFO Asset to a third party (or to agree in writing to undertake such transaction with a third party) on terms and conditions generally no less favorable to Abengoa than those offered by Abengoa to us. If an asset that was already the subject of negotiations is presented again, we will have a 15-day period to negotiate. After such 18-month period, the asset will cease to be an Abengoa ROFO Asset.

 

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We will pay to Abengoa a fee of 1% of the equity purchase price of any Abengoa ROFO Asset that we acquire as consideration for Abengoa granting us the right of first offer.

Under the ROFO Agreement, Abengoa will not be obligated to sell any Abengoa ROFO Asset and, therefore, we do not know when, if ever, these assets will be offered to us. In addition, in some of the assets offered to us under the ROFO Agreement, Abengoa may have equity partners with rights regulating divestitures by Abengoa of its stake such as drag-along and tag-along clauses, and rights of first refusal, among others. We will consider and take into account all these clauses when deciding whether to present an offer.

Even though we do not have a ROFO right over them as described in this section, Abengoa may offer to sell to us contracted assets in business sectors or geographic regions not covered by the ROFO Agreement. We will evaluate these opportunities on a case-by-case basis.

Any offer by Abengoa to sell an Abengoa ROFO Asset under the ROFO Agreement will be subject to an inherent conflict of interest because some of the same professionals within Abengoa’s organization who are involved in acquisitions that are suitable for us have responsibilities to Abengoa within Abengoa’s broader asset management business. Notwithstanding the significance of the services to be rendered by Abengoa or its designated affiliates on our behalf or of the assets which we may elect to acquire from Abengoa in accordance with the terms of the ROFO Agreement or otherwise, Abengoa will not owe fiduciary duties to us or our shareholders.

Any material transaction between Abengoa and us (including the proposed acquisition of any Abengoa ROFO Asset) will be subject to our related party transaction policy, which will require prior approval of such transaction by a majority of the independent members of our board of directors. See “—Procedures for Review, Approval and Ratification of Related Party Transactions; Conflicts of Interest.” See “Risk Factors—Risks Related to Our Relationship with Abengoa—We may not be able to consummate future acquisitions from Abengoa” and “—Our organizational and ownership structure may create significant conflicts of interest that may be resolved in a manner that is not in the best interests of Abengoa Yield or the best interests of holders of our shares and that may have a material adverse effect on our business, financial condition, results of operations and cash flows.”

Trademark License Agreement

We and Abengoa will enter into a Trademark License Agreement pursuant to which Abengoa will grant us a non-exclusive, royalty-free license to use the name “Abengoa” and the Abengoa logo, among other trademarks owned by Abengoa. Other than under this limited license, we will not have a legal right to the “Abengoa” name or the Abengoa logo. Abengoa will also grant an exclusive license to use the “Abengoa Yield” name and logo.

Abengoa will sell, transfer or assign to us the domain names www.abengoayield.com, www.abengoayield.co.uk and www.abengoayield.es against payment of costs incurred by Abengoa in registering such domain names. It will commit to cooperate to deliver to us any similar domain names at our request and it shall defend us against any infringements. We will assign the domain names to Abengoa within two years of any termination of the Trademark License Agreement.

Abengoa will be entitled to terminate the Trademark License Agreement with respect to us upon 90 days’ prior written notice of termination if any of the following occurs:

 

•

we default in the performance of any material term, condition or agreement contained in the Trademark License Agreement and the default continues uncured for a period of 90 days after written notice of termination of the breach is given to us;

 

•

we assign, sublicense, pledge, mortgage or otherwise encumber the intellectual property rights granted to us pursuant to the Trademark License Agreement without Abengoa’s prior written consent and do not provide satisfactory remedy within 90 days; or

 

•

in the event of our bankruptcy, insolvency or similar events.

 

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If Abengoa ceases to own directly or indirectly at least 20% of our outstanding shares, Abengoa will be entitled to terminate the Trademark License Agreement two years thereafter upon written notice.

In the event of any dispute under the Trademark License Agreement, a dispute notice will be required to be delivered, after which our CEO and the CEO of Abengoa will have an obligation to discuss and attempt to resolve the dispute for 15 days prior to submitting the matter to a court.

Financial Support Agreement

We and Abengoa will enter into a Financial Support Agreement in connection with the consummation of this offering, for a period of five years, pursuant to which:

 

(1)

Abengoa will provide us with a revolving credit line from its central treasury for a period of five years up to a maximum amount of $50,000,000. If we have any funding needs in excess of this amount, Abengoa will make a good faith effort to accommodate any requests from us for additional funding taking into positive consideration the achievement of our business objectives.

 

(2)

If we have a positive liquidity position at the Abengoa Yield plc level while the revolving credit line is outstanding, we will deposit such cash in Abengoa’s central treasury, up to a maximum amount of $20,000,000.

 

(3)

Abengoa will maintain any guarantees (whether parent company guarantees, bank guarantees, technical guarantees or otherwise) or letters of credit currently outstanding in our or any of our affiliates’ favor for a period of up to five years from the offering. We have undertaken to periodically review the relevance and possible substitution of such guarantees with a view to operating independently from Abengoa.

If Abengoa ceases to own, directly or indirectly, at least 20% of our outstanding shares, Abengoa shall be entitled to terminate the Financial Support Agreement not earlier than three years from the date thereof, upon 180 days’ prior written notice.

Procedures for Review, Approval and Ratification of Related Party Transactions; Conflicts of Interest

Our board of directors has adopted a code of business conduct and ethics to take effect upon the consummation of this offering that will provide that our board of directors or its authorized committee will periodically review all related party transactions and, when appropriate, initially authorize or ratify all such transactions. In the event that our board of directors or its authorized committee considers ratification of a related party transaction and determines not to so ratify, the code of business conduct will provide that our management will make all reasonable efforts to cancel or annul the transaction.

Support Services Agreement

In connection with the consummation of this offering, we will enter into a Support Services Agreement pursuant to which Abengoa will agree to provide or arrange for other service providers to provide management and administration services to us. This agreement does not include executive or senior management services.

Services Rendered

Under the Support Services Agreement, Abengoa or certain of its affiliates will provide or arrange for the provision by an appropriate service provider of the following services:

 

•

causing or supervising the carrying out of all day-to-day, secretarial, accounting, banking, treasury, administrative, liaison, representative, regulatory and reporting functions and obligations;

 

•

establishing and maintaining or supervising the establishment and maintenance of books and records;

 

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•

monitoring and/or oversight of our accountants, legal counsel and other accounting, financial or legal advisors and technical, commercial, marketing and other independent experts, and managing litigation in which we or one of our subsidiaries is sued or commencing litigation after consulting with, and subject to the approval of, the board of directors or its equivalent of us or our relevant subsidiary;

 

•

attending to all matters necessary for any reorganization, bankruptcy proceedings, dissolution or winding up of us or one of our subsidiaries, subject to approval by the relevant board of directors or its equivalent;

 

•

supervising the timely calculation and payment of taxes, and the filing of all tax returns;

 

•

causing or supervising the preparation of our annual financial statements and quarterly interim financial statements to be: (i) prepared in accordance with IFRS and audited at least to such extent and with such frequency as may be required by law, regulation or in order to comply with any debt covenants; and (ii) submitted to the relevant board of directors or its equivalent for its prior approval;

 

•

preparing filings for submission to, or required by, relevant regulators;

 

•

making recommendations in relation to and effecting the entry into insurance policies covering our assets, together with other insurances against other risks, including directors’ and officers’ insurance, as the relevant service provider and the relevant board of directors or its equivalent may from time to time agree;

 

•

providing us with authorizations and licenses necessary to use Abengoa’s corporate systems for management of risks (NOC) and for compliance processes (POC);

 

•

providing IT services, human resources support and office and space and support to our employees;

 

•

advising us regarding the maintenance of compliance with applicable laws and other obligations; and

 

•

providing all such other services as may from time to time be agreed with us that are reasonably related to our day-to-day operations.

These activities will be subject to the supervision of our executive management.

Support Services Fee

Pursuant to the Support Services Agreement, we will pay a support services fee of approximately $625,000 per quarter. The support services fee shall be adjusted for inflation annually beginning on January 1, 2015 at an inflation factor based on year-over-year CPI. The support services fee shall also be increased if the total services agreements fees paid by the assets in a given year are lower than 1% of our revenue. The increase would be equivalent to the difference between a 1% of our revenues and the total fees paid under the service agreements by our assets. We do not expect this adjustment to occur based on the current level of fees, unless a significant project stopped paying its fees under its relevant project-level services agreement. Additionally, it will also be increased in connection with our completion of future acquisitions (including any Abengoa ROFO Assets) by an amount estimated to be equal to 0.12% of the enterprise value of the acquired assets as of the acquisition closing date.

We may amend the scope of the services to be provided by Abengoa under the Support Services Agreement, including reducing the number of our subsidiaries that receive services or otherwise, by providing 180 days’ prior written notice to Abengoa; provided that the services to be provided by Abengoa under the Support Services Agreement cannot be increased without Abengoa’s prior written consent. Furthermore, we and Abengoa must consent to any related change in the support services fee resulting from a change in the scope of services. If the parties are unable to agree on a revised support services fee, we may terminate the agreement after the end of such 180-day period by providing 60 days’ prior written notice to Abengoa; provided, that any decision by us to terminate the Support Services Agreement must be approved by a majority of our independent directors.

 

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Term and Termination

The Support Services Agreement will not have a fixed term. However, we will be able to terminate the Support Services Agreement upon 180 days’ prior written notice of termination from us to Abengoa; provided that any decision by us to terminate the Support Services Agreement may be approved by a majority of our independent directors. We may not terminate the Support Services Agreement solely due to the poor performance of us or any of our subsidiaries or investments.

Abengoa will be able to terminate the Support Services Agreement upon 180 days’ prior written notice of termination to us if we default in the performance or observance of any material term, condition or agreement contained in the Support Services Agreement in a manner that results in material harm to Abengoa and the default continues unremedied for a period of 60 days after written notice of the breach is given to us. Abengoa will also be able to terminate the Support Services Agreement upon the occurrence of certain events relating to our bankruptcy or insolvency.

Indemnification and Limitations on Liability

Under the Support Services Agreement, Abengoa will not assume any responsibility other than to provide or arrange for the provision of the services called for thereunder in good faith and will not be responsible for any action that we take in following or declining to follow the advice or recommendations of Abengoa. The maximum amount of the aggregate liability of Abengoa or any of its affiliates, or of any director, officer, employee, member, shareholder, agent or other representative of Abengoa or any of its affiliates, will be equal to the support services fee previously paid by us in the two most recent calendar years pursuant to the Support Services Agreement. We have also agreed to indemnify each of Abengoa and its affiliates, directors, officers, agents, members, partners, shareholders and employees to the fullest extent permitted by law from and against any claims, liabilities, losses, damages, costs or expenses (including legal fees) incurred by an indemnified person or threatened in connection with our respective businesses, investments and activities or in respect of or arising from the Support Services Agreement or the services provided by Abengoa, except to the extent that the claims, liabilities, losses, damages, costs or expenses are determined by a final and non-appealable judgment entered by a court or by a settlement agreement to have resulted from the indemnified person’s bad faith, fraud, willful misconduct, gross negligence, or in the case of a criminal matter, action that the indemnified person knew to have been unlawful. In addition, under the Support Services Agreement, the indemnified persons will not be liable to us except to the extent that there is a determination by a final and non-appealable judgment entered by a court that the conduct involved bad faith, fraud, willful misconduct, gross negligence or in the case of a criminal matter, action that the indemnified person knew to have been unlawful.

Continuity Arrangements

Abengoa and/or its affiliates, as the case may be, will take all actions necessary (including obtaining consents) to transfer, and will transfer, and provide all necessary documentation in connection with such transfer, to us and/or our designee(s) any and all licenses currently held by Abengoa or any of its affiliates (unless the terms of a licenses does not allow for its transfer) and (i) used solely by us and/or our affiliates or (ii) which are necessary for us and our affiliates to operate our business as it was operated immediately prior to this offering. All such licenses, if any, will be transferred to us and/or our designee(s) as promptly as practicable but in no event later than October 31, 2014; provided, however, that any such transfer or effort related thereto will in no event materially interrupt any parties’ ordinary course business.

Executive Services Agreement

We intend to employ our executive and senior managers within one year following the consummation of this offering. Nevertheless, until that time, we will enter into an Executive Services Agreement with Abengoa under which approximately ten key executives, currently employed by Abengoa, will provide their services to us while remaining employees of and continuing to provide services to Abengoa. We estimate that in 2014 and 2015 such persons will devote approximately 60% of their time to our business.

 

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Services Rendered

Under the Executive Services Agreement, Abengoa will arrange for senior managers to provide, among others, the following services:

 

•

providing the senior managers to act for us as agreed from time to time, subject to the approval of the relevant board of directors or its equivalent;

 

•

identifying, evaluating and recommending to us acquisitions or dispositions from time to time and, where requested to do so, assisting in negotiating the terms of such acquisitions or dispositions;

 

•

recommending to us suitable candidates to serve on the boards of directors or their equivalents of our subsidiaries;

 

•

making recommendations with respect to the exercise of any voting rights to which we are entitled in respect of our subsidiaries;

 

•

making recommendations regarding the issuance of any security, equity or debt;

 

•

making recommendations with respect to the payment of dividends by us or any other distributions by us, including distributions to our shareholders; and

 

•

carrying out the functions of principal executive, accounting, legal and financial officers for purposes of applicable securities laws.

Executive Services Fee

We will pay an executive services fee of approximately $500,000 per quarter.

Termination

We will be able to terminate this agreement immediately upon notice on or after the date that is one year following the consummation of this offering without cause, or at any time upon 30 days’ notice with cause. Both parties can agree to terminate it earlier once the ten senior managers, or a majority of them, have transferred to us.

Abengoa will not be able to terminate this agreement unilaterally.

Once the ten senior managers, or a majority of them, have transferred to us, we will charge a percentage of the compensation and related costs of these managers back to Abengoa, as they will dedicate part of their time to manage assets that are owned by Abengoa at that time.

Indemnification and Limitations on Liability

Under the Executive Services Agreement, Abengoa will not assume any responsibility other than to provide or arrange for the provision of the services called for thereunder in good faith and will not be responsible for any action that we take in following or declining to follow the advice or recommendations of Abengoa. The maximum amount of the aggregate liability of Abengoa or any of its affiliates, or of any director, officer, employee, contractor, agent, advisor or other representative of Abengoa or any of its affiliates, will be equal to the executive management services fee previously paid by us in the previous calendar years pursuant to the Executive Services Agreement. We have also agreed to indemnify each of Abengoa and its affiliates, directors, officers, agents, members, partners, stockholders and employees to the fullest extent permitted by law from and against any claims, liabilities, losses, damages, costs or expenses (including legal fees) incurred by an indemnified person or threatened in connection with our respective businesses, investments and activities or in respect of or arising from the Executive Services Agreement or the services provided by Abengoa, except to the extent that the claims, liabilities, losses, damages, costs or expenses are determined by a final non-appealable judgment entered by a court to have resulted from the indemnified person’s bad faith, fraud or willful misconduct, or in the case of a criminal matter, action that the indemnified person knew to have been unlawful. In addition, under the Executive Services Agreement, the indemnified persons will not be liable to us to the fullest extent permitted by law, except for conduct that involved bad faith, fraud, willful misconduct, gross negligence or in the case of a criminal matter, action that the indemnified person knew to have been unlawful.

 

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PRINCIPAL AND SELLING SHAREHOLDER

Major Shareholders

Abengoa, through Abengoa Concessions Investments Limited, owns all of our shares as of the date of this prospectus. As described under “Summary—Asset Transfer”, we will distribute additional shares to subsidiaries of Abengoa in connection with the Asset Transfer and Abengoa will beneficially own all of our shares through Abengoa Concessions Investments Limited, Abengoa Solar, S.A. and Abengoa Concessions, S.L. immediately prior to the consummation of the offering. Abengoa Concessions, S.L. will be the selling shareholder if the underwriters exercise their option to purchase additional shares.

After consummation of the offering, Abengoa will beneficially own     % of our shares, assuming no exercise of the underwriters’ option to purchase additional shares, which would be reduced to     % if the underwriters exercise in full their option to purchase additional shares. We expect that Abengoa will hold its shares through Abengoa Concessions Investments Limited.

Shareholders in the United States

Prior to this offering, we have no shareholders in the United States.

Control of Abengoa Yield

Prior to the offering, Abengoa indirectly holds 100% of the voting power of our outstanding shares.

Arrangements for Change in Control of Abengoa Yield

We are not aware of any arrangements the operation of which may at a subsequent date result in a change of control of Abengoa Yield.

 

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DESCRIPTION OF SHARE CAPITAL

Issued capital

We were incorporated on December 17, 2013 under the name Abengoa Yield Limited, with an issued, fully paid up, share capital of 100 ordinary shares of €0.10 each. On March 19, 2014, Abengoa Yield Limited re-registered as a public limited company under the name Abengoa Yield plc, with an issued and fully paid-up share capital of 571,000 ordinary shares with a nominal value €0.10 per share. Following this re-registration, on March 20, 2014, Abengoa Yield plc redenominated its entire issued share capital of 571,000 ordinary shares with a nominal value of €0.10 per share into 571,000 ordinary shares with a nominal value of $0.138 per share. The entire issued share capital of Abengoa Yield plc was subsequently consolidated and sub-divided pursuant to Section 618 of the Companies Act 2006, or the Companies Act, to leave the Company with an issued share capital of 787,980 ordinary shares with a nominal value of $0.10 per share.

As of April 1, 2014, we had 787,980 shares outstanding.

On     , 2014, the Company’s sole shareholder resolved that the directors are authorized to issue equity securities. Such power shall expire on the fifth anniversary of the date of passing this resolution, namely:

Upon completion of this offering, our capital stock will consist of 80,000,000 shares that will have been issued in two steps:

 

•

following pricing, we will issue new shares and agree to a deferred cash payment to Abengoa in exchange for the assets they will contribute to us; and

 

•

immediately thereafter, we will issue new shares to the new shareholders in exchange for cash and will use cash proceeds to make the deferred cash payment.

Shares not representing capital

None.

Shares held by the Company

We are not permitted under English law to hold our own shares unless they are repurchased by us and held in treasury.

History of share capital

The following table presents the history of our share capital as of the end of each of our last three fiscal years:

 

		December 31,
		2013				2012		2011
Shares			100			N/A		N/A

Upon our incorporation (December 17, 2013), we issued 100 shares.

Memorandum and Articles of Association

Objects and Purposes

We were incorporated in England and Wales as a private limited company on December 17, 2013 under the name Abengoa Yield Limited, registered number 8818211. On March 19, 2014, we re-registered as a public limited company, under the name Abengoa Yield plc.

 

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The description of the company’s articles of association, or the Articles, in this section is based on the form of articles of association that will be adopted by the company prior to the consummation of this offering.

The Companies Act abolishes the need for an objects clause and, as such, our objects will be unrestricted.

Disclosure of Personal Interests of an Office Holder

The Companies Act requires that an office holder disclose to the company any personal interest that he or she may have, and all related material information and documents known to him or her, in connection with any existing or proposed transaction by the company. The disclosure is required to be made promptly and in any event, no later than at the board of directors meeting in which the transaction is first discussed.

Directors

Subject to the provisions of the Articles, the directors may meet for the dispatch of business and adjourn and otherwise regulate its proceedings as they think fit. Unless and until in a general meeting the shareholders of the company determine otherwise, the number of directors of the company shall not be less than 7 nor more than 13 in number.

The quorum necessary for the transaction of business of the directors may be fixed from time to time by the directors and unless so fixed at any other number shall be a number equal to at least half of the directors appointed from time to time. A meeting of the directors at which a quorum is present shall be competent to exercise all powers and discretions for the time being exercisable by the directors. A director is not counted in the quorum at a meeting in relation to any resolution on which he is debarred from voting.

The directors of the company may in accordance with the Articles, and the provisions of the Companies Act, authorize a matter proposed to the company that would, if not authorized, involve a breach by a director of his duty under section 175 of the Companies Act to avoid a situation in which he or she has, or can have, a direct or indirect interest that conflicts, or possibly may conflict with the interests of the company. A director is not required, by reason of being a director (save as otherwise agreed by such director), to account to the company for any benefit which the director (or a person connected with the director) derives from any such matter authorized by the director. Any contract, transaction or arrangement relating to such matter shall not be liable to be avoided on the grounds of any such benefit.

Sections 177 and 182 of the Companies Act require any transaction or arrangement with the company in which a director has an interest (proposed or existing) to be declared, and not only those that are extraordinary transactions or arrangements.

A director may not vote at a meeting of the board or of a committee of the board on any resolution in respect of any contract, transaction, or arrangement, or any other proposal in which he has (either alone or together with any person connected with him, as provided in the Companies Act) an interest other than in the circumstances set out below. A director shall not be counted in the quorum at a meeting of the directors in relation to any resolution in which the director is not entitled to vote.

Subject to the provisions of the Companies Act, a director is entitled to vote and be counted in the quorum in respect of any resolution concerning any contract, transaction or arrangement or any other proposal (inter alia):

 

•

in which he has an interest of which he is not aware or which cannot reasonably be regarded as likely to give rise to a conflict of interest;

 

•

in which he has an interest only by virtue of interests in the company’s shares, debentures or other securities or otherwise in or through the company;

 

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•

which involves the giving of any security, guarantee or indemnity to the director or any other person in respect of obligations incurred by him or any other person for the benefit of the company or a debt or other obligation of the company for which the director has assumed responsibility under a guarantee or indemnity or by the giving of security;

 

•

concerning an offer of securities by the company or any of its subsidiary undertakings in which he is or may be entitled to participate as a holder of securities or as an underwriter or sub-underwriter;

 

•

concerning any other corporate, provided that he and any connected persons do not own or have a beneficial interest in one percent or more of any class of share capital of such body corporate, or of the voting rights available to the members of such body corporate;

 

•

relating to an arrangement for the benefit of employees or former employees which does not award him any privilege or benefit not generally awarded to the employees or former employees to whom such arrangement relates;

 

•

concerning the purchase or maintenance of insurance for any liability for the benefit of directors;

 

•

concerning the giving of indemnities in favor of the directors; or

 

•

concerning the funding of expenditure by any director or directors (i) on defending criminal, civil or regulatory proceedings or actions against him or them, (ii) in connection with an application to the court for relief, (iii) on defending him or them in any regulator investigations, or (iv) incurred doing anything to enable him to avoid incurring such expenditure.

Any director (including the director that has the conflict) may propose that such conflicted director be authorized in relation to any matter which is the subject of such a conflict. The director with the conflict will not count towards the quorum at the meeting at which the conflict is considered and may not vote on any resolution authorizing the conflict. Where the board gives authority in relation to such a conflict, the board may impose such terms on the relevant director as it deems appropriate.

Each of our directors and other officers may be indemnified by us against all costs, charges, losses, expenses and liabilities incurred by such director or officer in the execution or discharge of his or her duties or in relation to those duties. The Companies Act renders void an indemnity for a director against any liability attaching to him in connection with any negligence, default, breach of duty or breach of trust in relation to the company of which he or she is a director, as described in “—Differences in Corporate Law—Liability of Directors and Officers.” We plan to purchase insurance for our directors regarding negligence, default, breach of trust and breach of duty under the terms allowed under the Companies Act.

Appointment of Directors

The Companies Act requires that a resolution approving provisions to appoint a director for a period of more than two years must not be passed unless a memorandum setting out the proposed contract incorporating the provision is made available to members: in the case of a resolution at a meeting, by being made available for inspection by members of the company both (i) at the company’s registered office for not less than 15 days ending with the date of the meeting, and (ii) at the meeting itself.

Subject to certain minimum thresholds in terms of their shareholdings, each shareholder shall be entitled to appoint a number of directors in proportion to their shareholding. However, no shareholder shall be entitled to appoint more than half of the directors plus one.

Effective from October 1, 2013, quoted companies must obtain a binding vote of shareholders on remuneration policy at least once every three years and an advisory vote an implementation report on how the remuneration policy was implemented in the relevant financial year.

 

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Ordinary remuneration shall be paid to the independent non-executive directors only and shall be determined by the directors.

Directors’ Borrowing Powers

Subject to the provisions of the Articles and the Companies Act, the directors may exercise all the powers of the company to borrow money, mortgage or charge all or any part or parts of its undertaking, property and uncalled capital, and issue debentures and other securities whether outright or as collateral security for any debt, liability or obligation of the company or of any third party.

Removal of Directors

The company may, by ordinary resolution of which special notice has been given, remove any director and elect another person in place of such director.

Retirement of Directors

Each director shall retire at the annual general meeting held in the third calendar year following the year in which he was elected or last re-elected by the company or such shorter period as the directors may determine. In addition, each director (other than the Chairman and any director holding an executive office) shall also be required to retire at each annual general meeting following the ninth anniversary on the date on which he was elected by the company. A director who retires at any annual general meeting shall be eligible for election or re-election unless the directors resolve otherwise not later than the date of the notice of such annual general meeting.

When a director retires at an annual general meeting in accordance with the Articles, the company may, by ordinary resolution at the meeting, fill the office being vacated by re-electing the retiring director. In the absence of such a resolution, the retiring director shall nevertheless be deemed to have been re-elected, except in the cases identified by the Articles.

Termination of Office

The office of a director of the company shall be terminated if:

 

(i)

subject to the provisions of the Companies Act, the shareholder who appointed the relevant director of the company elects to terminate the office of such director;

 

(ii)

the director of the company becomes prohibited by law or (if applicable) the NASDAQ Rules from acting as a director or ceases to be a director by virtue of any provision of the Companies Act;

 

(iii)

the company has received notice of the director’s resignation or retirement from office and such resignation or retirement from office has taken effect in accordance with its terms;

 

(iv)

the director has retired at an annual general meeting in accordance with the Articles;

 

(v)

the director has a bankruptcy order made against him/her, compounds with his/her creditors generally or applies to the court for an interim order under the UK Insolvency Act 1986 in connection with a voluntary arrangement under that Act or any analogous event occurs in relation to the director in another country;

 

(vi)

an order is made by any court claiming jurisdiction in that behalf on the ground (however formulated) of mental disorder for the director’s detention or for the appointment of another person (by whatever name called) to exercise powers with respect to the director’s property or affairs;

 

(vii)

the director is absent from meetings of the directors for three months without permission and the directors have resolved that the director’s office be vacated;

 

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(viii)

notice of termination is served or deemed served on the director and that notice is given by a majority of directors for the time being; or

 

(ix)

in the case of a director other than the chairman and any director holding an executive office, if the directors resolve to require the director to resign and the director fails to do so within 30 days of notification of such resolution being served or deemed served on the director.

Share Qualification of Directors

A director shall not be required to hold any shares of the company by way of qualification. A director who is not a member of the company shall nevertheless be entitled to attend and speak at general meetings.

Rights Attached to Our Shares

As of December 17, 2013, the shares have attached to them full voting, dividend and capital distribution (including winding up) rights. However, the shares do not confer any rights of redemption.

Without prejudice to any rights attached to any existing shares, the company may issue shares with such rights or restrictions as determined either by the company by ordinary resolution or, if the company passes a resolution to authorize them, the directors. The company may also issue shares which are, or are liable to be, redeemed at the option of the company or the holder.

Dividend Rights. Our Articles provide that the company may, by ordinary resolution, declare final dividends to be paid to its shareholders in accordance with their respective rights. However, no dividend shall be declared unless it has been recommended by the directors and does not exceed the amount recommended by the directors.

If the directors believe that the profits of the company justify such payment, they may pay fixed dividends on any class of shares where the fixed dividend is payable on fixed dates. They may also pay interim dividends on shares of any class in amounts and on dates and periods as they think fit. Provided the directors act in good faith, they shall not incur any liability to the holders of any shares for any loss they may suffer by the lawful payment of dividends on any other class of shares having rights ranking equally with or behind those shares.

Unless the share rights otherwise provide, all dividends shall be declared and paid according to the amounts paid up on the shares on which the dividend is paid, and apportioned and paid pro rata according to the amounts paid on the shares during any portion or portions of the period in respect of which the dividend is paid.

Any unclaimed dividends may be invested or otherwise applied for the benefit of the company until they are claimed. If any dividend is unclaimed for 12 years from the date on which it was declared or became due for payment, the person who was otherwise entitled to it shall cease to be entitled and the company may keep that sum. In addition, the company will not be considered a trustee with respect to the amount of any payment into a separate account by the directors of any unclaimed dividend or other sum payable on or in respect of a share of the company.

The company may cease to send any check or other means of payment by post for any dividend on any shares which is normally paid in that manner if in respect of at least two consecutive dividends payable on those shares, the check, warrant or order has been returned undelivered or remains uncashed but, subject to the provisions of these Articles, shall recommence sending checks, warrants or orders in respect of the dividends payable on those shares if the holder of or person entitled to them claims the arrears of dividend and does not instruct the company to pay future dividends in some other way.

The directors may, if authorized by ordinary resolution, offer to shareholders the right to elect to receive, in lieu of a dividend, an allotment of new shares credited as fully paid.

 

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Voting Rights. Subject to the provisions in the Articles and any special rights or restrictions as to voting attached to any shares or class of shares of the company, at a general meeting, voting on each and every resolution shall be taken by way of a poll.

As such, every member present in person or by proxy has one vote for every share held by him, as per the Articles.

A proxy shall not be entitled to vote where the member appointing the proxy would not have been entitled to vote on the resolution had he been present in person.

In the case of joint holders of a share, the vote of the senior who tenders a vote, whether in person or by proxy, shall be accepted to the exclusion of the votes of the other joint holders and for this purpose seniority shall be determined by the order in which the names appear in the register of the company in respect of the joint holding.

The actions necessary to change the rights of holders of the shares are as follows: the rights of the shareholders would need to be altered by way of a special resolution requiring 75% vote of the shareholders who are present and voting in person or by proxy. In order to change the rights of a separate class of shares, it will require such a vote by shareholders of that class of shares.

Liquidation Rights. In the event of our liquidation, subject to applicable law, after satisfaction of liabilities to creditors, our assets will be distributed to the holders of shares in proportion to their respective holdings. This liquidation right may be affected by the grant of preferential dividends or distribution rights to the holders of a class of shares with preferential rights that may be authorized in the future.

Redemption Provisions. We may, subject to applicable law and to our Articles, issue redeemable preference shares and redeem the same.

Capital Calls. Under our Articles and the Companies Act, the liability of our shareholders is limited to the nominal (par) value of the shares held by them.

Subject to the terms of allotment of the shares of the company, the directors of the company may make a call on our shareholders to pay up any nominal value or share premium outstanding by giving them notices of such call. A shareholder must pay to the company the amount called on his shares but is not required to do so until 14 days have passed since the notice of call was sent. If a shareholder fails to pay any part of a call, the directors may serve further notice naming another day not being less than seven days from the date of the further notice requiring payment and stating that in the event of non-payment the shares on which the call has been made will be liable to be forfeited. Subsequent forfeiture requires a resolution by the directors. As part of the initial public offering, the nominal value and share premium of all shares will be fully paid.

Transfer of Shares. Fully-paid shares are issued in registered form and may be transferred pursuant to our Articles, unless such transfer is restricted or prohibited by another instrument and subject to applicable securities laws.

Transfers of uncertificated shares may be effected by means of a relevant system (i.e., NASDAQ Global Select Market) unless the NASDAQ Regulations provide otherwise.

Preemptive Rights. In certain circumstances, our shareholders have preemptive rights under the Companies Act with respect to new issuances of equity securities. These rights are summarized in “—Differences in Corporate Law—Preemptive Rights.” We plan to convene a shareholders’ meeting prior to the effectiveness of this Form F-1 to obtain a waiver of such rights for a period of five years in accordance with the provisions of the Companies Act.

 

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Modification of Rights

Whenever the share capital of the company is divided into different classes of shares, the special rights attached to any class may be varied or abrogated either with the written consent of the holders of three-quarters in nominal value of the issued shares of the class (excluding shares held as treasury shares) or with the sanction of a special resolution passed at a separate meeting of the holders of the shares of the class (but not otherwise), and may be so varied or abrogated either while the company is a going concern or during or in contemplation of a winding-up.

The special rights attached to any class of shares will not, unless otherwise expressly provided by the terms of issue, be deemed to be varied by (i) the creation or issue of further shares ranking, as regards participation in the profits or assets of the company, in some or all respects equally with them but in no respect in priority to them, or (ii) the purchase or redemption by the company of any of its own shares.

Shareholders’ Meetings and Resolutions

An annual general meeting shall be held in each period of six months beginning with the day following the company’s accounting reference date, at such place or places, date and time as may be decided by the directors.

The directors may, whenever they think fit, call a general meeting. The directors are required to call a general meeting once the company has received requests from its members to do so in accordance with the Companies Act.

Notice of general meetings shall include all information required to be included by the Companies Act and shall be given to all members other than those members who are not entitled to receive such notices from the company under the provisions of the Articles. The company may determine that only those persons entered on the Register at the close of business on a day decided by the company, such day being no more than 21 days before the day that notice of the meeting is sent, shall be entitled to receive such a notice.

For the purposes of determining which persons are entitled to attend or vote at a meeting, and how many votes such persons may cast, the company must specify in the notice of the meeting a time, not more than 48 hours before the time fixed for the meeting, by which a person must be entered on the Register in order to have the right to attend or vote at the meeting. The directors may in their discretion resolve that, in calculating such period, no account shall be taken of any part of any day that is not a working day (within the meaning of Section 1173 of the Companies Act).

No business other than the appointment of a chairman shall be transacted at any general meeting unless a quorum is present at the time when the meeting proceeds to business. Two members present in person or by proxy and representing in total at least one-third in nominal value of the issued shares will be a quorum.

The directors may require attendees to submit to searches or put in place such arrangements or restrictions as they think fit to ensure the safety and security of attendees at a general meeting. Any member, proxy or other person who fails to comply with such arrangements or restrictions may be refused entry to, or removed from, the general meeting.

The directors may decide that a general meeting shall be held at two or more locations to facilitate the organization and administration of such meeting. A member present in person or by proxy at the designated “satellite” meeting place may be counted in the quorum and may exercise all rights that they would have been able to exercise if they had been present at the principal meeting place. The directors may make and change from time to time such arrangements as they shall in their absolute discretion consider appropriate to:

 

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ensure that all members and proxies for members wishing to attend the meeting can do so;

 

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ensure that all persons attending the meeting are able to participate in the business of the meeting and to see and hear anyone else addressing the meeting;

 

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ensure the safety of persons attending the meeting and the orderly conduct of the meeting; and

 

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•

restrict the numbers of members and proxies at any one location to such number as can safely and conveniently be accommodated there.

Limitation on Owning Securities

Our Articles do not restrict in any way the ownership or voting of our shares by non-residents. Furthermore, there is no longer an obligation of a shareholder of a U.K. company which is a non-listed (in the U.K. or EU) company to voluntarily disclose his shareholding unless, required to do so by the company. If the company serves a demand on a person under section 793 to the Companies Act, that person will be required to disclose any interest he has in the shares of the company.

Change in Control

We can issue additional shares with any rights or restrictions attached to them as long as they are not restricted by any rights attached to existing shares. These rights or restrictions can be decided by the directors so long as there is no conflict with the Articles or any resolution passed by the shareholders. The ability of the directors to issue shares with rights or restrictions that are different than those attached to the currently outstanding shares could have the effect of delaying, deferring or preventing change of control of our company.

We may in the future be subject to the U.K. Takeover Code which is not binding on our company at the present time. Nevertheless, the U.K. Takeover Code could apply to our company under certain circumstances in the future and if that were to occur, if a person: (a) acquires an interest in our shares which, when taken together with shares in which he or persons acting in concert with him are interested, carries 30% or more of the voting rights of our shares; or (b) who, together with persons acting in concert with him, is interested in shares that in the aggregate carry not less than 30% and not more than 50% of the voting rights in the company, acquires additional interests in shares that increase the percentage of shares carrying voting rights in which that person is interested, in both cases, the acquirer and, depending on the circumstances its concert parties, would be required (except with the consent of the UK Takeover Panel) to make a cash offer for our outstanding shares at a price not less than the highest price paid for any interests in the shares by the acquirer or its concert parties during the previous 12 months.

Brazil Dividend Policy

Pursuant to the terms of a deed we will enter into with an Abengoa subsidiary holding our shares in its capacity as our shareholder prior to the consummation of the offering, generally, in the event the annual dividend paid by ACBH to us as holder of ACBH’s preferred equity is below $18.4 million in any given year, the Abengoa subsidiary holding our shares will agree that Abengoa Yield can defer the payment of a portion of the dividend from Abengoa Yield to that Abengoa subsidiary in an amount equal to such shortfall (similar arrangements will apply if that Abengoa subsidiary transfers any of our shares to any other member of the ACI Group). However, any such deferral will be made only if and to the extent that the Abengoa subsidiary holding our shares (or, where relevant, another member of the ACI Group) continues to be a shareholder of ours as of the relevant date. If the ACI Group’s ownership of us falls below a level such that the attributable share of our dividends to the ACI Group falls below $18.4 million, we have the option of requiring the relevant member or members of the ACI Group to purchase part or all of our preferred interest in ACBH so that the preferred dividend payable to us from ACBH following such purchase is equivalent to (but does not exceed) the ACI Group’s share of our dividend going forward.

The deed will cease to be in force when: (i) we cease to hold any exchangeable preferred equity investment in ACBH; (ii) we elect to exchange all of our preferred equity in ACBH for shares in ACBH’s projects; or (iii) the aggregate amount of dividends from projects owned by ACBH and paid to ACBH and which are freely distributable by ACBH to Abengoa Yield reaches a minimum of $36 million per financial year for three consecutive financial years (provided that at that time: (a) all assets held by ACBH have entered into commercial operation and (b) ACBH’s cash flow projections for the following 12 months indicate that ACBH will be able to pay the preferred dividend of $18.4 million to Abengoa Yield for the current fiscal year).

 

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Other UK Law Considerations

Squeeze-out

Under the Companies Act, if a takeover offer (as defined in section 974 of the Companies Act) is made for the shares of a company and the offeror were to acquire, or unconditionally contract to acquire, not less than 90% in value of the shares to which the takeover offer relates the Takeover Offer Shares, and not less than 90% of the voting rights attached to the Takeover Offer Shares within three months of the last day on which its offer can be accepted, it could acquire compulsorily the remaining 10%. It would do so by sending a notice to outstanding shareholders telling them that it will acquire compulsorily their Takeover Offer Shares and then, six weeks later, it would execute a transfer of the outstanding Takeover Offer Shares in its favor and pay the consideration to the company, which would hold the consideration on trust for outstanding shareholders. The consideration offered to the shareholders whose Takeover Offer Shares are acquired compulsorily under the Companies Act must, in general, be the same as the consideration that was available under the takeover offer.

Sell-out

The Companies Act also gives minority shareholders a right to be bought out in certain circumstances by an offeror who has made a takeover offer (as defined in Section 974 of the Companies Act). If a takeover offer related to all our shares and, at any time before the end of the period within which the offer could be accepted, the offeror held or had agreed to acquire not less than 90% of our shares to which the offer relates, any holder of our shares to which the offer related who had not accepted the offer could by a written communication to the offeror require it to acquire those shares. The offeror is required to give any shareholder notice of his right to be bought out within one month of that right arising. The offeror may impose a time limit on the rights of the minority shareholders to be bought out, but that period cannot end less than three months after the end of the acceptance period. If a shareholder exercises his or her rights, the offeror is bound to acquire those shares on the terms of the offer or on such other terms as may be agreed.

Disclosure of Interest in Shares

Pursuant to Part 22 of the Companies Act, the company is empowered by notice in writing to require any person whom the company knows to be, or has reasonable cause to believe to be, interested in the company’s shares or at any time during the three years immediately preceding the date on which the notice is issued to have been so interested, within a reasonable time to disclose to the company details of that person’s interest and (so far as is within such person’s knowledge) details of any other interest that subsists or subsisted in those shares. Under the Articles, if a member defaults in supplying the company with the required details in relation to the shares in question, or the Default Shares, the member shall not be entitled to vote or exercise any other right conferred by membership in relation to general meetings. Where the Default Shares represent 0.25% or more of the issued shares of the class in question, the directors may direct that (i) any dividend or other money payable in respect of the Default Shares shall be retained by the company without any liability to pay interest on it when such dividend or other money is finally paid to the member and/or (ii) no transfer by the relevant member of shares (other than transfer approved in accordance with the provisions of the Articles) may be registered (unless such member is not in default and the transfer does not relate to Default Shares).

Purchase of Own Shares

Under English law, a public limited company may purchase its own shares only out of the distributable profits of the company or the proceeds of a new issue of shares made for the purpose of financing the purchase. A public limited company may not purchase its own shares if as a result of the purchase there would no longer be any issued shares of the company other than redeemable shares or shares held as treasury shares. Subject to the foregoing, because the NASDAQ Global Market is not a “recognized investment exchange” under the Companies Act, the company may purchase its own fully paid shares only pursuant to a purchase contract authorized by ordinary resolution of the holders of its ordinary shares before the purchase takes place. Any authority will not be effective if any shareholder from whom we propose to purchase shares votes on the

 

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resolution and the resolution would not have been passed if such shareholder had not done so. The resolution authorizing the purchase must specify a date, not being later than five years after the passing of the resolution, on which the authority to purchase is to expire.

A share buy-back by the company of its ordinary shares will give rise to UK stamp duty at the rate of 0.5% of the amount or value of the consideration payable by the company, and such stamp duty will be paid by the company.

Our Articles do not have conditions governing changes in our capital which are more stringent than those required by law.

Distributions

Under the Companies Act, before a public company incorporated in England and Wales can lawfully make a distribution, it must ensure that it has sufficient distributable reserves (accumulated, realized profits, so far as not previously utilized by distribution or capitalization, less accumulated, realized losses, so far as not previously written off in a reduction or reorganization of capital duly made). In this regard, we intend to enter into a capital reduction pursuant to which share premium is converted into a distributable reserve in 2014 for this purpose. For more information on our cash dividend policy and the risks regarding such policy, see “Cash Dividend Policy.”

Differences in Corporate Law

The applicable provisions of the Companies Act differ from laws applicable to U.S. corporations and their shareholders. Set forth below is a summary of certain differences between the provisions of the Companies Act applicable to us and the Delaware General Corporation Law relating to shareholders’ rights and protections. This summary is not intended to be a complete discussion of the respective rights and it is qualified in its entirety by reference to English law and Delaware law.

 

		England and Wales		Delaware
Number of Directors		Under the Companies Act, a public limited company must have at least two directors and the number of directors may be fixed by or in the manner provided in a company’s articles of association.		Under Delaware law, a corporation must have at least one director and the number of directors shall be fixed by or in the manner provided in the bylaws.
Removal of Directors		Under the Companies Act, shareholders may remove a director without cause by an ordinary resolution (which is passed by a simple majority of those voting in person or by proxy at a general meeting) irrespective of any provisions of any service contract the director has with the company, provided that 28 clear days’ notice of the resolution is given to the company and its shareholders and certain other procedural requirements under the Companies Act are followed (such as allowing the director to make representations against his or her removal either at the meeting or in writing).		Under Delaware law, unless otherwise provided in the certificate of incorporation, directors may be removed from office, with or without cause, by a majority stockholder vote, though in the case of a corporation whose board is classified, stockholders may effect such removal only for cause.

 

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		England and Wales		Delaware
Vacancies on the Board of Directors		Under English law, the procedure by which directors (other than a company’s initial directors) are appointed is generally set out in a company’s articles of association, provided that where two or more persons are appointed as directors of a public limited company by resolution of the shareholders, resolutions appointing each director must be voted on individually unless a resolution of the shareholders that such resolutions do not have to be voted on individually is first agreed to by the meeting without any vote being given against it.		Under Delaware law, vacancies on a corporation’s board of directors, including those caused by an increase in the number of directors, may be filled by a majority of the remaining directors.
Annual General Meeting		Under the Companies Act, a public limited company must hold an annual general meeting in each six-month period following the company’s annual accounting reference date.		Under Delaware law, the annual meeting of stockholders shall be held at such place, on such date and at such time as may be designated from time to time by the board of directors or as provided in the certificate of incorporation or by the bylaws.
General Meeting		Under the Companies Act, a general meeting of the shareholders of a public limited company may be called by the directors.   Shareholders holding at least 5% of the paid-up capital of the company carrying voting rights at general meetings can require the directors to call a general meeting.		Under Delaware law, special meetings of the stockholders may be called by the board of directors or by such person or persons as may be authorized by the certificate of incorporation or by the bylaws.
Notice of General Meetings		Under the Companies Act, 21 clear days’ notice must be given for an annual general meeting and any resolutions to be proposed at the meeting. Subject to a company’s articles of association providing for a longer period, at least 14 clear days’ notice is required for any other general meeting. In addition, certain matters (such as the removal of directors or auditors) require special notice, which is 28 clear days’ notice. The shareholders of a company may in all cases consent to a shorter notice period, the proportion of shareholders’ consent required being 100% of those entitled to attend and vote in the case of an annual general meeting and, in the case of any other general meeting, a majority in number of the		Under Delaware law, unless otherwise provided in the certificate of incorporation or bylaws, written notice of any meeting of the stockholders must be given to each stockholder entitled to vote at the meeting not less than ten nor more than 60 days before the date of the meeting and shall specify the place, date, hour, and purpose or purposes of the meeting.

 

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		England and Wales		Delaware
		members having a right to attend and vote at the meeting, being a majority who together hold not less than 95% in nominal value of the shares giving a right to attend and vote at the meeting. Neither of these thresholds can be changed by a company’s articles of association.
Proxy		Under the Companies Act, at any meeting of shareholders, a shareholder may designate another person to attend, speak and vote at the meeting on their behalf by proxy.		Under Delaware law, at any meeting of stockholders, a stockholder may designate another person to act for such stockholder by proxy, but no such proxy shall be voted or acted upon after three years from its date, unless the proxy provides for a longer period.
Preemptive Rights		Under the Companies Act, “equity securities” (being (i) shares in the company other than shares that, with respect to dividends and capital, carry a right to participate only up to a specified amount in a distribution (“ordinary shares”) or (ii) rights to subscribe for, or to convert securities into, ordinary shares) proposed to be allotted for cash must be offered first to the existing equity shareholders in the company in proportion to the respective nominal value of their holdings, unless an exception applies or a special resolution to the contrary has been passed by shareholders in a general meeting or the articles of association provide otherwise in each case in accordance with the provisions of the Companies Act.		Under Delaware law, unless otherwise provided in a corporation’s certificate of incorporation, a stockholder does not, by operation of law, possess preemptive rights to subscribe to additional issuances of the corporation’s stock.
Liability of Directors and Officers		Under the Companies Act, any provision (whether contained in a company’s articles of association or any contract or otherwise) that purports to exempt a director of a company (to any extent) from any liability that would otherwise attach to him in connection with any negligence, default, breach of duty or breach of trust in relation to the company is void.   Any provision by which a company directly or indirectly provides an indemnity (to any extent) for a director of the company or of an associated company against any liability attaching to him in connection with any negligence, default,		Under Delaware law, a corporation’s certificate of incorporation may include a provision eliminating or limiting the personal liability of a director to the corporation and its stockholders for damages arising from a breach of fiduciary duty as a director. However, no provision can limit the liability of a director for:   •    any breach of the director’s duty of loyalty to the corporation or its stockholders;   •    acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

 

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		England and Wales		Delaware
		breach of duty or breach of trust in relation to the company of which he is a director is also void except as permitted by the Companies Act, which provides exceptions for the company to: (i) purchase and maintain insurance against such liability; (ii) provide a “qualifying third party indemnity” (being an indemnity against liability incurred by the director to a person other than the company or an associated company. Such indemnity must not cover criminal fines, penalties imposed by regulatory bodies, the defense costs of criminal proceedings where the director is found guilty, the defense costs of civil proceedings successfully brought against the director by the company or an associated company, and the costs of unsuccessful applications by the director for relief); and (iii) provide a “qualifying pension scheme indemnity” (being an indemnity against liability incurred in connection with the company’s activities as trustee of an occupational pension plan). Such indemnity must not cover a fine imposed in criminal proceedings, or sum payable to a regulatory authority by way of a penalty in respect of non-compliance with any requirement of a regulatory nature (however arising), or any liability incurred by the director in defending criminal proceedings in which he is convicted).		•    intentional or negligent payment of unlawful dividends or stock purchases or redemptions; or   •    any transaction from which the director derives an improper personal benefit.
Voting Rights		Under English law, unless a poll is demanded by the shareholders of a company or is required by the chairman of the meeting or the company’s articles of association, shareholders shall vote on all resolutions on a show of hands. Under the Companies Act, a poll may be demanded by: (i) not fewer than five shareholders having the right to vote on the resolution; (ii) any shareholder(s) representing at least 10% of the total voting rights of all the shareholders having the right to vote on the resolution (excluding any voting rights attached to treasury shares); or (iii) any shareholder (s) holding shares in the company conferring a right to vote on the resolution being shares on which an		Delaware law provides that, unless otherwise provided in the certificate of incorporation, each stockholder is entitled to one vote for each share of capital stock held by such stockholder.

 

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		England and Wales		Delaware
		aggregate sum has been paid up equal to not less than 10% of the total sum paid up on all the shares conferring that right. A company’s articles of association may provide more extensive rights for shareholders to call a poll.   Under English law, an ordinary resolution is passed on a show of hands if it is approved by a simple majority (more than 50%) of the votes cast by shareholders present (in person or by proxy) and entitled to vote. If a poll is demanded, an ordinary resolution is passed if it is approved by holders representing a simple majority of the total voting rights of shareholders present (in person or by proxy) who (being entitled to vote) vote on the resolution. Special resolutions require the affirmative vote of not less than 75% of the votes cast by shareholders present (in person or by proxy) at the meeting.
Shareholder Vote on Certain Transactions		The Companies Act provides for schemes of arrangement, which are arrangements or compromises between a company and any class of shareholders or creditors and used in certain types of reconstructions, amalgamations, capital reorganizations or takeovers. These arrangements require:   •    the approval at a shareholders’ or creditors’ meeting convened by order of the court, of a majority in number of shareholders or creditors representing 75% in value of the capital held by, or debt owed to, the class of shareholders or creditors, or class thereof present and voting, either in person or by proxy; and   •    the approval of the court.		Generally, under Delaware law, unless the certificate of incorporation provides for the vote of a larger portion of the stock, completion of a merger, consolidation, sale, lease or exchange of all or substantially all of a corporation’s assets or dissolution requires:   •    the approval of the board of directors; and   •    approval by the vote of the holders of a majority of the outstanding stock or, if the certificate of incorporation provides for more or less than one vote per share, a majority of the votes of the outstanding stock of a corporation entitled to vote on the matter.
Standard of Conduct for Directors		Under English law, a director owes various statutory and fiduciary duties to the company, including:   •    to act in the way he considers, in good faith, would be most likely to promote the success of the company for the benefit of its members as a whole;		Delaware law does not contain specific provisions setting forth the standard of conduct of a director. The scope of the fiduciary duties of directors is generally determined by the courts of the State of Delaware. In general, directors have a duty to act without self-interest, on a well-informed basis and in a manner they reasonably believe to be in the best interest of the stockholders.

 

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		England and Wales		Delaware
		•    to avoid a situation in which he has, or can have, a direct or indirect interest that conflicts, or possibly conflicts, with the interests of the company;   •    to act in accordance with the company’s constitution and only exercise his powers for the purposes for which they are conferred;   •    to exercise independent judgment;   •    to exercise reasonable care, skill and diligence;   •    not to accept benefits from a third party conferred by reason of his being a director or doing (or not doing) anything as a director; and   •    a duty to declare any interest that he has, whether directly or indirectly, in a proposed or existing transaction or arrangement with the company.
Stockholder Suits		Under English law, generally, the company, rather than its shareholders, is the proper claimant in an action in respect of a wrong done to the company or where there is an irregularity in the company’s internal management. Notwithstanding this general position, the Companies Act provides that (i) a court may allow a shareholder to bring a derivative claim (that is, an action in respect of and on behalf of the company) in respect of a cause of action arising from a director’s negligence, default, breach of duty or breach of trust and (ii) a shareholder may bring a claim for a court order where the company’s affairs have been or are being conducted in a manner that is unfairly prejudicial to some of its shareholders.		Under Delaware law, a stockholder may initiate a derivative action to enforce a right of a corporation if the corporation fails to enforce the right itself. The complaint must:   •    state that the plaintiff was a stockholder at the time of the transaction of which the plaintiff complains or that the plaintiffs shares thereafter devolved on the plaintiff by operation of law; and   •    allege with particularity the efforts made by the plaintiff to obtain the action the plaintiff desires from the directors and the reasons for the plaintiff’s failure to obtain the action; or   •    state the reasons for not making the effort.   Additionally, the plaintiff must remain a stockholder through the duration of the derivative suit. The action will not be dismissed or compromised without the approval of the Delaware Court of Chancery.

Exchange Listing

We have applied to list our shares on the NASDAQ Global Select Market under the symbol “ABY”.

Transfer Agent and Registrar

The transfer agent and registrar for our ordinary shares is Computershare Trust Company, N.A.

 

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SHARES ELIGIBLE FOR FUTURE SALE

Future sales of substantial amounts of our shares in the public market, or the perception that such sales may occur, could adversely affect the prevailing market price of our shares. No prediction can be made as to the effect, if any, future sales of shares, or the availability of our shares for future sales, will have on the market price of our shares prevailing from time to time. The number of shares available for future sale in the public market is subject to legal and contractual restrictions, some of which are described below. The expiration of these restrictions will permit sales of substantial amounts of our shares in the public market, or could create the perception that these sales may occur, which could adversely affect the prevailing market price of our shares. These factors also could make it more difficult for us to raise funds through future offerings of our shares.

Upon the consummation of this offering, we will have issued and outstanding an aggregate of 80 million shares. All of the shares to be sold in this offering will be freely tradable without restriction or further registration under the Securities Act, except for any such shares held or acquired by an “affiliate” of ours, as that term is defined in Rule 144 promulgated under the Securities Act, or Rule 144, which shares will be subject to the volume limitations and other restrictions of Rule 144 described below. The remaining shares that will be outstanding upon completion of this offering will be “restricted securities,” as that phrase is defined in Rule 144, and may be resold only after registration under the Securities Act or pursuant to an exemption from such registration, including, among others, the exemptions provided by Rule 144, which rules are summarized below. These remaining shares that will be outstanding upon completion of this offering will be available for sale in the public market after the expiration of the lock-up agreements described in “Underwriting,” taking into account the provisions of Rule 144.

Rule 144

The shares being sold in this offering will generally be freely tradable without restriction or further registration under the Securities Act, except that any shares held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits shares that have been acquired by a person who is an affiliate of ours, or has been an affiliate of ours within the past three months, to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

•

1% of the total number of our outstanding shares which will equal approximately              shares after this offering; or

 

•

the average weekly reported trading volume of our shares on the NASDAQ Global Select Market for the four calendar weeks prior to the sale.

Such sales are also subject to specific manner-of-sale provisions, a six-month holding period requirement for restricted securities, notice requirements and the availability of current public information about us. An “affiliate” is a person that directly, or indirectly through one or more intermediaries, controls or is controlled by, or is under common control with an issuer.

Rule 144 also provides that a person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has for at least six months beneficially owned shares that are restricted securities (including the holding period of any prior owner other than an affiliate), will be entitled to freely sell such shares subject only to the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has for at least one year beneficially owned shares that are restricted securities (including the holding period of any prior owner other than an affiliate), will be entitled to freely sell such shares under Rule 144 without regard to the public information requirements of Rule 144. To the extent that any of our affiliates sell their shares, other than pursuant to Rule 144 or a registration statement, the purchaser’s holding period for the purpose of effecting a sale under Rule 144 commences on the date of the transfer from the affiliate.

 

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Lock-Up Agreements

We expect that we, the selling shareholder, each other Abengoa entity holding our shares and our directors and executive officers will enter into lock-up agreements under which we and they will agree that we and they will not sell, directly or indirectly, any shares for a period of 180 days from the date of this prospectus (subject to certain exceptions) without the prior written consent of the representatives. See “Underwriting.”

 

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TAXATION

Material U.K. Tax Considerations

The following is a general summary of material U.K. tax considerations relating to the ownership and disposal of our shares. The comments set out below are based on current United Kingdom tax law as applied in England and Wales and HM Revenue & Customs, or HMRC, practice (which may not be binding on HM Revenue & Customs) as at the date of this summary, both of which are subject to change, possibly with retrospective effect. They are intended as a general guide and apply only to our shareholders resident and, in the case of an individual, domiciled for tax purposes in the United Kingdom and to whom “split year” treatment does not apply (except insofar as express reference is made to the treatment of non-United Kingdom residents), who hold our shares as an investment and who are the absolute beneficial owners thereof. The discussion does not address all possible tax consequences relating to an investment in the shares. Certain categories of shareholders, including those carrying on certain financial activities, those subject to specific tax regimes or benefitting from certain reliefs or exemptions, those connected with us and those for whom the shares are employment-related securities may be subject to special rules and this summary does not apply to such shareholders and any general statements made in this disclosure do not take them into account. This summary does not address any inheritance tax considerations.

This summary is for general information only and is not intended to be, nor should it be considered to be, legal or tax advice to any particular investor. It does not address all of the tax considerations that may be relevant to specific investors in light of their particular circumstances or to investors subject to special treatment under U.K. tax law. In particular:

POTENTIAL INVESTORS SHOULD SATISFY THEMSELVES PRIOR TO INVESTING AS TO THE OVERALL TAX CONSEQUENCES, INCLUDING, SPECIFICALLY, THE CONSEQUENCES UNDER U.K. TAX LAW AND HMRC PRACTICE OF THE ACQUISITION, OWNERSHIP AND DISPOSAL OF THE SHARES IN THEIR OWN PARTICULAR CIRCUMSTANCES BY CONSULTING THEIR OWN TAX ADVISORS.

Taxation of dividends

We will not be required to withhold amounts on account of United Kingdom tax at source when paying a dividend in respect of our shares whether to U.K. resident or non-U.K. resident shareholders.

A United Kingdom resident individual shareholder who receives a dividend from us will be entitled to a tax credit which may be set off against the shareholder’s total income tax liability. The tax credit will be equal to 10% of the aggregate of the dividend and the tax credit (the “gross dividend”), which is also equal to one-ninth of the cash dividend received. Such an individual shareholder who is liable to income tax at the basic rate will be subject to tax on the dividend at the rate of 10% of the gross dividend, so that the tax credit will satisfy in full such shareholder’s liability to income tax on the dividend. In the case of such an individual shareholder who is liable to income tax at the higher rate, the tax credit will be set against but not fully match the shareholder’s tax liability on the gross dividend and such shareholder will have to account for additional income tax equal to 22.5% of the gross dividend (which is also equal to 25% of the cash dividend received) to the extent that the gross dividend when treated as the top slice of the shareholder’s income falls above the threshold for higher rate income tax. In the case of such an individual shareholder who is subject to income tax at the additional rate, the tax credit will also be set against but not fully match the shareholder’s liability on the gross dividend and such shareholder will have to account for additional income tax equal to 27.5% of the gross dividend (which is also equal to approximately 30.6% of the cash dividend received) to the extent that the gross dividend when treated as the top slice of the shareholder’s income falls above the threshold for additional rate income tax.

A United Kingdom resident individual shareholder who is not liable to income tax in respect of the gross dividend and other United Kingdom resident taxpayers who are not liable to United Kingdom tax on dividends will not be entitled to claim repayment of the tax credit attaching to dividends paid by us.

 

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Shareholders who are within the charge to corporation tax will be subject to corporation tax on dividends paid by us, unless (subject to special rules for such shareholders that are small companies) the dividends fall within an exempt class and certain other conditions are met. Each shareholder’s position will depend on its own individual circumstances, although it would normally be expected that the dividends paid by us would fall within an exempt class. Such shareholders will not be able to claim repayment of tax credits attaching to dividends.

Non-United Kingdom resident shareholders who hold their shares as an investment and not in connection with any trade carried on by them will not be subject to United Kingdom tax in respect of any dividends. Non-United Kingdom resident shareholders will not generally be able to claim repayment from HM Revenue & Customs of any part of the tax credit attaching to dividends paid by us. A shareholder resident outside the United Kingdom may also be subject to foreign taxation on dividend income under local law. Shareholders who are not resident for tax purposes in the United Kingdom should obtain their own tax advice concerning tax liabilities on dividends received from us.

Taxation of disposals

U.K. Holders

Shareholders who are resident in the United Kingdom, or, in the case of individuals, who cease to be resident in the United Kingdom for a period of five years or less, may depending on their circumstances (including the availability of exemptions or reliefs), be liable to United Kingdom taxation on chargeable gains in respect of gains arising from a sale or other disposal of our shares.

Non-U.K. Holders

An individual holder who is not a U.K. Holder will not be liable to U.K. capital gains tax on capital gains realized on the disposal of his or her shares unless such holder carries on (whether solely or in partnership) a trade, profession or vocation in the United Kingdom through a branch or agency in the United Kingdom to which the shares are attributable. In these circumstances, such holder may, depending on his or her individual circumstances, be chargeable to U.K. capital gains tax on chargeable gains arising from a disposal of his or her shares.

A corporate holder of shares that is not a U.K. Holder will not be liable for U.K. corporation tax on chargeable gains realized on the disposal of its shares unless it carries on a trade in the United Kingdom through a permanent establishment to which the shares are attributable. In these circumstances, a disposal of shares by such holder may give rise to a chargeable gain or an allowable loss for the purposes of U.K. corporation tax.

Stamp duty and stamp duty reserve tax

The stamp duty and stamp duty reserve tax, or SDRT, treatment of the issue and transfer of, and the agreement to transfer, our shares outside a depositary receipt system or a clearance service are discussed in the paragraphs under ‘General’ below. The stamp duty and SDRT treatment of such transactions in relation to such systems are discussed in the paragraphs under “Depositary Receipt Systems and Clearance Services” below.

General

The issue of new shares under the primary offering does not give rise to a SDRT liability, according to the HM Revenue & Customs practice and recent case law and will not be subject to stamp duty.

An agreement to transfer our shares will normally give rise to a charge to SDRT at the rate of 0.5% of the amount or value of the consideration payable for the transfer. SDRT is, in general, payable by the purchaser.

Transfers of our shares will generally be subject to stamp duty at the rate of 0.5% of the consideration given for the transfer (rounded up to the next £5). The purchaser normally pays the stamp duty.

 

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If a duly stamped transfer completing an agreement to transfer is produced within six years of the date on which the agreement is made (or, if the agreement is conditional, the date on which the agreement becomes unconditional) any SDRT already paid is generally repayable, normally with interest, and any SDRT charge yet to be paid is cancelled.

Depositary Receipt Systems and Clearance Services

Following the ECJ decision in C-569/07 HSBC Holdings Plc, Vidacos Nominees Limited v The Commissioners of Her Majesty’s Revenue & Customs and the First-tier Tax Tribunal decision in HSBC Holdings Plc and The Bank of New York Mellon Corporation v The Commissioners of Her Majesty’s Revenue & Customs, HM Revenue & Customs has confirmed that 1.5% SDRT is no longer payable when new shares are issued to a clearance service (such as, in our understanding, DTC) or depositary receipt system.

Where our shares are transferred (i) to, or to a nominee or an agent for, a person whose business is or includes the provision of clearance services or (ii) to, or to a nominee or an agent for, a person whose business is or includes issuing depositary receipts, stamp duty or SDRT will generally be payable at the higher rate of 1.5% of the amount or value of the consideration given or, in certain circumstances, the value of the shares.

There is an exception from the 1.5% charge on the transfer to, or to a nominee or agent for, a clearance service where the clearance service has made and maintained an election under section 97A(1) of the Finance Act 1986, which has been approved by HM Revenue & Customs. In these circumstances, SDRT at the rate of 0.5% of the amount or value of the consideration payable for the transfer will arise on any transfer of our shares into such an account and on subsequent agreements to transfer such shares within such account. It is our understanding that DTC has not made an election under section 97A(1) of the Finance Act of 1986.

Any liability for stamp duty or SDRT in respect of a transfer into a clearance service or depositary receipt system, or in respect of a transfer within such a service, which does arise will strictly be accountable by the clearance service or depositary receipt system operator or their nominee, as the case may be, but will, in practice, be payable by the participants in the clearance service or depositary receipt system.

The Proposed Financial Transactions Tax

The European Commission has published a proposal for a Directive for a common Financial Transactions Tax, or FTT, in Belgium, Germany, Estonia, Greece, Spain, France, Italy, Austria, Portugal, Slovenia and Slovakia (the “participating Member States”).

The proposed FTT has very broad scope and could, if introduced in its current form, apply to certain dealings in our shares (including secondary market transactions) in certain circumstances.

Under current proposals the FTT could apply in certain circumstances to persons both within and outside of the participating Member States. Generally, it would apply to certain dealings in our shares where at least one party is a financial institution, and at least one party is established in a participating Member State. A financial institution may be, or be deemed to be, “established” in a participating Member State in a broad range of circumstances, including (i) by transacting with a person established in a participating Member State or (ii) where the financial instrument which is subject to the dealings is issued in a participating Member State.

The FTT proposal remains subject to negotiation between the participating Member States. Further, the legality of the FTT proposals is at present uncertain. It may therefore be altered prior to any implementation, the timing of which remains unclear. Additional EU Member States may decide to participate. Prospective holders of our shares are advised to seek their own professional advice in relation to the FTT.

Material U.S. Federal Income Tax Considerations

The following is a summary of material U.S. federal income tax consequences of the acquisition, ownership and disposition of shares by U.S. Holders (as defined below) who are initial purchasers of the shares. This

 

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summary is based upon U.S. federal income tax laws (including the IRC, final, temporary and proposed Treasury regulations, rulings, judicial decisions and administrative pronouncements), and the income tax treaty between the United States and the United Kingdom, or the Treaty, all as of the date hereof and all of which are subject to changes in wording or administrative or judicial interpretation occurring after the date hereof, possibly with retroactive effect.

As used herein, the term “U.S. Holder” means a beneficial owner of shares:

 

(a)

that is, for U.S. federal income tax purposes, (i) a citizen or resident of the United States, (ii) a corporation (or other entity taxable as a corporation) created or organized in or under the laws of the United States or any political subdivision thereof, (iii) an estate the income of which is subject to U.S. federal income taxation regardless of its source, or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust, or the trust has validly elected to be treated as a domestic trust for U.S. federal income tax purposes;

 

(b)

that holds the shares as capital assets for U.S. federal income tax purposes; and

 

(c)

that owns, directly, indirectly or by attribution, less than 10% of the share capital or voting stock of Abengoa Yield.

This summary does not cover all aspects of U.S. federal income taxation that may be relevant to, or the actual tax effect that any of the matters described herein will have on, the acquisition, ownership or disposition of shares by particular investors, and does not address state, local, foreign or other tax laws. This summary does not address all of the U.S. federal income tax considerations that may apply to U.S. Holders that are subject to special tax rules, such as certain U.S. expatriates, insurance companies, tax-exempt organizations, certain financial institutions, persons subject to the alternative minimum tax or the net investment income tax, dealers and certain traders in securities or currencies, persons holding shares as part of a straddle, hedging, conversion or other integrated transaction, persons who acquired their shares pursuant to the exercise of employee stock options or otherwise as compensation, partners in entities classified as partnerships for U.S. federal income tax purposes, persons holding shares through an individual retirement account or other tax-deferred account, or persons whose functional currency is not the U.S. dollar or persons that carry on a trade, business or vocation in the United Kingdom through a branch, agency or permanent establishment to which the shares are attributable. Such U.S. holders may be subject to U.S. federal income tax consequences different from those set forth below.

If an entity classified as partnership for U.S. federal income tax purposes holds shares, the U.S. federal income tax treatment of a partner in such entity generally will depend upon the status of the partner and the activities of the partnership. An entity treated as a partnership for U.S. federal income tax purposes that holds shares and its partners are urged to consult their own tax advisor regarding the specific U.S. federal income tax consequences to the partnership and its partners of acquiring, owning and disposing of the shares.

This discussion assumes that Abengoa Yield is not, and will not become, a passive foreign investment company, or PFIC, for U.S. federal income tax purposes, as discussed below under “—Passive foreign investment company rules.”

Potential investors in shares should consult their own tax advisors concerning the specific U.S. federal, state and local tax consequences of the ownership and disposition of shares in light of their particular situations as well as any consequences arising under the laws of any other taxing jurisdiction.

Taxation of distributions on the shares

Distributions received by a U.S. Holder on shares generally will constitute dividends to the extent paid out of Abengoa Yield’s current or accumulated earnings and profits (as determined for U.S. federal income tax

 

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purposes). Abengoa Yield intends to annually calculate its earnings and profits in accordance with U.S. federal income tax principles. If distributions exceed Abengoa Yield’s current and accumulated earnings and profits, such excess distributions will constitute a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in its shares and will result in a reduction of such tax basis. To the extent such excess exceeds a U.S. Holder’s tax basis in the shares, such excess will generally be taxed as capital gain.

Subject to certain exceptions for short-term and hedged positions, dividends received by certain non-corporate U.S. Holders of shares generally will be subject to U.S. federal income taxation at rates lower than those applicable to other ordinary income if the dividends are “qualified dividends.” Distributions received by a U.S. Holder on shares will be qualified dividends if: (i) shares are readily tradable on an established securities market in the United States (such as NASDAQ Global Market, which we have applied for the shares to be listed on) and (ii) Abengoa Yield was not, for the year prior to the year in which the dividends are paid, and is not, for the year in which the dividends are paid, a PFIC. As discussed below under “—Passive foreign investment company rules,” although there can be no assurance that Abengoa Yield will not be considered a PFIC for any taxable year, Abengoa Yield does not believe that it will be a PFIC for its current taxable year and does not expect to be a PFIC in the foreseeable future. Non-corporate U.S. Holders should consult their own tax advisors to determine whether they are subject to any special rules that limit their ability to be taxed at these favorable rates. Corporate U.S. Holders will not be entitled to claim the dividends-received deduction with respect to dividends paid by Abengoa Yield. Dividends will be included in a U.S. Holder’s income on the date of the U.S. Holder’s receipt of the dividend.

Taxation upon sale or other disposition of shares

A U.S. Holder generally will recognize U.S. source capital gain or loss on the sale or other disposition of shares, which will generally be long-term capital gain or loss if the U.S. Holder has held such shares for more than one year. The amount of the U.S. Holder’s gain or loss will be equal to the difference between such U.S. Holder’s adjusted tax basis in the shares sold or otherwise disposed of and the amount realized on the sale or other disposition. Net long-term capital gain recognized by certain non-corporate U.S. Holders will be taxed at a lower rate than the rate applicable to ordinary income. The deductibility of capital losses is subject to limitations.

Passive foreign investment company rules

If Abengoa Yield were a PFIC for any taxable year during which a U.S. Holder held shares, certain adverse U.S. federal income tax consequences may apply to the U.S. Holder. Abengoa Yield does not believe that it will be a PFIC for its current taxable year and does not expect to be a PFIC in the foreseeable future. However, PFIC status depends on the composition of a company’s income and assets and the fair market value of its assets (including, among others, less than 25% owned equity investments) from time to time, as well as on the application of complex statutory and regulatory rules that are subject to potentially varying or changing interpretations. Accordingly, there can be no assurance that Abengoa Yield will not be considered a PFIC for any taxable year.

A non-U.S. corporation will be a PFIC in any taxable year in which, after taking into account the income and assets of the corporation and certain subsidiaries pursuant to applicable “look-through rules,” either: (i) at least 75% of its gross income is “passive income” or (ii) at least 50% of the average value of its assets is attributable to assets which produce passive income or are held for the production of passive income. For purposes of the PFIC rules, “passive income” includes, among other things, certain foreign currency gains and the excess of gains over losses from certain commodities transactions. Gains from commodities transactions, however, are generally excluded from the definition of passive income if such gains are active business gains from the sale of commodities and the foreign corporation’s commodities meet specified criteria.

If Abengoa Yield were a PFIC for any taxable year during which a U.S. Holder held shares, gain recognized by a U.S. Holder on a sale or other disposition of the shares would generally be allocated ratably over the

 

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U.S. Holder’s holding period for the shares. The amounts allocated to the taxable year of the sale or other disposition and to any year before Abengoa Yield became a PFIC would be taxed as ordinary income. The amount allocated to each other taxable year would be subject to U.S. federal income tax at the highest rate in effect in that year for individuals or corporations, as appropriate, and an interest charge would be imposed on the resulting U.S. federal income tax liability. The same treatment would generally apply to any distribution in respect of shares to the extent the distribution exceeds 125% of the average of the annual distributions on shares received by the U.S. Holder during the preceding three years or the U.S. Holder’s holding period, whichever is shorter. Certain elections may be available that would result in alternative treatments (such as mark-to-market treatment) of the shares.

In addition, if Abengoa Yield were a PFIC for a taxable year in which it pays a dividend or in the prior taxable year, the favorable dividend rate discussed above with respect to dividends paid to certain non-corporate U.S. Holders would not apply.

Information reporting and backup withholding

Payments of dividends and sales proceeds that are made within the United States or through certain U.S. financial intermediaries generally are subject to information reporting and to backup withholding unless the U.S. Holder is a corporation or other exempt recipient or, in the case of backup withholding, the U.S. Holder provides a correct taxpayer identification number and certifies that it is not subject to backup withholding. The amount of any backup withholding from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability and may entitle such U.S. Holder to a refund, provided that the required information is timely furnished to the Internal Revenue Service.

Certain U.S. Holders who are individuals may be required to report information relating to their ownership of an interest in certain foreign financial assets, including stock and securities of a non-U.S. person (such as Abengoa Yield), subject to exceptions (including an exception for stock and securities held through a U.S. financial institution). Other U.S. Holders may be subject to similar rules in the future. U.S. Holders should consult their tax advisors regarding their reporting obligations with respect to the shares.

 

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UNDERWRITING

Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are acting as book-running managers and representatives of the underwriters named below in respect of the offering. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of shares set forth opposite the underwriter’s name.

 

Underwriter		Number of Shares
Citigroup Global Markets Inc.
Merrill Lynch, Pierce, Fenner & Smith Incorporated
Total

The underwriting agreement provides that the obligations of the underwriters to purchase the shares included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the shares (other than those covered by the over-allotment option described below) if they purchase any of the shares.

Shares sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $             per share. If all the shares are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The representative has advised us that the underwriters do not intend to make sales to discretionary accounts.

If the underwriters sell more shares than the total number set forth in the table above, the selling shareholder has granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to an additional              shares at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional shares approximately proportionate to that underwriter’s initial purchase commitment. Any over-allotment shares issued or sold under the option will be issued and sold by the selling shareholder on the same terms and conditions as the other shares that are the subject of this offering.

We, the selling shareholder, each other Abengoa entity holding our shares and our officers and directors listed in the “Management” section have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of the representatives and, subject to certain exceptions, dispose of or hedge any shares, or any securities convertible into or exchangeable for our shares. The representatives in their sole discretion may release any of the securities subject to these lock-up agreements at any time, which, in the case of officers and directors, shall be with notice.

Prior to this offering, there has been no public market for our shares. Consequently, the initial public offering price for the shares was determined by negotiations between us and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly-traded companies considered comparable to our company. We cannot assure you, however, that the price at which the shares will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our shares will develop and continue after this offering.

We have applied to have our shares listed on the NASDAQ Global Market under the symbol “ABY”.

 

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The following table shows the underwriting discounts and commissions that we and the selling shareholder are to pay to the underwriters in connection with this offering.

 

Selling Shareholder

Abengoa Yield

No Exercise

Full Exercise

Per share

$

$

$

Total

$

$

$

Abengoa will pay the offering expenses, other than the underwriting discounts and commissions payable by us, and certain expenses payable by the underwriters. In addition, the underwriters have agreed to reimburse Abengoa $             for certain expenses in connection with this offering.

In connection with the offering, the underwriters may purchase and sell shares in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the over-allotment option, and stabilizing purchases.

Short sales involve secondary market sales by the underwriters of a greater number of shares than they are required to purchase in the offering. “Covered” short sales are sales of shares in an amount up to the number of shares represented by the underwriters’ over-allotment option. “Naked” short sales are sales of shares in an amount in excess of the number of shares represented by the underwriters’ over-allotment option.

Covering transactions involve purchases of shares either pursuant to the underwriters’ over-allotment option or in the open market in order to cover short positions. To close a naked short position, the underwriters must purchase shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering. To close a covered short position, the underwriters must purchase shares in the open market or must exercise the over-allotment option. In determining the source of shares to close the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option.

Stabilizing transactions involve bids to purchase shares so long as the stabilizing bids do not exceed a specified maximum.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the shares. They may also cause the price of the shares to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the NASDAQ Global Market, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

Conflicts of Interest

The underwriters are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. The underwriters and their respective affiliates have in the past performed commercial banking, investment banking and advisory services for us and our affiliates, including Abengoa, from time to time for which they have received customary fees and reimbursement of expenses and may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. In the

 

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ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. In addition, affiliates of some of the underwriters are lenders, and in some cases agents or managers for the lenders, under certain of our credit facilities and other credit arrangements or those of our affiliates. In their capacity as lenders, such lender affiliates may, in the future, seek a reduction of a loan commitment to us or our affiliates, or impose incremental pricing or collateral requirements with respect to such facilities or credit arrangements, in the ordinary course of business. See “Risk Factors—Risks Related to Our Indebtedness.” In addition, certain of the underwriters or their affiliates that have a lending relationship with us routinely hedge their credit exposure to us consistent with their customary risk management policies. A typical such hedging strategy would include these underwriters or their affiliates hedging such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of shares described in this prospectus may not be made to the public in that relevant member state other than:

 

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;

 

•

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150 natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by us for any such offer; or

 

•

in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of shares shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe for the shares, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state) and includes any relevant implementing measure in the relevant member state. The expression 2010 PD Amending Directive means Directive 2010/73/EU.

The sellers of the shares have not authorized and do not authorize the making of any offer of shares through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the shares as contemplated in this prospectus. Accordingly, no purchaser of the shares, other than the underwriters, is authorized to make any further offer of the shares on behalf of the sellers or the underwriters.

 

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Notice to Prospective Investors in the United Kingdom

This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (each such person being referred to as a “relevant person”). The securities are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such securities will be engaged in only with, relevant persons. Any person in the United Kingdom that is not a relevant person should not act or rely on this document or any of its contents.

Notice to Prospective Investors in France

Neither this prospectus nor any other offering material relating to the shares described in this prospectus has been submitted to the clearance procedures of the Autorite des Marches Financiers or of the competent authority of another member state of the European Economic Area and notified to the Autorite des Marches Financiers. The shares have not been offered or sold and will not be offered or sold, directly or indirectly, to the public in France. Neither this prospectus nor any other offering material relating to the shares has been or will be:

 

•

released, issued, distributed or caused to be released, issued or distributed to the public in France; or

 

•

used in connection with any offer for subscription or sale of the shares to the public in France.

Such offers, sales and distributions will be made in France only:

 

•

to qualified investors (investisseurs qualifies) and/or to a restricted circle of investors (cercle restreint d’investisseurs), in each case investing for their own account, all as defined in, and in accordance with articles L.411-2, D.411-1, D.411-2, D.734-1, D.744-1, D.754-1 and D.764-1 of the French Code monetaire et financier;

 

•

to investment services providers authorized to engage in portfolio management on behalf of third parties; or

 

•

in a transaction that, in accordance with article L.411-2-II-1°-or-2°-or 3° of the French Code monetaire et financier and article 211-2 of the General Regulations (Reglement General) of the Autorite des Marches Financiers, does not constitute a public offer (appel public à l’epargne).

The shares may be resold directly or indirectly, only in compliance with articles L.411-1, L.411-2, L.412-1 and L.621-8 through L.621-8-3 of the French Code monetaire et financier.

Notice to Prospective Investors in Hong Kong

The shares may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong) and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

 

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Notice to Prospective Investors in Japan

The shares offered in this prospectus have not been and will not be registered under the Financial Instruments and Exchange Law of Japan. The shares have not been offered or sold and will not be offered or sold, directly or indirectly, in Japan or to or for the account of any resident of Japan (including any corporation or other entity organized under the laws of Japan), except (i) pursuant to an exemption from the registration requirements of the Financial Instruments and Exchange Law and (ii) in compliance with any other applicable requirements of Japanese law.

Notice to Prospective Investors in Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person pursuant to Section 275(1), or any person pursuant to Section 275(1A), and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to compliance with conditions set forth in the SFA.

Where the shares are subscribed or purchased under Section 275 of the SFA by a relevant person which is:

 

•

a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or

 

•

a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary of the trust is an individual who is an accredited investor,

shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferred within six months after that corporation or that trust has acquired the shares pursuant to an offer made under Section 275 of the SFA except:

 

•

to an institutional investor (for corporations, under Section 274 of the SFA) or to a relevant person defined in Section 275(2) of the SFA, or to any person pursuant to an offer that is made on terms that such shares, debentures and units of shares and debentures of that corporation or such rights and interest in that trust are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets, and further for corporations, in accordance with the conditions specified in Section 275 of the SFA;

 

•

where no consideration is or will be given for the transfer; or

 

•

where the transfer is by operation of law.

Notice to Prospective Investors in Spain

Neither the shares nor this prospectus have been approved or registered in the administrative registries of the Spanish National Securities Exchange Commission, or Comision Nacional del Mercado de Valores, or CNMV. Accordingly, the shares may not be offered in Spain except in circumstances which do not constitute a public offer of securities in Spain within the meaning of article 30bis of the Spanish Securities Market Law of July 28, 1988 (Ley 24/1988, de 28 Julio, del Mercado de Valores), as amended and restated, and supplemental rules enacted thereunder.

 

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Notice to Prospective Investors in Australia

No placement document, prospectus, product disclosure statement or other disclosure document has been lodged with the Australian Securities and Investments Commission (“ASIC”), in relation to the offering. This prospectus does not constitute a prospectus, product disclosure statement or other disclosure document under the Corporations Act 2001 (the “Corporations Act”), and does not purport to include the information required for a prospectus, product disclosure statement or other disclosure document under the Corporations Act.

Any offer in Australia of the shares may only be made to persons (the “Exempt Investors”) who are “sophisticated investors” (within the meaning of section 708(8) of the Corporations Act), “professional investors” (within the meaning of section 708(11) of the Corporations Act) or otherwise pursuant to one or more exemptions contained in section 708 of the Corporations Act so that it is lawful to offer the shares without disclosure to investors under Chapter 6D of the Corporations Act.

The shares applied for by Exempt Investors in Australia must not be offered for sale in Australia in the period of 12 months after the date of allotment under the offering, except in circumstances where disclosure to investors under Chapter 6D of the Corporations Act would not be required pursuant to an exemption under section 708 of the Corporations Act or otherwise or where the offer is pursuant to a disclosure document which complies with Chapter 6D of the Corporations Act. Any person acquiring shares must observe such Australian on-sale restrictions.

This prospectus contains general information only and does not take account of the investment objectives, financial situation or particular needs of any particular person. It does not contain any securities recommendations or financial product advice. Before making an investment decision, investors need to consider whether the information in this prospectus is appropriate to their needs, objectives and circumstances, and, if necessary, seek expert advice on those matters.

Notice to Prospective Investors in the Dubai International Financial Centre

This prospectus relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority (“DFSA”). This prospectus is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this prospectus nor taken steps to verify the information set forth herein and has no responsibility for the prospectus. The shares to which this prospectus relates may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of the shares offered should conduct their own due diligence on the shares. If you do not understand the contents of this prospectus you should consult an authorized financial advisor.

Notice to Prospective Investors in Switzerland

The shares may not be publicly offered in Switzerland and will not be listed on the SIX Swiss Exchange (“SIX”) or on any other stock exchange or regulated trading facility in Switzerland. This document has been prepared without regard to the disclosure standards for issuance prospectuses under art. 652a or art. 1156 of the Swiss Code of Obligations or the disclosure standards for listing prospectuses under art. 27 ff. of the SIX Listing Rules or the listing rules of any other stock exchange or regulated trading facility in Switzerland. Neither this document nor any other offering or marketing material relating to the shares or the offering may be publicly distributed or otherwise made publicly available in Switzerland.

Neither this document nor any other offering or marketing material relating to the offering, the Company, the shares have been or will be filed with or approved by any Swiss regulatory authority. In particular, this document will not be filed with, and the offer of shares will not be supervised by, the Swiss Financial Market Supervisory Authority FINMA (FINMA), and the offer of shares has not been and will not be authorized under the Swiss Federal Act on Collective Investment Schemes (“CISA”). The investor protection afforded to acquirers of interests in collective investment schemes under the CISA does not extend to acquirers of shares.

 

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EXPENSES OF THE OFFERING

We estimate that expenses in connection with the offering, other than underwriting discounts and commissions, will be as follows:

 

Expense		Amount
Securities and Exchange Commission registration fee		$	77,280
NASDAQ listing fee			225,000
Financial Industry Regulatory Authority filing fee			90,500
Printing and engraving expenses			412,500
Legal fees and expenses (including tax advice)			5,356,000
Accounting fees and expenses			889,600
Transfer agent and registrar fees			350,000
Miscellaneous fees and expenses			250,000
Total		$	7,650,880

All of the above expenses will be paid by Abengoa other than certain expenses payable by the underwriters. In addition, the underwriters have agreed to reimburse Abengoa $             of certain expenses in connection with the offering.

 

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LEGAL MATTERS

The validity of the shares and certain other matters under English law will be passed upon for us by Linklaters LLP, our English counsel. We are also being advised as to certain legal matters by Linklaters LLP, New York, New York and Linklaters, S.L.P., Madrid, Spain. The underwriters are being advised as to certain legal matters by Davis Polk & Wardwell LLP, Madrid, Spain.

 

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EXPERTS

The Annual Combined Financial Statements included in this prospectus as of and for each of the years ended December 31, 2013 and 2012 have been audited by Deloitte, S.L., an independent registered public accounting firm, as stated in their report appearing herein which report expresses an unqualified opinion on the Annual Combined Financial Statements and includes an explanatory paragraph referring to the adoption of IFRS 10. Such Annual Combined Financial Statements are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The financial statement of Abengoa Yield plc (formerly Abengoa Yield Limited) included in this prospectus has been audited by Deloitte LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statement is included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

 

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WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form F-1, including relevant exhibits and schedules, under the Securities Act for the shares being by offered by this prospectus. This prospectus is a part of the registration statement and does not contain all of the information set forth in the registration statement. The rules and regulations of the SEC allow us to omit from this prospectus certain information included in the registration statement. This prospectus summarizes material provisions of contracts and other documents. Since this prospectus does not contain all of the information contained in the registration statement and exhibits, you should read the registration statement on Form F-1 and its exhibits and other documents.

Upon completion of this offering, we will become subject to periodic reporting and other informational requirements of the Exchange Act as applicable to foreign private issuers. Accordingly, we will be required to file reports, including annual reports on Form 20-F, periodic reports and other information with the SEC.

We are allowed four months to file our annual report with the SEC, and we are not required to disclose certain detailed information regarding executive compensation that is required from U.S. domestic issuers. Also, as a foreign private issuer, we are exempt from the rules of the Exchange Act prescribing the furnishing of proxy statements to shareholders, and our executive officers, directors and principal shareholders are exempt from the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act.

As a foreign private issuer, we are also exempt from the requirements of Regulation FD (Fair Disclosure) which, generally, are meant to ensure that select groups of investors are not privy to specific information about an issuer before other investors. We are, however, still subject to the anti-fraud and anti-manipulation rules of the SEC, such as Rule 10b-5. Since many of the disclosure obligations required of us as a foreign private issuer are different than those required of U.S. domestic reporting companies, our shareholders, potential shareholders and the investing public in general should not expect to receive information about us in the same amount, or at the same time, as information is received from, or provided by, other U.S. domestic reporting companies. We are only liable for violations of the rules and regulations of the SEC that apply to us as a foreign private issuer.

We plan to file our annual report on Form 20-F with the SEC no later than 90 days after the end of each fiscal year. We plan to furnish a quarterly report with the SEC on Form 6-K no later than 60 days following the end of each of the first three fiscal quarters of each year, or as soon thereafter as is reasonably practicable. The quarterly report will include substantially the same information as required by a Form 10-Q, including Management’s Discussion and Analysis of Financial Condition and Results of Operations; provided that the financial statements included in such quarterly report will be prepared and presented in conformity with IFRS as issued by the IASB, rather than with U.S. GAAP.

For further information about us and our shares, you may inspect a copy of the registration statement, of the exhibits and schedules to the registration statement or of any reports, statements or other information we file with the SEC without charge at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549, United States. You may obtain copies of all or any part of the registration statement upon the payment of the duplicating fees by writing to the SEC. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website at www.sec.gov that contains reports and information statements and other information regarding registrants like us that file electronically with the SEC. You also can inspect our registration statement, as well as any other information we file with or furnish to the SEC on this website. This reference to the SEC’s website is an inactive textual reference only and is not a hyperlink.

We expect to make our annual reports and other information filed with or furnished to the SEC available, free of charge, through our website at www.abengoayield.com and www.abengoayield.co.uk as soon as reasonably practicable after those reports and other information are filed with or furnished to the SEC. The information contained on, or that can be accessed through, our website is not part of, and is not incorporated into, this prospectus.

 

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COMBINED FINANCIAL STATEMENTS

 

		Page
Unaudited Combined Condensed Interim Financial Statements
Combined condensed statements of financial position as of March 31, 2014 and December 31, 2013			F-2
Combined condensed income statements for the three month periods ended March 31, 2014 and March 31, 2013			F-4
Combined condensed statements of comprehensive income for the three month periods ended March  31, 2014 and March 31, 2013			F-5
Combined condensed statements of changes in equity for the three month periods ended March  31, 2014 and March 31, 2013			F-6
Combined condensed cash flow statements for the three month periods ended March 31, 2014 and March  31, 2013			F-7
Notes to the combined condensed interim financial statements for the three month period ended March  31, 2014			F-9
Audited Combined Financial Statements as of and for the years ended December 31, 2013 and 2012
Report of Independent Registered Public Accounting Firm			F-24
Combined statements of financial position as of December 31, 2013 and 2012, and as of January  1, 2012			F-25
Combined income statements for the years ended December 31, 2013 and 2012			F-27
Combined statements of comprehensive income for the years ended December 31, 2013 and 2012			F-28
Combined statements of changes in equity for the years ended December 31, 2013 and 2012			F-29
Combined cash flow statements for the years ended December 31, 2013 and 2012			F-30
Notes to the combined financial statements			F-32
Appendix I Entities included in the Company as subsidiaries as of December 31, 2013 and 2012			F-65
Appendix II Investments recorded under the equity method as of December 31, 2013 and 2012			F-67
Appendix III-1 and Appendix III-2 Projects subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 2013 and 2012			F-68
Appendix IV (Schedule I) Report of Independent Registered Public Accounting Firm and Financial Statements of Abengoa Yield plc			F-74

 

F-1

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Table of Contents

Combined condensed statements of financial position as of March 31, 2014 and December 31, 2013

Amounts in thousands of U.S. dollars

 

		Note (1)		As of March 31, 2014				As of December 31, 2013
Assets
Non-current assets
Contracted concessional assets		6		$	4,400,722			$	4,418,120
Investments carried under the equity method		7			402,640				387,324
Financial investments		8 & 9			73,616				28,852
Deferred tax assets					44,721				52,784
Total non-current assets				$	4,921,699			$	4,887,080
Current assets
Inventories					5,357				5,244
Clients and other receivables		12			94,198				97,597
Financial investments		8			164,336				266,363
Cash and cash equivalents					809,676				357,664
Total current assets				$	1,073,567			$	726,868
Total assets				$	5,995,266			$	5,613,948

 

(1)	Notes 1 to 18 are an integral part of the combined condensed interim financial statements

 

F-2

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Table of Contents

Combined condensed statements of financial position as of March 31, 2014 and December 31, 2013

Amounts in thousands of U.S. dollars

 

		Note (1)		As of March 31, 2014				As of December 31, 2013
Equity and liabilities
Equity attributable to the Company
Hedging reserves				$	(55,458	)		$	(36,600	)
Accumulated currency translation differences					8,881				9,009
Other equity					1,466,381				1,245,510
Non-controlling interest					66,181				69,279
Total equity				$	1,485,985			$	1,287,198
Non-current liabilities
Long-term non-recourse project financing		13			2,312,519				2,842,338
Grants and other liabilities		14			1,055,142				650,903
Related parties		11			369,612				492,534
Derivative liabilities		9			71,384				44,221
Deferred tax liabilities					3,328				21,839
Total non-current liabilities				$	3,811,985			$	4,051,835
Current liabilities
Short-term non-recourse project financing		13			517,051				52,312
Trade payables and other current liabilities		15			178,446				204,013
Income and other tax payables					1,799				18,590
Total current liabilities				$	697,296			$	274,915
Total equity and liabilities				$	5,995,266			$	5,613,948

 

(1)	Notes 1 to 18 are an integral part of the combined condensed interim financial statements

 

F-3

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Table of Contents

Combined condensed income statements for the three month periods ended March 31, 2014 and

March 31, 2013

Amounts in thousands of U.S. dollars

 

		Note (1)		For the three months ended March 31,
				2014				2013
Revenue				$	63,822			$	32,304
Other operating income					20,308				97,945
Raw materials and consumables used					(4,499	)			(476	)
Employee benefit expenses					(1,707	)			(573	)
Depreciation, amortization, and impairment charges					(27,238	)			(8,545	)
Other operating expenses					(26,785	)			(103,876	)
Operating profit/(loss)				$	23,901			$	16,779
Financial income		17			156				366
Financial expense		17			(54,329	)			(20,633	)
Net exchange differences					615				(426	)
Other financial income/(expense), net		17			(407	)			(1,746	)
Financial expense, net				$	(53,965	)		$	(22,439	)
Share of profit/(loss) of associates carried under the equity method				$	(311	)		$	(59	)
Profit/(loss) before income tax				$	(30,375	)		$	(5,719	)
Income tax				$	1,814			$	(839	)
Profit/(loss) for the period				$	(28,561	)		$	(6,558	)
Loss/(profit) attributable to non-controlling interests				$	1,655			$	1,645
Profit/(loss) for the period attributable to the Company				$	(26,906	)		$	(4,913	)

 

(1)	Notes 1 to 18 are an integral part of the combined condensed interim financial statements

The combined condensed income statements include the following income (expense) items arising from transactions with related parties:

 

		For the three months ended March 31,
		2014				2013
Sales		$	594			$	1,027
Construction costs			(9,114	)			(97,824	)
Services rendered			502				77
Services received			(2,918	)			(2,411	)
Purchases			(2,505	)			(47	)
Financial income			125				182
Financial expenses			(6,690	)			(1,040	)

 

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Table of Contents

Combined condensed statements of comprehensive income for the three month periods ended

March 31, 2014 and March 31, 2013

Amounts in thousands of U.S. dollars

 

		For the three months ended March 31,
		2014				2013
Profit/(loss) for the period		$	(28,561	)		$	(6,558	)
Items that may be subject to transfer to income statement
Change in fair value of cash flow hedges			(35,417	)			15,980
Currency translation differences			(195	)			(5,159	)
Tax effect			10,464				(4,794	)
Net income/(expenses) recognized directly in equity		$	(25,148	)		$	6,027
Cash flow hedges			7,032				1,905
Tax effect			(2,110	)			(572	)
Transfers to income statement		$	4,922			$	1,333
Other comprehensive income/(loss)		$	(20,225	)		$	7,360
Total comprehensive income/(loss) for the period		$	(48,786	)		$	802
Total comprehensive income/(loss) attributable to non-controlling interest		$	2,894			$	2,798
Total comprehensive income/(loss) attributable to the Company		$	(45,892	)		$	3,600

Notes 1 to 18 are an integral part of the combined condensed financial statements.

 

F-5

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Table of Contents

Combined condensed statements of changes in equity for the three month periods ended March 31, 2014 and March 31, 2013

Amounts in thousands of U.S. dollars

 

		Hedging reserves				Accumulated currency translation differences				Other equity				Total equity attributable to the Company				Non-controlling interest				Total equity
Balance as of January 1, 2013		$	(103,547	)		$	2.731			$	1,182,008			$	1,081,192			$	58,617			$	1,139,809
Profit for the period after taxes			—				—				(4,913	)			(4,913	)			(1,645	)			(6,558	)
Change in fair value of cash flow hedges			17,255				—				—				17,255				630				17,885
Currency translation differences			—				(3,565	)			—				(3,565	)			(1,594	)			(5,159	)
Tax effect			(5,177	)			—				—				(5,177	)			(189	)			(5,366	)
Other comprehensive income		$	12,078			$	(3,565	)		$	—			$	8,513			$	(1,153	)		$	7,360
Total comprehensive income		$	12,078			$	(3,565	)		$	(4,913	)		$	3,600			$	(2,798	)		$	802
Capital contributions		$	—			$	—			$	117,352			$	117,352			$	866			$	118,218
Scope variations, acquisitions and other movements		$	—			$	—			$	117,352			$	117,352			$	866			$	118,218
Balance as of March 31, 2013		$	(91,469	)		$	(834	)		$	1,294,447			$	1,202,144			$	56,685			$	1,258,829
Balance as of January 1, 2014			(36,600	)			9,009				1,245,510				1,217,919				69,279				1,287,198
Profit/(loss) for the period after taxes			—				—				(26,906	)			(26,906	)			(1,655	)			(28,561	)
Change in fair value of cash flow hedges			(26,710	)			—				—				(26,710	)			(1,675	)			(28,385	)
Currency translation differences			—				(128	)			—				(128	)			(67	)			(195	)
Tax effect			7,852				—				—				7,852				503				8,355
Other comprehensive income		$	(18,858	)		$	(128	)		$	—			$	(18,986	)		$	(1,239	)		$	(20,225	)
Total comprehensive income		$	(18,858	)		$	(128	)		$	(26,906	)		$	(45,892	)		$	(2,894	)		$	(48,786	)
Capital contributions		$	—			$	—			$	247,777			$	247,777			$	(204	)		$	247,573
Scope variations, acquisitions and other movements		$	—			$	—			$	247,777			$	247,777			$	(204	)		$	247,573
Balance as of March 31, 2014		$	(55,458	)		$	8,881			$	1,466,381			$	1,419,804			$	66,181			$	1,485,985

 

(1)	Notes 1 to 18 are an integral part of the combined condensed interim financial statements

 

F-6

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Table of Contents

Combined condensed cash flow statements for the three month periods ended March 31, 2014 and March 31, 2013

Amounts in thousands of U.S. dollars

 

		For the three months ended March 31,
		2014				2013
I. Profit/(loss) for the period		$	(28,561	)		$	(6,558	)
Non-monetary adjustments			76,217				7,970
II. Profit for the period adjusted by non monetary items		$	47,656			$	1,412
III. Variations in working capital		$	(36,332	)		$	(7,523	)
Income tax paid			180				(245	)
Interest received			156				2,052
Interest paid			(12,130	)			(2,208	)
A. Net cash provided by operating activities		$	(470	)		$	(6,512	)
Investment in contracted concessional assets			(26,306	)			(132,966	)
Other non-current assets/liabilities			(13,641	)			(4,005	)
B. Net cash used in investing activities		$	(39,947	)		$	(136,971	)
C. Net cash provided by financing activities		$	492,509			$	185,259
Net increase/(decrease) in cash and cash equivalents		$	452,092			$	41,776
Cash, cash equivalents and bank overdrafts at beginning of the period			357,664				97,499
Translation differences cash or cash equivalent			(80	)			(1,193	)
Cash and cash equivalents at end of the period		$	809,676			$	138,082

Notes 1 to 18 are an integral part of the combined condensed interim financial statements.

 

F-7

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Table of Contents

Contents

 

Note 1.- Nature of the business			F-9
Note 2.- Basis of preparation			F-11
Note 3.- Financial risk management			F-13
Note 4.- Financial information by segment			F-13
Note 5.- Changes in the scope of the combined condensed interim financial statements			F-18
Note 6.- Contracted concessional assets			F-18
Note 7.- Investments carried under the equity method			F-19
Note 8.- Financial investments			F-19
Note 9.- Derivative financial instruments			F-19
Note 10.- Fair value of financial instruments			F-20
Note 11.- Related parties			F-20
Note 12.- Clients and other receivable			F-21
Note 13.- Non-recourse financing (project financing)			F-21
Note 14.- Grants and other liabilities			F-21
Note 15.- Trade payables and other current liabilities			F-22
Note 16.- Income Tax			F-22
Note 17.- Financial income and expenses			F-22
Note 18.- Subsequent events			F-23

 

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Table of Contents

Note 1.- Nature of the business

Abengoa Yield plc was incorporated in England and Wales as a private limited company on December 17, 2013 by Abengoa, S.A. (‘Abengoa’ or ‘the Parent’) under the name Abengoa Yield Limited. On March 19, 2014, Abengoa Yield plc was re-registered as a public limited company, under the name Abengoa Yield plc. Abengoa Yield plc is a dividend growth-oriented company formed to serve as the primary vehicle through which Abengoa will own, manage, and acquire renewable energy, conventional power, electric transmission lines, and other contracted revenue-generating assets, initially focused on North America (United States and Mexico) and South America (Peru, Chile and Uruguay), as well as Europe (Spain in the first instance).

Abengoa listed on the Madrid Stock Exchange and the NASDAQ Global Select Market, is a leading engineering and clean technology company with operations in more than 50 countries worldwide that provides innovative solutions for a diverse range of customers in the energy and environmental sectors. Over the course of its 70-year history, Abengoa has developed a unique and integrated business model that applies accumulated engineering expertise to promoting sustainable development solutions, including delivering new methods for generating power from the sun, developing biofuels, producing potable water from seawater, and efficiently transporting electricity. A cornerstone of Abengoa’s business model has been the investment in proprietary technologies, particularly in areas with relatively high barriers to entry. Abengoa’s engineering and construction activities provide sophisticated turnkey engineering, procurement, and construction services from design to implementation for infrastructure projects within the energy and environmental sectors and engages in other related activities with a high technology component. Its concession-type infrastructures activities include the management, operation and maintenance of infrastructure assets, usually pursuant to long-term concession agreements. Its industrial production activities produce mostly bioethanol.

The accompanying combined condensed interim financial statements of Abengoa Yield plc (‘the Company’, ‘Abengoa Yield’ or ‘the Predecessor’) have been prepared in connection with the proposed initial public offering of common shares of Abengoa Yield, or the Offering, and represent the eleven assets described herein that Abengoa intends to transfer to Abengoa Yield prior to the Offering. The Company has elected to account for the Asset Transfer to Abengoa Yield plc using the predecessor values, given that these will be transactions between entities under common control. Any difference between the consideration given and the aggregate book value of the assets and liabilities of the acquired entities as of the date of the transaction will be reflected as an adjustment to equity.

The portfolio consists of five renewable energy assets, a cogeneration facility, and several electric transmission lines, all of which are fully operational as of today, with the exception of the Mojave solar facility, which is in the test operation stage and expected to be fully operational by October 2014, and Palmatir wind farm, which is expected to achieve commercial operation day (‘COD’) by May 2014. All of our assets have contracted revenues (regulated revenues in the case of the Spanish assets) with low-risk offtakers, and have an average remaining contract life of approximately 26 years as of December 31, 2013. Our contracts are generally fixed-priced and pursuant to regulated rates revised based on inflation or similar types of public indexes. Over 90% of cash generated each year and available for distribution from these assets in the next four years is in U.S. dollars, or indexed to the U.S. dollar. Over 90% of our project-level debt is hedged against changes in interest rates through an underlying fixed rate on the debt instrument or through interest rate swaps, caps, or similar hedging instruments.

Our assets and operations are organized into the following three business sectors:

 

•

Renewable energy: renewable energy assets include of (i) two concentrated solar power (CSP) plants in the United States, Solana and Mojave, each with a gross capacity of 280 MW; (ii) one on-shore wind farm in Uruguay, Palmatir, with a gross capacity of 50 MW; and (iii) two CSP plants in Spain, Solaben 2 and Solaben 3, with a gross capacity of 50 MW each.

 

•

Conventional power: the conventional power asset consists of Abengoa Cogeneracion Tabasco, or ACT, a 300 MW cogeneration plant in Mexico.

 

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•

Electric transmission lines: the electric transmission line assets include (i) two lines in Peru, ATN and ATS, spanning a total of 931 miles; and (ii) three lines in Chile, Quadra 1, Quadra 2, and Palmucho, spanning a total of 87 miles.

Abengoa Yield is expected to be comprised of the following projects:

 

Our Assets

Type

Ownership

Location

Currency

Capacity (Gross)

Counterparty Credit Ratings(3)

COD/ Expected COD

Contract Years Left

Solana

Renewable (CSP)

100% Class B1

Arizona (USA)

USD

280 MW

A-/A3/BBB+

4Q 2013

29

Mojave

Renewable (CSP)

100%

California (USA)

USD

280 MW

BBB/A3/BBB+

4Q 2014

25

ACT

Conventional Power

100%

Mexico

USD

300 MW

BBB+/Baa1/BBB+

2Q 2013

19

ATN

Transmission line

100%

Peru

USD

362 miles

BBB+/Baa2/BBB+

1Q 2011

27

ATS

Transmission line

100%

Peru

USD

569 miles

BBB+/Baa2/BBB+

1Q 2014

30

Quadra 1 & Quadra 2

Transmission line

100%

Chile

USD

81 miles

N/A

2Q 2014 & 1Q 2014

21

Palmucho

Transmission line

100%

Chile

CLP

6 miles

BBB+/Baa2/BBB+

4Q 2007

23

Palmatir

Renewable (Wind)

100%

Uruguay

USD

50 MW

BBB-/Baa3/BBB-

2Q 2014

20

Solaben 2 & Solaben 3

Renewable (CSP)

70%2

Spain

Euro

2x50 MW

BBB-/Baa2/BBB+

2Q 2012 & 4Q 2012

24

 

(1)

On September 30, 2013, Liberty Interactive Corporation invested $300 million in Class A membership interests in exchange for a share of the dividends and taxable loss generated by Solana. As a result of the agreement, Liberty Interactive Corporation will receive 54.06% of both dividends and taxable loss generated during a period of approximately five years; such percentage will decrease to 24.05% thereafter.

(2)	Itochu Corporation holds 30% of the economic rights to each of Solaben 2 and Solaben 3.

(3)	Reflects the counterparty’s issuer credit ratings issued by Standard & Poor’s Ratings Services, or S&P, Moody’s Investors Service Inc., or Moody’s, and Fitch Ratings Ltd, or Fitch.

Entities included in these combined condensed interim financial statements have signed with the grantor of the concession contracts of construction, operation and maintenance and they subcontract the construction of the contracted assets to Abengoa. Given that these projects (except for Palmucho) are included within the scope of IFRIC 12, and given that they are included in the combined financial statements during their construction phase, the Company has recorded income and cost attributable to the construction in the combined income statement. Construction revenue is recorded within “Other operating income” according to the percentage of completion method as established by IAS 11. Construction cost, which is fully contracted with related parties, is recorded within “Other operating expense”.

The combined condensed interim financial statements were prepared using Abengoa’s historical basis in the assets and liabilities of the Predecessor, and include all revenues, expenses, assets, and liabilities attributed to the Predecessor. In addition, other operating expenses include an allocation of certain general and administrative services provided by Abengoa. The Company believes that by including the allocated costs, the combined income statement includes a reasonable estimate of actual costs incurred to operate the business. However, such expenses may not be indicative of the actual level of expense that would have been incurred by the Predecessor if

 

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it had operated as an independent, publicly-traded company during the periods prior to the Offering or of the costs expected to be incurred in the future. In the opinion of management, the inter-company eliminations and adjustments necessary for a fair presentation of the condensed interim combined financial statements, in accordance with the International Financial Reporting Standards as issued by the International Accounting Standards Board (IFRS-IASB) have been made.

These combined condensed interim financial statements were approved by the Chief Executive Officer on April 30, 2014.

Note 2.- Basis of preparation

The Company is not an existing legal entity for the periods presented. Rather, it is a combination of entities and assets currently owned by Abengoa and that have been under common control of Abengoa during the periods presented. The management has prepared the condensed interim combined financial statements for the only purpose of including them as historical financial information of the predecessor of Abengoa Yield in a public prospectus.

Abengoa is a company listed on the Madrid Stock Exchange and on the NASDAQ Global Select Market and prepares, on an annual basis, consolidated financial statements in accordance with IFRS-IASB. Since the combined condensed interim financial statements of Abengoa Yield are carved out from the consolidated financial statements of Abengoa, the combined condensed interim financial statements have also been prepared in accordance with the IFRS-IASB.

As a consequence, the combined condensed interim financial statements represent the operations of the contributed entities using the predecessor values, and the accounting policies are the same as those used in the historical consolidated financial statements of Abengoa.

The Company’s combined financial statements corresponding to the 2013 financial year were approved by the Chief Executive Officer on February 27, 2014.

These combined condensed interim financial statements are presented in accordance with IAS 34, ‘Interim Financial Reporting’. In accordance with IAS 34, interim financial information is prepared solely in order to update the most recent annual combined financial statements prepared by the Company, placing emphasis on new activities, occurrences and circumstances that have taken place during the three month period ended March 31, 2014 and not duplicating the information previously published in the annual combined financial statements for the year ended December 31, 2013. Therefore, the combined condensed interim financial statements do not include all the information that would be required in complete combined financial statements prepared in accordance with the IFRS-IASB. In view of the above, for an adequate understanding of the information, these combined condensed interim financial statements must be read together with Abengoa Yield’s combined financial statements for the year ended December 31, 2013.

In determining the information to be disclosed in the notes to the combined condensed interim financial statements, Abengoa Yield, in accordance with IAS 34, has taken into account its materiality in relation to the combined condensed interim financial statements.

The combined condensed interim financial statements are presented in U.S. dollars, which is the Company’s functional and presentation currency. Amounts included in these combined condensed interim financial statements are all expressed in thousands of U.S. dollars, unless otherwise indicated.

 

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Application of new accounting standards

 

a)	Standards, interpretations and amendments effective from January 1, 2014 under IFRS-IASB, applied by the Company:

 

•

IAS 32 (amendment) ’Offsetting of financial assets and financial liabilities’. The IAS 32 amendment is mandatory for periods beginning on or after January 1, 2014.

 

•

IAS 36 (amendment) ‘Recoverable Amount Disclosures for Non-Financial Assets’. The IAS 36 amendment is mandatory for periods beginning on or after January 1, 2014.

 

•

IAS 39 (amendment) ‘Novation of Derivatives and Continuation of Hedge Accounting’. The IAS 39 amendment is mandatory for periods beginning on or after January 1, 2014.

 

•

IFRIC 21 (Interpretation) “Levies”. The IFRIC 21 is mandatory for periods beginning on or after January 1, 2014.

These amendments and interpretations effective from January 1, 2014 did not have any material impact on these combined condensed interim financial statements.

 

b)	Standards, interpretations and amendments published by the IASB that will be effective for periods after January 1, 2014:

 

•

Annual Improvements to IFRSs 2010-2012 and 2011-2013 cycles. These improvements are mandatory for periods beginning on or after July 1, 2014.

 

•

IFRS 9 ’Financial Instruments’. This Standard will be effective from January 1, 2018.

The Company does not expect any material impact of the Annual Improvements that will be effective from July 1, 2014 and is assessing the impact of IFRS 9 (classification and measurement) which will be effective from January 1, 2018.

Use of estimates

Some of the accounting policies applied require the application of significant judgment by management to select the appropriate assumptions to determine these estimates. These assumptions and estimates are based on our historical experience, advice from experienced consultants, forecasts and other circumstances and expectations as of the close of the financial period. The assessment is considered in relation to the global economic situation of the industries and regions where the Company operates, taking into account future development of our businesses. By their nature, these judgments are subject to an inherent degree of uncertainty; therefore, actual results could materially differ from the estimates and assumptions used. In such cases, the carrying values of assets and liabilities are adjusted.

The most critical accounting policies, which reflect significant management estimates and judgment to determine amounts in our combined condensed interim financial statements, are as follows:

 

•

Contracted concesional agreements.

 

•

Impairment of intangible assets.

 

•

Assessment of control.

 

•

Derivative financial instruments and fair value estimates.

 

•

Income taxes and recoverable amount of deferred tax assets.

As of the date of preparation of these combined condensed interim financial statements, no relevant changes in the estimates made are anticipated and, therefore, no significant changes in the value of the assets and liabilities recognized at March 31, 2014, are expected.

 

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Although these estimates and assumptions are being made using all available facts and circumstances, it is possible that future events may require management to amend such estimates and assumptions in future periods. Changes in accounting estimates are recognized prospectively, in accordance with IAS 8, in the combined income statement of the year in which the change occurs.

Note 3.- Financial risk management

Abengoa Yield’s activities are exposed to various financial risks: market risk (including currency risk and interest rate risk), credit risk and liquidity risk. Risk is managed by the Company’s Risk Management and Finance Department, which are responsible for identifying and evaluating financial risks quantifying them by project, region and company, in accordance with mandatory internal management rules. Written internal policies exist for global risk management, as well as for specific areas of risk. In addition, there are official written management regulations regarding key controls and control procedures for each company and the implementation of these controls is monitored through internal audit procedures.

These combined condensed interim financial statements do not include all financial risk management information and disclosures required for annual financial statements, and should be read together with the information included in Note 3 to Abengoa Yield’s combined financial statements as of December 31, 2013.

Note 4.- Financial information by segment

Abengoa Yield’s segment structure reflects how management currently makes financial decisions and allocates resources. Its operating segments are based on the following geographies where the contracted concessional assets are located:

 

•

North America

 

•

South America

 

•

Europe

Based on the type of business, the Company has identified the following business sectors:

Renewable energy: Our renewable energy assets include two CSP plants in the United States, Solana and Mojave, each with a gross capacity of 280 MW and located in Arizona and California, respectively. Solana reached COD on October 9, 2013, and Mojave has substantially completed construction and is in operation test stage, with expected COD by October 2014. Additionally, we own a wind farm in Uruguay, Palmatir, with a gross capacity of 50 MW. The construction of Palmatir is complete and COD is expected in May 2014. Finally, Solaben 2 and Solaben 3 are two CSP plants located in Spain. Both projects have been in operation since mid-2012 and receive regulated revenues under the framework for renewable projects in Spain.

Conventional power: Our conventional power asset consist of ACT, a 300 MW cogeneration plant in Mexico, which is party to a 20-year take-or-pay contract with Pemex for the sale of electric power and steam.

Electric transmission lines: Our electric transmission assets include (i) two lines in Peru, ATN, and ATS, spanning a total of 931 miles; (ii) three lines in Chile, Quadra 1, Quadra 2 and Palmucho, spanning a total of 87 miles. ATN reached COD in 2011 and ATS reached COD on January 17, 2014. Quadra 1 reached COD in April 2014 and Quadra 2 reached COD in March 2014. Palmucho reached COD in October 2007.

Abengoa Yield´s Chief Operating Decision Maker (CODM) assesses the performance and assignment of resources according to the identified operating segments. The CODM considers the revenues as a measure of the business activity and the Adjusted EBITDA (earnings before interest, tax, share of (loss)/profit of associates,

 

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depreciation, amortization and impairment charge) as measure of the performance of each segment. In order to assess performance of the business, the CODM receives reports of each reportable segment using revenues and Adjusted EBITDA. Net interest expense evolution is assessed on a consolidated basis. Financial expense and amortization are not taken into consideration by CODM for the allocation of resources.

 

a)

The following tables show Revenues and Adjusted EBITDA by operating segments and business sectors for the three month periods ended March 31, 2014 and 2013:

 

		Revenue								Adjusted EBITDA
		For the three months ended March 31,								For the three months ended March 31,
		2014				2013				2014				2013
Geography
North America		$	42,855			$	19,961			$	37,194			$	18,612
South America			14,270				5,664				10,997				3,915
Europe			6,697				6,680				2,948				2,797
Total		$	63,822			$	32,304			$	51,139			$	25,324
		Revenue								Adjusted EBITDA
		For the three months ended March 31,								For the three months ended March 31,
		2014				2013				2014				2013
Business sectors
Renewable energy		$	20,784			$	6,680			$	16,578			$	2,722
Conventional power			28,768				19,961				23,473				18,612
Electric transmission lines			14,270				5,664				11,088				3,990
Total		$	63,822			$	32,304			$	51,139			$	25,324

The reconciliation of segment Adjusted EBITDA with the profit/(loss) attributable to the Company is as follows:

 

		For the three months ended March 31,
		2014				2013
Total segment Adjusted EBITDA		$	51,139			$	25,324
Depreciation, amortization, and impairment charges			(27,238	)			(8,545	)
Financial expense, net			(53,965	)			(22,439	)
Share in profits/(losses) associates			(311	)			(59	)
Income tax			1,814				(839	)
Profit attributable to non-controlling interests			1,655				1,645
Profit/(loss) attributable to the Company		$	(26,906	)		$	(4,913	)

 

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b)

The long term asset and liabilities by operating segments (and business sector) as of March 31, 2014 and December 31, 2013 are as follows:

Assets and liabilities by geography as of March 31, 2014:

 

		North America				South America				Europe				Balance as of 03.31.14
Assets allocated
Contracted concessional assets		$	2,672,289			$	1,029,237			$	699,196			$	4,400,722
Investments carried under the equity method			396,897				—				5,743				402,640
Current financial investments			147,588				16,748				—				164,336
Cash and cash equivalents			677,607				68,911				63,158				809,676
Subtotal allocated		$	3,894,381			$	1,114,896			$	768,097			$	5,777,374
Unallocated assets
Other non-current assets															118,337
Other current assets															99,555
Subtotal unallocated														$	217,892
Total assets														$	5,995,266
		North America				South America				Europe				Balance as of 03.31.14
Liabilities allocated
Long-term and short-term non-recourse project financing		$	1,755,851			$	623,825			$	449,894			$	2,829,570
Subtotal allocated		$	1,755,851			$	623,825			$	449,894			$	2,829,570
Unallocated liabilities
Other non-current liabilities															1,499,466
Other current liabilities															180,245
Subtotal unallocated														$	1,679,711
Total liabilities														$	4,509,282
Equity unallocated														$	1,485,985
Total liabilities and equity unallocated														$	3,165,696
Total liabilities and equity														$	5,995,266

Assets and liabilities by geography as of December 31, 2013:

 

		North America				South America				Europe				Balance as of 12.31.13
Assets allocated
Contracted concessional assets		$	2,678,436			$	1,034,768			$	704,916			$	4,418,120
Investments carried under the equity method			381,248				—				6,076				387,324
Current financial investments			230,046				36,317				—				266,363
Cash and cash equivalents			206,298				86,681				64,685				357,664
Subtotal allocated		$	3,496,028			$	1,157,766			$	775,677			$	5,429,471
Unallocated assets
Other non-current assets															81,636
Other current assets															102,841
Subtotal unallocated														$	184,477
Total assets														$	5,613,948

 

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		North America				South America				Europe				Balance as of 12.31.13
Liabilities allocated
Long-term and short-term non-recourse project financing		$	1,842,817			$	605,397			$	446,436			$	2,894,650
Subtotal allocated		$	1,842,817			$	605,397			$	446,436			$	2,894,650
Unallocated liabilities
Other non-current liabilities															1,209,497
Other current liabilities															222,603
Subtotal unallocated														$	1,432,100
Total liabilities														$	4,326,750
Equity unallocated														$	1,287,198
Total liabilities and equity unallocated														$	2,719,298
Total liabilities and equity														$	5,613,948

Assets and liabilities by business sectors as of March 31, 2014:

 

		Renewable energy				Conventional power				Electric transmission lines				Balance as of 03.31.14
Assets allocated
Contracted concessional assets		$	2,870,457			$	637,308			$	892,956			$	4,400,722
Investments carried under the equity method			402,640				—				—				402,640
Current financial investments			67,111				80,481				16,744				164,336
Cash and cash equivalents			555,900				190,636				63,140				809,676
Subtotal allocated		$	3,896,108			$	908,425			$	972,840			$	5,777,374
Unallocated assets
Other non-current assets															118,337
Other current assets															99,555
Subtotal unallocated														$	217,892
Total assets														$	5,995,266

 

		Renewable energy				Conventional power				Electric transmission lines				Balance as of 03.31.14
Liabilities allocated
Long-term and short-term non-recourse project financing		$	1,684,690			$	627,338			$	517,542			$	2,829,570
Subtotal allocated		$	1,684,690			$	627,338			$	517,542			$	2,829,570
Unallocated liabilities
Other non-current liabilities															1,499,466
Other current liabilities															180,245
Subtotal unallocated														$	1,679,711
Total liabilities														$	4,509,282
Equity unallocated														$	1,485,985
Total liabilities and equity unallocated														$	3,165,696
Total liabilities and equity														$	5,995,266

 

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Assets and liabilities by business sectors as of December 31, 2013:

 

		Renewable energy				Conventional power				Electric transmission lines				Balance as of 12.31.13
Assets allocated
Contracted concessional assets		$	2,888,622			$	635,849			$	893,649			$	4,418,120
Investments carried under the equity method			387,324				—				—				387,324
Current financial investments			122,795				107,255				36,313				266,363
Cash and cash equivalents			90,395				186,078				81,191				357,664
Subtotal allocated		$	3,489,136			$	929,182			$	1,011,153			$	5,429,471
Unallocated assets
Other non-current assets															81,636
Other current assets															102,841
Subtotal unallocated														$	184,477
Total assets														$	5,613,948

 

		Renewable energy				Conventional power				Electric transmission lines				Balance as of 12.31.13
Liabilities allocated
Long-term and short-term non-recourse project financing		$	1,667,174			$	729,318			$	498,158			$	2,894,650
Subtotal allocated		$	1,667,174			$	729,318			$	498,158			$	2,894,650
Unallocated liabilities
Other non-current liabilities															1,209,497
Other current liabilities															222,603
Subtotal unallocated														$	1,432,100
Total liabilities														$	4,326,750
Equity unallocated														$	1,287,198
Total liabilities and equity unallocated														$	2,719,298
Total liabilities and equity														$	5,613,948

 

c)

The investment in contracted concessional assets and in entities under the equity method by operating segments and business sectors for the three month periods ended March 31, 2014 and 2013 are as follows:

 

		Capex
		For the three months ended March 31,
		2014				2013
Geography
North America		$	15,572			$	61,683
South America			10,798				72,152
Europe			—				6
Total		$	26,370			$	133,841

 

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		Capex
		For the three months ended March 31,
		2014				2013
Business sectors
Renewable energy		$	16,970			$	72,531
Conventional power			—				4,231
Electric transmission lines			9,400				57,079
Total		$	26,370			$	133,841

 

d)

The amount of depreciation and amortization expense recognized for the three month periods ended March 31, 2014 and 2013 are as follows

 

		For the three months ended March 31,
		2014				2013
Depreciation and amortization by geography
North America		$	(16,530	)		$	—
South America			(5,479	)			(2,670	)
Europe			(5,229	)			(5,875	)
Total		$	(27,238	)		$	(8,545	)

 

		For the three months ended March 31,
		2014				2013
Depreciation and amortization by business sectors
Renewable energy		$	(21,759	)		$	(5,875	)
Conventional power			—				—
Electric transmission lines			(5,479	)			(2,670	)
Total		$	(27,238	)		$	(8,545	)

Note 5.- Changes in the scope of the combined condensed interim financial statements

There were no changes in the scope of the combined financial statements during the three month period ended March 31, 2014.

Note 6.- Contracted concessional assets

The detail of contracted concessional assets included in the heading ‘Contracted Concessional assets’ as of March 31, 2014 and December 31, 2013 is as follows:

 

		As of March 31, 2014				As of December 31, 2013
Contracted concessional assets cost		$	4,501,745			$	4,492,286
Amortization and impairment			(101,023	)			(74,166	)
Total		$	4,400,722			$	4,418,120

Contracted concessional assets include fixed assets financed through non-recourse loans, related to service concession arrangements recorded in accordance with IFRIC 12, except for Palmucho, which is recorded in accordance with IAS 17. Concessional assets are recorded as intangible or financial assets, according to IFRIC 12 and IAS 17.

No losses from impairment of contracted concessional assets were recorded during 2014.

 

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Note 7.- Investments carried under the equity method

The table below shows the breakdown of the investments held in associates as of March 31, 2004 and December 31, 2013:

 

		As of March 31, 2014				As of December 31, 2013
Mojave Solar, LLC		$	396,897			$	381,248
Evacuación Valdecaballeros, S.L.			5,743				6,076
Total		$	402,640			$	387,324

Note 8.- Financial investments

The detail of the main categories included in Non-current and current financial investment as of March 31, 2014 and December 31, 2013 is as follows:

 

		Balance as of 03.31.14				Balance as of 12.31.13
Other receivable accounts		$	64,598			$	15,230
Derivative assets			9,018				13,622
Total non-current financial investments		$	73,616			$	28,852
Other receivable accounts		$	164,336			$	266,363
Total current financial investments		$	164,336			$	266,363

Current Other receivable accounts include the short-term portion of contracted concessional assets.

Note 9.- Derivative financial instruments

The breakdowns of the fair value amount of the derivative financial instruments as of March 31, 2014 and December 31, 2013 are as follows:

 

		Balance as of 03.31.14								Balance as of 12.31.13
		Assets				Liabilities				Assets				Liabilities
Interest rate derivatives - cash flow hedge		$	9,018			$	71,384			$	13,622			$	44,221

All the derivatives are interest rate cash-flow hedges and are classified as non-current assets or non-current liabilities, as they hedge long-term financing agreements. All derivatives are classified as level 2 (see Note 10).

During the three month period ended March 31, 2014, the fair value of derivative assets decreased and the fair value of derivative liabilities increased mainly due to a decrease in the fair value of swaps resulting from the decrease in future interest rates.

The net amount of the cash flow hedges transferred to the combined income statement is a loss of $7,032 thousand in the three month period ended March 31, 2014 (loss of $1,905 thousand in the three month period ended March 31, 2013). The net amount of the time value component of the cash flow hedges recognized in the combined income statement for the three month periods ended March 31, 2014 and 2013 has been a loss of $912 thousand and a gain of $134 thousand respectively.

The after-tax losses accumulated in equity in connection with derivatives designated as cash flow hedges as of March 31, 2014 and December 31, 2013, amount to $55,458 thousand and $36,600 thousand respectively.

 

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Note 10.- Fair value of financial instruments

Financial instruments measured at fair value are presented in accordance with the following level classification based on the nature of the inputs used for the calculation of fair value:

 

•

Level 1: Inputs are quoted prices in active markets for identical assets or liabilities.

 

•

Level 2: Fair value is measured based on inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices).

 

•

Level 3: Fair value is measured based on unobservable inputs for the asset or liability.

As of March 31, 2014 and December 31, 2013, all the financial instruments measured at fair value correspond to derivatives and have been classified as Level 2 (see Note 9).

Note 11.- Related parties

Details of balances with related parties as of March 31, 2014 and December 31, 2013 are as follows:

 

		Balance as of 03.31.14				Balance as of 12.31.13
Trade payables (current)		$	25,834			$	25,077
Total current payables with related parties		$	25,834			$	25,077
Trade payables (non- current)			5,103				5,107
Credit payables (non-current)			364,509				487,427
Total non-current payables with related parties		$	369,612			$	492,534

The decrease in the line Credit payables (non-current) is primarily due to the capitalization (equity) for $232,100 thousands of credit payables with related parties which occurred in February 2014. On the other hand, a related party purchased on March 21, 2014, General Electric´s interest in ACT, which was recorded as non-recourse financing from an accounting perspective and is now classified as Related parties credit payables for $98,151 thousands.

The operations carried out by entities included in these combined condensed interim financial statements with Abengoa and with subsidiaries of Abengoa not included in the combined group during the three month periods ended March 31, 2014 and 2013 have been as follows:

 

		For the three months ended March 31,
		2014				2013
Sales		$	594			$	1,027
Construction costs			(9,114	)			(97,824	)
Services rendered			502				77
Services received			(2,918	)			(2,411	)
Purchases			(2,505	)			(47	)
Financial income			125				182
Financial expenses			(6,690	)			(1,040	)

Services received include operation and maintenance services received by some plants, the fee incurred by some operating under the services agreement with Abengoa, and the allocation of general and administrative services. Sales include mainly sale of energy by Spanish CSP plants.

Construction costs include construction work subcontracted to Abengoa for the construction of the assets, which is recorded in these combined condensed interim financial statements due to the fact that contracted concessional assets are included in the combined financial statements during the construction phase, according to IFRIC 12.

 

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Note 12.- Clients and other receivable

Clients and other receivable as of March 31, 2014 and December 31, 2013, consist of the following:

 

		Balance as of 03.31.14				Balance as of 12.31.13
Trade receivables		$	36,323			$	26,649
Tax receivables			39,863				61,888
Other debtors			18,012				9,060
Total		$	94,198			$	97,597

As of March 31, 2014 and December 31, 2013, the fair value of clients and other receivable accounts does not differ significantly from its carrying value.

Note 13.- Non-recourse financing (project financing)

The main purpose of the Company is the long-term ownership and management of contracted concessional assets, such as renewable energy, conventional power and electric transmission line assets, which are financed through non-recourse project finance. This note shows the non-recourse financing linked to the contracted concessional assets included in Note 6 of these combined condensed interim financial statements.

The detail of Non-recourse financing of both non-current and current liabilities as of March 31, 2014 and December 31, 2013 is as follows:

 

		Balance as of 03.31.14				Balance as of 12.31.13
Non-current		$	2,312,519			$	2,842,338
Current			517,051				52,312
Total non-recourse financing		$	2,829,570			$	2,894,650

The repayment schedule for non-recourse project financing, as of March 31, 2014 is as follows and is consistent with the projected cash flows of the related projects.

 

Rest 2014		Between January and March 2015				Between April and December 2015				2016				2017				2018				Subsequent years				Total
514,368			2,683				62,180				87,615				93,270				355,804				1,713,650				2,829,570

Current non-recourse financing includes $451,310 thousand corresponding to the loan with the Federal Financing Bank related to the Solana project, which was paid on April 2, 2014.

Note 14.- Grants and other liabilities

 

		Balance as of 03.31.14				Balance as of 12.31.13
Grants		$	817,668			$	416,264
Long-term trade payables			237,475				234,639
Grants and other non-current liabilities		$	1,055,142			$	650,903

The increase in Grants was primarily due to an ITC Cash Grant collection awarded by the U.S. Department of the Treasury for the Solana project, recorded as “Cash and cash equivalents” in these combined condensed interim financial statements as of March 31, 2014. The cash received was used on April 2, 2014 to fully repay the Solana short-term tranche of the loan with the Federal Financing Bank (see note 13).

 

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The Long-term trade payables include as of March 31, 2014, USD 231 million related to the non-current portion of the investment from Liberty Interactive Corporation (‘Liberty’) made on October 2, 2013. Its current portion is recorded in other current liabilities (see note 15).

Note 15.- Trade payables and other current liabilities

Trade payable and other current liabilities as of March 31, 2014 and December 31, 2013 are as follows:

 

		Balance as of 03.31.14				Balance as of 12.31.13
Trade suppliers		$	69,552			$	101,409
Credits for services			18,368				18,484
Down payments from clients			4,670				4,711
Remunerations payable			300				144
Suppliers of intangible assets current			196				308
Other accounts payable			85,360				78,957
Total		$	178,446			$	204,013

The Other account payable line includes the short term portion of Liberty´s investment for an amount of USD 71 million as of March 31, 2014 (see note 14).

Nominal values of Trade payables and other current liabilities are considered to approximately equal to fair values and the effect of discounting them is not significant.

Note 16.- Income Tax

The effective tax rate for the periods presented has been established based on Management’s best estimates.

Income tax amounts to $ 1,814 income in the three months ended March 31, 2014 with respect of a Loss before income tax of $30,375. The effective tax rate is lower than nominal tax rate mainly due to permanent differences in some jurisdictions and to the fact that the Company has not recorded tax credits for losses in all jurisdictions where it has recorded losses.

Note 17.- Financial income and expenses

Financial income and expenses

The following table sets forth our financial income and expenses for the three month periods ended March 31, 2014 and 2013:

 

		For the three months ended March 31,
		2014				2013
Financial income
Interest income from loans and credits		$	156			$	232
Interest rates benefits derivatives: cash flow hedges			—				134
Total		$	156			$	366

 

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		For the three months ended March 31,
		2014				2013
Financial expenses
Expenses due to interest:
- Loans from credit entities		$	(30,451	)		$	(17,688	)
- Other debts			(15,484	)			(1,040	)
Interest rates losses derivatives: cash flow hedges			(8,394	)			(1,905	)
Total		$	(54,329	)		$	(20,633	)

Financial expenses have increased for the three month period ended March 31, 2014 when compared with the same period in the previous year, mainly due to interest expense from loans and credits associated with projects that have entered into operation during the last quarters of 2013 and during the first quarter of 2014, interest expense from other debts mainly due to the notes issued by ATN in the third quarter of 2013 and losses from interest rate derivatives designated as cash flow hedges, which mainly correspond to transfers from equity to financial expense when the hedged item is impacting the combined income statement.

Other net financial income and expenses

The following table sets out ‘Other net financial income and expenses’ for the three month periods ended March 31, 2014 and 2013:

 

		For the three months ended March 31,
		2014				2013
Other financial income / (expenses)
Other financial income		$	89			$	106
Other financial expenses			(496	)			(1,852	)
Total		$	(407	)		$	(1,746	)

For the three month periods ended March 31, 2014 and 2013, Other financial expenses mainly include guarantees and letters of credit, wire transfers and other bank fees and other minor financial expenses.

Note 18.- Subsequent events

On April 8, 2014, ATS refinanced its then existing project finance debt through a project bond issuance of $432 million, at a fixed coupon and with semi-annual amortization until April 2043.

On April 2, 2014, Solana fully repaid the short-term tranche of the loan with the Federal Financing Bank, which was granted with a DOE guarantee, using proceeds from an ITC Cash Grant payment awarded by the U.S. Department of the Treasury.

 

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								Deloitte, S.L. Américo Vespucio, 13 Isla de la Cartuja 41092 Sevilla España   Tel: +34 954 48 93 00 Fax: +34 954 48 93 10 www.deloitte.es

Report of Independent Registered Public Accounting Firm

To the Board of Directors of Abengoa Yield Ltd.:

We have audited the accompanying combined statements of financial position of the Abengoa Concessions Businesses (a group of businesses within Abengoa, S.A. herein after “the Company” – see Note 1) as of December 31, 2013 and 2012, and the related combined income statements, the combined statements of comprehensive income, the combined statements of changes in equity, the combined cash flow statements and related notes to the combined financial statements for each of the years in the two-year period ended December 31, 2013. These combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Combined Group is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Combined Group’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the combined financial statements, referred to above, present fairly, in all material respects, the financial position of the Company as of December 31, 2013 and 2012, and the results of their operations and cash flows for each of the years in the two-year period ended December 31, 2013 in conformity with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board.

As discussed in Note 2.1, the combined financial statements have been prepared as a combination of the historical accounts of the companies that compose the Company. The combined financial statements also include expense allocations for certain corporate functions historically provided by Abengoa, S.A. These allocations may not be reflective of the actual expense which would have been incurred had the Company operated as a separate entity apart from Abengoa, S.A. As described in Note 2.1 to the combined financial statements, the Company has adopted IFRS 10 for all years presented in the combined financial statements.

/s/Deloitte, S.L.

Seville, Spain

February 28, 2014

Deloitte S.L. Inscrita en el Registro Mercantil de Madrid, tomo 13.650, sección 8ª, folio 188, hoja M-54414, inscripción 96ª. C.I.F.: B-79104469.

Domicilio social: Plaza Pablo Ruiz Picasso, 1, Torre Picasso, 28020, Madrid.

 

F-24

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Combined statements of financial position as of December 31, 2013 and 2012, and as of January 1, 2012

Amounts in thousands of U.S. dollars

 

		Note (1)		As of December 31,								As of January 1,
				2013				2012				2012
Assets
Non-current assets
Contracted concessional assets		6		$	4,418,120			$	2,058,941			$	1,546,795
Investments carried under the equity method		7			387,324				734,083				180,210
Other receivable accounts		8			15,230				8,001				222
Derivative assets		8 & 9			13,622				5,604				9,188
Financial investments					28,852				13,605				9,410
Deferred tax assets		16			52,784				60,242				44,115
Total non-current assets				$	4,887,080			$	2,866,871			$	1,780,530
Current assets
Inventories					5,244				—				—
Trade receivables		11			26,649				11,194				1,215
Credits and other receivables		11			70,948				94,883				123,606
Clients and other receivables		8 & 11			97,597				106,077				124,821
Other receivable accounts					266,363				127,647				101,707
Financial investments		8			266,363				127,647				101,707
Cash and cash equivalents		8 & 12			357,664				97,499				40,171
Total current assets				$	726,868			$	331,223			$	266,699
Total assets				$	5,613,948			$	3,198,094			$	2,047,229

 

(1)	Notes 1 to 20 are an integral part of the combined financial statements

 

F-25

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Combined statements of financial position as of December 31, 2013 and 2012, and as of January 1, 2012

Amounts in thousands of U.S. dollars

 

		Note (1)		As of December 31,								As of January 1,
				2013				2012				2012
Equity and liabilities
Equity attributable to the Company
Hedging reserves				$	(36,600	)		$	(103,547	)		$	(82,048	)
Accumulated currency translation differences					9,009				2,731				290
Other equity					1,245,510				1,182,008				617,752
Non-controlling interest					69,279				58,617				47,926
Total equity				$	1,287,198			$	1,139,809			$	583,920
Non-current liabilities
Borrowings					2,736,552				1,320,042				1,003,239
Notes and bonds					105,786				—				—
Long-term non-recourse project financing		8 & 13			2,842,338				1,320,042				1,003,239
Grants and other liabilities		14			650,903				129,217				—
Related parties		8 & 10			492,534				222,946				86,952
Derivative liabilities		8 & 9			44,221				134,673				122,974
Deferred tax liabilities		16			21,839				15,358				4,652
Total non-current liabilities				$	4,051,835			$	1,822,236			$	1,217,817
Current liabilities
Borrowings					49,540				48,867				78,674
Notes and bonds					2,772				—				—
Short-term non-recourse project financing		8 & 13			52,312				48,867				78,674
Trade payables and other current liabilities		8 & 15			204,013				186,048				166,246
Income and other tax payables					18,590				1,134				572
Total current liabilities				$	274,915			$	236,049			$	245,492
Total equity and liabilities				$	5,613,948			$	3,198,094			$	2,047,229

 

(1)	Notes 1 to 20 are an integral part of the combined financial statements

 

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Combined income statements for the years ended December 31, 2013 and 2012

Amounts in thousands of U.S. dollars

 

		Note (1)		For the year ended December 31,
				2013				2012
Revenue		4		$	210,907			$	107,183
Other operating income		18			379,644				560,372
Raw materials and consumables used					(8,671	)			(4,289	)
Employee benefit expenses					(2,446	)			(1,789	)
Depreciation, amortization, and impairment charges		6			(46,943	)			(20,234	)
Other operating expenses		18			(420,905	)			(573,510	)
Operating profit/(loss)				$	111,586			$	67,733
Financial income		19			1,153				718
Financial expense		19			(123,784	)			(64,104	)
Net exchange differences					(895	)			392
Other financial income/(expense), net		19			(1,693	)			(173	)
Financial expense, net				$	(125,219	)		$	(63,167	)
Share of profit/(loss) of associates carried under the equity method				$	13			$	(404	)
Profit/(loss) before income tax				$	(13,620	)		$	4,162
Income tax		16		$	11,762			$	(4,021	)
Profit/(loss) for the year				$	(1,858	)		$	141
Loss/(profit) attributable to non-controlling interests				$	(1,559	)		$	1,195
Profit/(loss) for the year attributable to the Company				$	(3,417	)		$	1,336

 

(1)	Notes 1 to 20 are an integral part of the combined financial statements

The combined income statements include the following income (expense) items arising from transactions with related parties:

 

		Year ended December 31,
		2013				2012
Sales		$	11,925			$	5,089
Construction costs			(364,715	)			(558,620	)
Services rendered			2,804				3,527
Services received			(24,403	)			(8,742	)
Purchases			(2,669	)			(177	)
Financial income			468				575
Financial expenses			(11,209	)			(4,525	)

 

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Combined statements of comprehensive income for the years ended December 31, 2013 and 2012

Amounts in thousands of U.S. dollars

 

		Note (1)				For the year ended December 31,
						2013				2012
Profit/(loss) for the year						$	(1,858	)		$	141
Items that may be subject to transfer to income statement
Change in fair value of cash flow hedges							75,907				(41,320	)
Currency translation differences							8,941				3,521
Tax effect							(22,494	)			12,396
Net income/(expenses) recognized directly in equity						$	62,354			$	(25,403	)
Cash flow hedges			9				27,513				5,916
Tax effect							(8,254	)			(1,775	)
Transfers to income statement						$	19,259			$	4,141
Other comprehensive income/(loss)						$	81,613			$	(21,262	)
Total comprehensive income/(loss) for the year						$	79,755			$	(21,121	)
Total comprehensive income/(loss) attributable to non-controlling interest							(9,947	)			3,399
Total comprehensive income/(loss) attributable to the Company						$	69,808			$	(17,722	)

 

(1)	Notes 1 to 20 are an integral part of the combined financial statements

 

F-28

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Combined statements of changes in equity for the years ended December 31, 2013 and 2012

Amounts in thousands of U.S. dollars

 

		Hedging reserves				Accumulated currency translation differences				Other equity				Total equity attributable to the Company				Non-controlling interest				Total equity
Balance as of January 1, 2012		$	(82,048	)		$	290			$	617,752			$	535,994			$	47,926			$	583,920
Profit for the year after taxes			—				—				1,336				1,336				(1,195	)			141
Change in fair value of cash flow hedges			(30,713	)			—				—				(30,713	)			(4,691	)			(35,404	)
Currency translation differences			—				2,441				—				2,441				1,080				3,521
Tax effect			9,214				—				—				9,214				1,407				10,621
Other comprehensive income		$	(21,499	)		$	2,441			$	—			$	(19,058	)		$	(2,204	)		$	(21,262	)
Total comprehensive income		$	(21,499	)		$	2,441			$	1,336			$	(17,722	)		$	(3,399	)		$	(21,121	)
Capital contributions		$	—			$	—			$	562,920			$	562,920			$	14,090			$	577,010
		$	—			$	—			$	562,920			$	562,920			$	14,090			$	577,010
Balance as of December 31, 2012		$	(103,547	)		$	2,731			$	1,182,008			$	1,081,192			$	58,617			$	1,139,809
Balance as of January 1, 2013		$	(103,547	)		$	2,731			$	1,182,008			$	1,081,192			$	58,617			$	1,139,809
Profit/(loss) for the year after taxes			—				—				(3,417	)			(3,417	)			1,559				(1,858	)
Change in fair value of cash flow hedges			95,242				—				—				95,242				8,178				103,420
Currency translation differences			—				6,278				—				6,278				2,663				8,941
Tax effect			(28,295	)			—				—				(28,295	)			(2,453	)			(30,748	)
Other comprehensive income		$	66,947			$	6,278			$	—			$	73,225			$	8,388			$	81,613
Total comprehensive income		$	66,947			$	6,278			$	(3,417	)		$	69,808			$	9,947			$	79,755
Capital contributions		$	—			$	—			$	66,919			$	66,919			$	715			$	67,634
Scope variations, acquisitions and other movements		$	—			$	—			$	66,919			$	66,919			$	715			$	67,634
Balance as of December 31, 2013		$	(36,600	)		$	9,009			$	1,245,510			$	1,217,919			$	69,279			$	1,287,198

 

(1)	Notes 1 to 20 are an integral part of the combined financial statements

 

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Combined cash flow statements for the years ended December 31, 2013 and 2012

Amounts in thousands of U.S. dollars

 

				For the year ended
		Note (1)		2013				2012
I. Profit/(loss) for the year				$	(1,858	)		$	141
Non-monetary adjustments
Depreciation, amortization and impairment charges		6			46,943				20,234
Finance (income)/expenses					95,117				57,440
Fair value gains on derivative financial instruments					8,272				1,007
Shares of (profits)/losses from associates					(13	)			404
Income tax		16			(11,762	)			4,021
Changes in consolidation and other non-monetary items					(46,168	)			(60,269	)
II. Profit for the year from adjusted by non monetary items				$	90,531			$	22,978
Variations in working capital
Inventories					(5,244	)			—
Clients and other receivables					10,622				23,775
Trade payables and other current liabilities					(45,110	)			16,322
Financial investments and other current assets/liabilities					48,945				26,527
III. Variations in working capital				$	9,213			$	66,624
Income tax paid					(73	)			(255	)
Interest received					640				718
Interest paid					(62,923	)			(42,083	)
A. Net cash provided by operating activities				$	37,388			$	47,982
Investments in entities under the equity method		7			(240,639	)			(554,276	)
Investment in contracted concessional assets		6			(401,678	)			(518,495	)
Other non-current assets/liabilities					(52,250	)			(25,929	)
B. Net cash used in investing activities				$	(694,567	)		$	(1,098,700	)
Proceeds from Non recourse financing		13			1,139,671				339,550
Repayment of Non-recourse financing		13			(667,784	)			(61,620	)
Proceeds from related parties and other					442,986				829,322
C. Net cash provided by financing activities				$	914,873			$	1,107,252
Net increase/(decrease) in cash and cash equivalents				$	257,694			$	56,534
Cash, cash equivalents and bank overdrafts at beginning of the year					97,499				40,171
Translation differences cash or cash equivalent					2,471				794
Cash and cash equivalents at end of the year				$	357,664			$	97,499

 

(1)	Notes 1 to 20 are an integral part of the combined financial statements

 

F-30

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Contents

 

Note 1.- Nature of the business			F-32
Note 2.- Significant accounting policies			F-34
Note 3.- Financial risk management			F-44
Note 4.- Financial information by segment			F-45
Note 5.- Changes in the scope of the combined financial statements			F-50
Note 6.- Contracted concession assets			F-50
Note 7.- Investments carried under the equity method			F-52
Note 8.- Financial Instruments by category			F-53
Note 9.- Derivative financial instruments			F-53
Note 10.- Related parties			F-54
Note 11.- Clients and other receivable			F-56
Note 12.- Cash and cash equivalents			F-56
Note 13.- Non-recourse financing (project financing)			F-57
Note 14.- Grants and other liabilities			F-58
Note 15.- Trade payables and other current liabilities			F-59
Note 16.- Income Tax			F-59
Note 17.- Third-party guarantees and commitments			F-61
Note 18.- Other operating income and expenses			F-62
Note 19.- Financial income and expenses			F-63
Note 20.- Other information			F-64
Appendices(1)			F-65

 

(1)	The Appendices are an integral part of the notes to the combined financial statements.

 

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Note 1.- Nature of the business

Abengoa Yield Limited is a United Kingdom corporation incorporated on December 17, 2013, by Abengoa, S.A. (‘Abengoa’ or ‘the Parent’). Abengoa Yield Limited is a dividend growth-oriented company formed to serve as the primary vehicle through which Abengoa will own, manage, and acquire renewable energy, conventional power, electric transmission lines, and other contracted revenue-generating assets, initially focused on North America (United States and Mexico) and South America (Peru, Chile and Uruguay), as well as Europe (Spain in the first instance).

Abengoa listed on the Madrid Stock Exchange and the NASDAQ Global Select Market, is a leading engineering and clean technology company with operations in more than 50 countries worldwide that provides innovative solutions for a diverse range of customers in the energy and environmental sectors. Over the course of its 70-year history, Abengoa has developed a unique and integrated business model that applies accumulated engineering expertise to promoting sustainable development solutions, including delivering new methods for generating power from the sun, developing biofuels, producing potable water from seawater, and efficiently transporting electricity. A cornerstone of Abengoa’s business model has been the investment in proprietary technologies, particularly in areas with relatively high barriers to entry. Abengoa’s engineering and construction activities provide sophisticated turnkey engineering, procurement, and construction services from design to implementation for infrastructure projects within the energy and environmental sectors and engages in other related activities with a high technology component. Its concession-type infrastructures activities include the management, operation and maintenance of infrastructure assets, usually pursuant to long-term concession agreements. Its industrial production activities produce mostly bioethanol.

The accompanying combined financial statements of Abengoa Yield Limited (‘the Company’, ‘Abengoa Yield’ or ‘the Predecessor’) have been prepared in connection with the proposed initial public offering of common shares of Abengoa Yield, or the Offering, and represent the eleven assets described herein that Abengoa intends to transfer to Abengoa Yield prior to the Offering. The Company has elected to account for the Asset Transfer to Abengoa Yield Limited using the predecessor values, given that these will be transactions between entities under common control. Any difference between the consideration given and the aggregate book value of the assets and liabilities of the acquired entities as of the date of the transaction will be reflected as an adjustment to equity.

The portfolio consists of five renewable energy assets, a cogeneration facility, and several electric transmission lines, all of which are fully operational as of today, with the exception of the Mojave solar facility, which is in the test operation stage and expected to be fully operational by October 2014, and Palmatir wind farm, which is expected to achieve commercial operation day (‘COD’) by May 2014. All of our assets have contracted revenues (regulated revenues in the case of the Spanish assets) with low-risk offtakers, and have an average remaining contract life of approximately 26 years as of December 31, 2013. Our contracts are generally fixed-priced and pursuant to regulated rates revised based on inflation or similar types of public indexes. Over 90% of cash generated each year and available for distribution from these assets in the next four years is in U.S. dollars, or indexed to the U.S. dollar. Over 90% of our project-level debt is hedged against changes in interest rates through an underlying fixed rate on the debt instrument or through interest rate swaps, caps, or similar hedging instruments.

Our assets and operations are organized into the following three business sectors:

 

•

Renewable energy: renewable energy assets include of (i) two concentrated solar power (CSP) plants in the United States, Solana and Mojave, each with a gross capacity of 280 MW; (ii) one on-shore wind farm in Uruguay, Palmatir, with a gross capacity of 50 MW; and (iii) two CSP plants in Spain, Solaben 2 and Solaben 3, with a gross capacity of 50 MW each.

 

•

Conventional power: the conventional power asset consists of Abengoa Cogeneracion Tabasco, or ACT, a 300 MW cogeneration plant in Mexico.

 

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•

Electric transmission lines: the electric transmission line assets include (i) two lines in Peru, ATN and ATS, spanning a total of 931 miles; and (ii) three lines in Chile, Quadra 1, Quadra 2, and Palmucho, spanning a total of 87 miles.

Abengoa Yield is expected to be comprised of the following projects:

 

Our Assets

Type

Ownership

Location

Currency

Capacity (Gross)

Counterparty CreditRatings(3)

COD/ Expected COD

Contract Years Left

Solana

Renewable (CSP)

100% Class B1

Arizona (USA)

USD

280 MW

A-/A3/BBB+

4Q 2013

29

Mojave

Renewable (CSP)

100%

California (USA)

USD

280 MW

BBB/A3/BBB+

4Q 2014

25

ACT

Conventional Power

100%

Mexico

USD

300 MW

BBB+/Baa1/BBB+

2Q 2013

19

ATN

Transmission line

100%

Peru

USD

362 miles

BBB+/Baa2/BBB+

1Q 2011

27

ATS

Transmission line

100%

Peru

USD

569 miles

BBB+/Baa2/BBB+

1Q 2014

30

Quadra 1 & Quadra 2

Transmission line

100%

Chile

USD

81 miles

N/A

2Q 2014 & 1Q 2014

21

Palmucho

Transmission line

100%

Chile

CLP

6 miles

BBB+/Baa2/BBB+

4Q 2007

23

Palmatir

Renewable (Wind)

100%

Uruguay

USD

50 MW

BBB-/Baa3/BBB-

2Q 2014

20

Solaben 2 & Solaben 3

Renewable (CSP)

70%2

Spain

Euro

2x50 MW

BBB-/Baa2/BBB+

2Q 2012 & 4Q 2012

24

 

(1)

Liberty Interactive Corporation invested $300 million in Class A membership interests in exchange for a share of the dividends and taxable loss generated by Solana on September 30, 2013. As a result of the agreement, Liberty Interactive Corporation will receive 54.06% of both dividends and taxable loss generated during a period of approximately five years; such percentage will decrease to 24.05% thereafter.

(2)	Itochu Corporation holds 30% of the economic rights to each of Solaben 2 and Solaben 3.

(3)	Reflects the countrerparty’s issuer credit ratings issued by S&P, Moody’s and Fitch.

Entities included in these combined financial statements have signed with the grantor of the concession contracts of construction, operation and maintenance and they subcontract the construction of the contracted assets to Abengoa. Given that these projects (except for Palmucho) are included within the scope of IFRIC 12 and given that they are included in the combined financial statements during their construction phase, the Company has recorded income and cost attributable to the construction in the combined income statement. Construction revenue is recorded within “Other operating income” according to the percentage of completion method as established by IAS 11. Construction cost, which is fully contracted with related parties, is recorded within “Other operating expense”.

The combined financial statements were prepared using Abengoa’s historical basis in the assets and liabilities of the Predecessor, and include all revenues, expenses, assets, and liabilities attributed to the Predecessor. In addition, other operating expenses include an allocation of certain general and administrative services provided by Abengoa. The Company believes that by including the allocated costs, the combined income statement includes a reasonable estimate of actual costs incurred to operate the business. However, such expenses may not be indicative of the actual level of expense that would have been incurred by the Predecessor if it had operated as an independent, publicly-traded company during the periods prior to the Offering or of the costs expected to be incurred in the future. In the opinion of management, the inter-company eliminations and adjustments necessary for a fair presentation of the combined financial statements, in accordance with the International Financial Reporting Standards as issued by the International Accounting Standards Board (IFRS-IASB) have been made.

 

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These combined financial statements were approved by the Chief Executive Officer on February 27, 2014.

Note 2.- Significant accounting policies

2.1 Basis of preparation

The Company is not an existing legal entity for the periods presented. Rather, it is a combination of entities and assets currently owned by Abengoa and that have been under common control of Abengoa during the periods presented. The management has prepared the combined financial statements for the only purpose of including them as historical financial information of the predecessor of Abengoa Yield in a public prospectus.

Abengoa is a company listed in Madrid Stock Exchange and in NASDAQ and prepares, on an annual basis, consolidated financial statements in accordance with IFRS-IASB. Since the combined financial statements of Abengoa Yield are carved out from the consolidated financial statements of Abengoa in 2012 and 2013, the combined financial statements have also been prepared in accordance with the IFRS-IASB.

As a consequence, the combined financial statements represent the operations of the contributed entities using the predecessor values, and the accounting policies are the same as those used in the historical combined financial statements of Abengoa. Accordingly, the Company has not been considered IFRS first time adopter and IFRS 1 ‘First time adoption of financial reporting standards’ does not apply.

The combined financial statements are presented in U.S. dollars, which is the Company’s functional and presentation currency. Amounts included in these combined financial statements are all expressed in thousands of U.S. dollars, unless otherwise indicated.

Application of new accounting standards

 

a)	Standards, interpretations, and amendments effective from January 1, 2013 under IFRS-IASB, applied by the Company:

 

•

IFRS 13 ‘Fair value measurement’. IFRS 13 defines fair value, sets out a framework for measuring fair value in a single IFRS and requires disclosures about fair value measurements. This standard has been applied prospectively from January 1, 2013, and has not had a significant impact in the combined financial statements.

 

•

IFRS 10, ‘Consolidated financial statements’. IFRS 10 modifies the former definition of control. The new definition of control sets out the following three elements: power over the investee; exposure, or rights, to variable returns from involvement with the investee; and the ability to use power over the investee to affect the amount of the investor’s returns.

 

•

IFRS 12 ‘Disclosures of interests in other entities’. IFRS 12 defines the required disclosures of interests in subsidiaries, associates, joint ventures, and non-controlling interests.

 

•

IFRS 10, IFRS 11, and IFRS 12 (amendments) ‘Transition guidance’.

 

•

International Accounting Standard (IAS) 1 (amendment) ‘Financial statements presentation’. The main change resulting from this amendment is a requirement to group items presented in ‘other comprehensive income’ (OCI) into two categories on the basis of whether or not they will be subsequently reclassified to profit or loss.

The main impact of the application of the new standard IFRS 10 relates to the de-consolidation of Solana and Mojave, companies that do not fulfill the conditions of effective control of the interest in terms of decision making during the construction phase and which have been recorded in the combined financial statements according to the equity method during this period. In accordance with this standard, these projects are fully consolidated once they enter into operation and control over them is gained. Solana has been fully consolidated since its entry into operation (see note 5).

 

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According to the terms and requirements established in IAS 8 ‘Accounting policies, changes in accounting estimates and errors’ and according to IFRS 10 (C2A) ‘Transition’, the above standards and amendments have been retrospectively applied to 2012. Additionally, according to IAS 1 (40A), a third combined statement of financial position as of the beginning of the preceding period, which is January 1, 2012, has been presented applying the new accounting standards. According to IAS 1 (40c), it has not been necessary to present the notes relating to the combined statement of position as of January 1, 2012.

The effect of the de-consolidation of the affected companies and their integration according to the equity method on the combined statements of financial position as of December 31, 2012 and January 1, 2012 is shown below:

 

		Balance as of 12.31.12				Balance as of 1.1.12
Assets
Contracted concessional assets		$	(2,980.453	)		$	(899,409	)
Investments carried under the equity method			728,007				175,895
Financial investments			(1,365	)			(10,547	)
Current assets			(10,715	)			(628	)
Total assets		$	(2,264,526	)		$	(734,689	)
Long-term non-recourse project financing			(1,300,671	)			(385,426	)
Other non-current liabilities			(552,286	)			(346,376	)
Current liabilities			(411,568	)			(2,887	)
Total liabilities		$	(2,264,526	)		$	(734,689	)

This de-consolidation has had no impact on revenues, operating profit or net income for the year ended December 31, 2012.

There is no impact of the new standard IFRS 10 on the basic and diluted earnings per share for the year ended December 31, 2012

b) Recently Issued Accounting Pronouncements

Standards, interpretations and amendments published by the IASB that will be effective for periods beginning on or after January 1, 2014, are:

 

•

IAS 32 (amendment) ‘Compensation of financial assets for financial liabilities’. IAS 32 amendment is mandatory for periods beginning on or after January 1, 2014, and is to be applied retroactively.

 

•

IAS 36 (Amendment) ‘Recoverable amount disclosures for non-financial assets’. IAS 36 amendment is mandatory for periods beginning on or after January 1, 2014.

 

•

IAS 39 (Amendment) ‘Novation of derivatives and continuation of hedge accounting’. IAS 39 amendment is mandatory for periods beginning on or after January 1, 2014.

 

•

IFRS 9, ‘Financial instruments’. This Standard will be effective from January 1, 2015.

The company does not expect any material impact of the amendments that will be effective from January 1, 2014, and is assessing the impact of IFRS 9 (classification and measurement) which will be effective from January 1, 2015.

2.2. Principles to include and record companies in the combined financial statements

Companies included in these combined financial statements are accounted for as subsidiaries as long as Abengoa has had control over them and are accounted for as investments under the equity method as long as Abengoa has had significant influence over them, in the periods presented. The group of entities included in these combined financial statements is referred to as the “Company”.

 

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a)

Controlled entities

Control is achieved when the Company:

 

•

Has power over the investee;

 

•

Is exposed, or has rights, to variable returns from its involvement with the investee; and

 

•

Has the ability to use its power to affect its returns.

The Company reassesses whether or not it controls an investee when facts and circumstances indicate that there are changes to one or more of the three elements of control listed above. In order to evaluate the existence of control, we need to distinguish two independent stages in these projects in terms of decision making process: the construction phase and the operation phase. In some of these projects such as Solana and Mojave CSP plants in the United States, the Company has concluded that all the relevant decisions during the construction phase are subject to the approval of a third party. As a result, the Company does not have control over these assets during this period and records these companies as associates under the equity method. Once the project is in operation, the Company gains control over these companies which are then fully consolidated.

The Company uses the acquisition method to account for business combinations. According to this method, identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Any contingent consideration is recognized at fair value at the acquisition date and subsequent changes in its fair value are recognized in accordance with IAS 39 either in profit or loss or as a change to other comprehensive income. Acquisition related costs are expensed as incurred. The Company recognizes any non-controlling interest in the acquiree either at fair value or at the non-controlling interest’s proportionate share of the acquirer’s net assets on an acquisition by acquisition basis.

All assets and liabilities between entities of the combined group, equity, income, expenses, and cash flows relating to transactions between entities of the group are eliminated in full.

 

b)

Investments accounted for under the equity method

An associate is an entity over which the Company has significant influence. Significant influence is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies.

The results and assets and liabilities of associates are incorporated in these combined financial statements using the equity method of accounting. Under the equity method, an investment in an associate is initially recognized in the combined statement of financial position at cost and adjusted thereafter to recognize the Company share of the profit or loss and other comprehensive income of the associate.

Profits and losses resulting from the transactions of the Company with the associate are recognized in the combined financial Statements only to the extent of interests in the associate that are not related to the combined entities.

Controlled entities and associates included in these combined financial statements as of December 31, 2013, 2012, and as of January 1, 2012, are set out in appendices.

2.3. Contracted concessional Assets and price purchase agreements

Contracted concessional assets and price purchase agreements (PPAs) include fixed assets financed through non-recourse loans, related to service concession arrangements recorded in accordance with IFRIC 12, except for Palmucho, which is recorded in accordance with IAS 17. The infrastructures accounted for by the Company as concessions are related to the activities concerning electric transmission lines, solar electricity generation plants, cogeneration plants and a wind farm. The useful life of these assets is approximately the same as the length of the concession arrangement. The infrastructure used in a concession can be classified as an intangible asset or a financial asset, depending on the nature of the payment entitlements established in the agreement.

 

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The application of IFRIC 12 requires extensive judgment in relation with, among other factors, (i) the identification of certain infrastructures and contractual agreements in the scope of IFRIC 12, (ii) the understanding of the nature of the payments in order to determine the classification of the infrastructure as a financial asset or as an intangible asset and (iii) the timing and recognition of the revenue from construction and concessionary activity.

Under the terms of contractual arrangements within the scope of this interpretation, the operator shall recognize and measure revenue in accordance with IAS 11 and 18 for the services it performs. If the operator performs more than one service (i.e. construction or upgrade services and operation services) under a single contract or arrangement, consideration received or receivable shall be allocated by reference to the relative fair values of the services delivered, when the amounts are separately identifiable.

Consequently, even though construction is subcontracted to Abengoa, in accordance with the provisions of IFRIC 12, the Company recognizes and measures revenue and costs for providing construction services during the period of construction of the infrastructure in accordance with IAS 11 “Construction Contracts”. Construction revenue is recorded within “Other operating income” and Construction cost, which is fully contracted with related parties, is recorded within “Other operating expenses”. This applies in the same way to the two models.

 

a)

Intangible asset

The Company recognizes an intangible asset to the extent that it receives a right to charge final customers for the use of the infrastructure. This intangible asset is subject to the provisions of IAS 38 and is amortized linearly, taking into account the estimated period of commercial operation of the infrastructure which coincides with the concession period.

Once the infrastructure is in operation, the treatment of income and expenses is as follows:

 

•

Revenues from the updated annual revenue for the contracted concession, as well as operations and maintenance services are recognized in each period according to IAS 18 “Revenue”.

 

•

Operating and maintenance costs and general overheads and administrative costs are recorded in accordance with the nature of the cost incurred (amount due) in each period.

 

•

Financing costs are expensed as incurred.

 

b)

Financial asset

The Company recognizes a financial asset when demand risk is assumed by the grantor, to the extent that the concession holder has an unconditional right to receive payments for the asset. This asset is recognized at the fair value of the construction services provided, considering upgrade services in accordance with IAS 11, if any.

The financial asset is subsequently recorded at amortized cost calculated according to the effective interest method. Revenue from operations and maintenance services is recognized in each period according to IAS 18 “Revenue”. The remuneration of managing and operating the asset resulting from the valuation at amortized cost is also recorded in revenue.

Financing costs are expensed as incurred.

2.4. Borrowing costs

Interest costs incurred in the construction of any qualifying asset are capitalized over the period required to complete and prepare the asset for its intended use. A qualifying asset is an asset that necessarily takes a substantial period of time to get ready for its internal use or sale, which is considered to be more than one year. Remaining borrowing costs are expensed in the period in which they are incurred.

 

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2.5 Asset impairment

Abengoa Yield reviews its contracted concessional assets to identify any indicators of impairment annually.

The recoverable amount of an asset is the higher of its fair value less costs to sell and its value in use, defined as the present value of the estimated future cash flows to be generated by the asset. In the event that the asset does not generate cash flows independently of other assets, the Company calculates the recoverable amount of the Cash Generating Unit (‘CGU’) to which the asset belongs.

When the carrying amount of the CGU to which these assets belong is lower than its recoverable amount assets are impaired.

Assumptions used to calculate value in use include a discount rate, growth rate and projections considering real data based in the contracts terms and projected changes in both selling prices and costs. The discount rate is estimated by Management, to reflect both changes in the value of money over time and the risks associated with the specific CGU.

For contracted concessional assets, with a defined useful life and with a specific financial structure, cash flow projections until the end of the project are considered and no terminal value is assumed.

Contracted concessional assets have a contractual structure that permit the Company to estimate quite accurately the costs of the project (both in the construction and in the operations periods) and revenue during the life of the project.

Projections take into account real data based on the contract terms and fundamental assumptions based on specific reports prepared by experts, assumptions on demand and assumptions on production. Additionally, assumptions on macro-economic conditions are taken into account, such as inflation rates, future interest rates, etc. and sensitivity analyses are performed over all major assumptions which can have a significant impact in the value of the asset

Cash flow projections of CGUs are calculated in the functional currency of those CGUs and are discounted using rates that take into consideration the risk corresponding to each specific country and currency.

Taking into account that in most CGUs the specific financial structure is linked to the financial structure of the projects that are part of those CGUs, the discount rate used to calculate the present value of cash-flow projections is based on the weighted average cost of capital (WACC) for the type of asset, adjusted, if necessary, in accordance with the business of the specific activity and with the risk associated with the country where the project is performed.

In any case, sensitivity analyses are performed, especially in relation with the discount rate used and fair value changes in the main business variables, in order to ensure that possible changes in the estimates of these items do not impact the possible recovery of recognized assets.

Accordingly, the following table provides a summary of the discount rates used (WACC) and growth rates to calculate the recoverable amount for CGUs with the operating segment to which it pertains:

 

Operating segment		Discount rate		Growth Rate
Europe		5% - 6%		0%
South America		5% - 6%		0%

In the event that the recoverable amount of an asset is lower than its carrying amount, an impairment charge for the difference would be recorded in the combined income statement under the item “Depreciation, amortization and impairment charges”.

Pursuant to IAS 39, an impairment loss is recognized if the carrying amount of these assets exceeds the present value of future cash flows discounted at the initial effective interest rate.

 

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2.6 Loans and accounts receivable

Loans and accounts receivable are non-derivative financial assets with fixed or determinable payments, not listed on an active market.

In accordance with IFRIC 12, certain assets under concessions qualify as financial assets and are recorded as is described in note 2.3.

Pursuant to IAS 39, an impairment loss is recognized if the carrying amount of these assets exceeds the present value of future cash flows discounted at the initial effective interest rate.

Other loans and accounts receivable are initially recognized at fair value plus transaction costs and are subsequently measured at amortized cost in accordance with the effective interest rate method. Interest calculated using the effective interest rate method is recognized under other financial income within financial income.

2.7. Derivative financial instruments and hedging activities

Derivatives are recorded at fair value. The Company applies hedge accounting to all hedging derivatives that qualify to be accounted for as hedges under IFRS-IASB.

When hedge accounting is applied, hedging strategy and risk management objectives are documented at inception, as well as the relationship between hedging instruments and hedged items. Effectiveness of the hedging relationship needs to be assessed on an ongoing basis. Effectiveness tests are performed prospectively and retrospectively at inception and at each reporting date, following the dollar offset method.

Abengoa Yield applies cash flow hedging. Under this method, the effective portion of changes in fair value of derivatives designated as cash flow hedges are recorded temporarily in equity and are subsequently reclassified from equity to profit or loss in the same period or periods during which the hedged item affects profit or loss. Any ineffective portion of the hedged transaction is recorded in the combined income statement as it occurs.

When interest rate options are designated as hedging instruments, the intrinsic value and time value of the financial hedge instrument are separated. Changes in intrinsic value which are highly effective are recorded in equity and subsequently reclassified from equity to profit or loss in the same period or periods during which the hedged item affects profit or loss. Changes in time value are recorded as financial income or expense, together with any ineffectiveness.

When the hedging instrument matures or is sold, or when it no longer meets the requirements to apply hedge accounting, accumulated gains and losses recorded in equity remain as such until the forecast transaction is ultimately recognized in the combined income statement. However, if it becomes unlikely that the forecast transaction will actually take place, the accumulated gains and losses in equity are recognized immediately in the combined income statement.

2.8. Fair value estimates

Financial instruments measured at fair value are presented in accordance with the following level classification based on the nature of the inputs used for the calculation of fair value:

 

•

Level 1: Inputs are quoted prices in active markets for identical assets or liabilities.

 

•

Level 2: Fair value is measured based on inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices).

 

•

Level 3: Fair value is measured based on unobservable inputs for the asset or liability.

In the event that prices cannot be observed, the management shall make its best estimate of the price that the market would otherwise establish based on proprietary internal models which, in the majority of cases, use data

 

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based on observable market parameters as significant inputs (Level 2) but occasionally use market data that is not observed as significant inputs (Level 3). Different techniques can be used to make this estimate, including extrapolation of observable market data. The best indication of the initial fair value of a financial instrument is the price of the transaction, except when the value of the instrument can be obtained from other transactions carried out in the market with the same or similar instruments, or valued using a valuation technique in which the variables used only include observable market data, mainly interest rates. Differences between the transaction price and the fair value based on valuation techniques that use data that is not observed in the market, are not initially recognized in the income statement.

Abengoa Yield derivatives correspond mainly to the interest rate swaps designated as cash flow hedges. All derivatives are classified as level 2.

Description of the valuation method

Interest rate swap valuations are made by valuing the swap part of the contract and valuing the credit risk. The methodology used by the market and applied by Abengoa Yield to value interest rate swaps is to discount the expected future cash flows according to the parameters of the contract. Variable interest rates, which are needed to estimate future cash flows, are calculated using the curve for the corresponding currency and extracting the implicit rates for each of the reference dates in the contract. These estimated flows are discounted with the swap zero curve for the reference period of the contract.

The effect of the credit risk on the valuation of the interest rate swaps depends on the future settlement. If the settlement is favorable for the Company, the counterparty credit spread will be incorporated to quantify the probability of default at maturity. If the expected settlement is negative for the Company, its own credit risk will be applied to the final settlement.

Classic models for valuing interest rate swaps use deterministic valuation of the future of variable rates, based on future outlooks. When quantifying credit risk, this model is limited by considering only the risk for the current paying party, ignoring the fact that the derivative could change sign at maturity. A payer and receiver swaption model is proposed for these cases. This enables the associated risk in each swap position to be reflected. Thus, the model shows each agent’s exposure, on each payment date, as the value of entering into the ‘tail’ of the swap, i.e. the live part of the swap.

Variables (Inputs)

Interest rate derivative valuation models use the corresponding interest rate curves for the relevant currency and underlying reference in order to estimate the future cash flows and to discount them. Market prices for deposits, futures contracts and interest rate swaps are used to construct these curves. Interest rate options (caps and floors) also use the volatility of the reference interest rate curve.

To estimate the credit risk of the counterparty, the credit default swap (CDS) spreads curve is obtained in the market for important individual issuers. For less liquid issuers, the spreads curve is estimated using comparable CDSs or based on the country curve. To estimate proprietary credit risk, prices of debt issues in the market and CDSs for the sector and geographic location are used.

The fair value of the financial instruments that results from the aforementioned internal models takes into account, among other factors, the terms and conditions of the contracts and observable market data, such as interest rates, credit risk and volatility. The valuation models do not include significant levels of subjectivity, since these methodologies can be adjusted and calibrated, as appropriate, using the internal calculation of fair value and subsequently compared to the corresponding actively traded price. However, valuation adjustments may be necessary when the listed market prices are not available for comparison purposes.

 

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2.9. Clients and other receivables

Clients and other receivables are amounts due from customers for sales in the normal course of business. They are recognized initially at fair value and subsequently measured at amortized cost using the effective interest rate method, less allowance for doubtful accounts. Trade receivables due in less than one year are carried at their face value at both initial recognition and subsequent measurement, provided that the effect of not discounting flows is not significant.

An allowance for doubtful accounts is recorded when there is objective evidence that the Company will not be able to recover all amounts due as per the original terms of the receivables.

2.10. Cash and cash equivalents

Cash and cash equivalents include cash in hand, cash in bank and other highly-liquid current investments with an original maturity of three months or less which are held for the purpose of meeting short-term cash commitments.

2.11. Grants

Grants are recognized at fair value when it is considered that there is a reasonable assurance that the grant will be received and that the necessary qualifying conditions, as agreed with the entity assigning the grant, will be adequately complied with.

Grants are recorded as liabilities in the combined statement of financial position and are recognized in “Other operating income” in the combined income statement based on the period necessary to match them with the costs they intend to compensate.

In addition, as described in note 2.12 below, grants correspond also to loans with interest rates below market rates, for the initial difference between the fair value of the loan and the proceeds received.

2.12. Loans and borrowings

Loans and borrowings are initially recognized at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortized cost and any difference between the proceeds initially received (net of transaction costs incurred in obtaining such proceeds) and the repayment value is recognized in the combined income statement over the duration of the borrowing using the effective interest rate method.

Loans with interest rates below market rates are initially recognized at fair value in liabilities and the difference between proceeds received from the loan and its fair value is initially recorded within “Grants and Other liabilities” in the combined statement of financial position, and subsequently recorded in “Other operating income” in the combined income statement when the costs financed with the loan are expensed.

2.13. Bonds and notes

The Company initially recognizes ordinary notes at fair value, net of issuance costs incurred. Subsequently, notes are measured at amortized cost until settlement upon maturity. Any other difference between the proceeds obtained (net of transaction costs) and the redemption value is recognized in the combined income statement over the term of the debt using the effective interest rate method.

2.14. Income taxes

Current income tax expense is calculated on the basis of the tax laws in force as of the date of the combined statement of financial position in the countries in which the subsidiaries and associates operate and generate taxable income.

 

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Deferred income tax is calculated in accordance with the liability method, based upon the temporary differences arising between the carrying amount of assets and liabilities and their tax base. Deferred income tax is determined using tax rates and regulations which are expected to apply at the time when the deferred tax is realized.

Deferred tax assets are recognized only when it is probable that sufficient future taxable profit will be available to use deferred tax assets.

2.15. Trade payables and other liabilities

Trade payables are obligations arising from purchases of goods and services in the ordinary course of business and are recognized initially at fair value and are subsequently measured at their amortized cost using the effective interest method. Other liabilities are obligations not arising in the normal course of business and which are not treated as financing transactions. Advances received from customers are recognized as “Trade payables and other current liabilities”.

2.16. Foreign currency transactions

The combined financial statements are presented in U.S. dollars, which is Abengoa Yield functional and reporting currency. Financial statements of each subsidiary within the Company are measured in the currency of the principal economic environment in which the subsidiary operates, which is the subsidiary’s functional currency.

Transactions denominated in a currency different from the subsidiary’s functional currency are translated into the subsidiary’s functional currency applying the exchange rates in force at the time of the transactions. Foreign currency gains and losses that result from the settlement of these transactions and the translation of monetary assets and liabilities denominated in foreign currency at the year-end rates are recognized in the combined income statement, unless they are deferred in equity, as occurs with cash flow hedges and net investment in foreign operations hedges.

Assets and liabilities of subsidiaries with a functional currency different from the Company’s reporting currency are translated to U.S. dollars at the exchange rate in force at the closing date of the financial statements. Income and expenses are translated into U.S. dollars using the average annual exchange rate, which does not differ significantly from using the exchange rates of the dates of each transaction. The difference between equity translated at the historical exchange rate and the net financial position that results from translating the assets and liabilities at the closing rate is recorded in equity under the heading “Accumulated currency translation differences”.

Results of companies carried under the equity method are translated at the average annual exchange rate.

2.17. Equity

Given that the Company is not an existing legal entity, legal share capital does not exist for these combined financial statements as of December 31, 2013 and 2012, and cannot be presented separately in Equity.

The Company has recyclable balances in its equity, corresponding mainly to hedge reserves and translation differences arising from currency conversion in the preparation of these combined financial statements. These balances have been presented separately in Equity.

Non-controlling interest represents interest from other partners in entities included in these combined financial statements which are not fully owned by Abengoa as of the dates presented.

Other Equity represents the Parent’s net investment in the entities included in these combined financial statements.

 

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2.18. Provisions and contingencies

Provisions are recognized when:

 

•

there is a present obligation, either legal or constructive, as a result of past events;

 

•

it is more likely than not that there will be a future outflow of resources to settle the obligation; and

 

•

the amount has been reliably estimated.

Provisions are initially measured at the present value of the expected outflows required to settle the obligation and subsequently valued at amortized cost following the effective interest method. The balance of Provisions disclosed in the Notes reflects management’s best estimate of the potential exposure as of the date of preparation of the Combined Financial Statements.

Contingent liabilities are possible obligations, existing obligations with low probability of a future outflow of economic resources and existing obligations where the future outflow cannot be reliably estimated. Contingences are not recognized in the Combined Statements of Financial Position unless they have been acquired in a business combination.

Some companies included in the combined group have dismantling provisions, which are intended to cover future expenditures related to the dismantlement of the solar plants and it will be likely to be settled with an outflow of resources in the long term (over 5 years)

Such provisions are accrued when the obligation for dismantling, removing and restoring the site on which the plant is located, is incurred, which is usually during the construction period. The provision is measured in accordance with IAS 37, Provisions, Contingent Liabilities and Contingent Assets and is recorded as a liability under the heading “Grants and other liabilities” of the Financial Statements, and as part of the cost of the plant under the heading “Contracted concessional assets.”

2.19. Use of estimates

Some of the accounting policies applied require the application of significant judgment by management to select the appropriate assumptions to determine these estimates. These assumptions and estimates are based on our historical experience, advice from experienced consultants, forecasts and other circumstances and expectations as of the close of the financial period. The assessment is considered in relation to the global economic situation of the industries and regions where the Company operates, taking into account future development of our businesses. By their nature, these judgments are subject to an inherent degree of uncertainty; therefore, actual results could materially differ from the estimates and assumptions used. In such cases, the carrying values of assets and liabilities are adjusted.

The most critical accounting policies, which reflect significant management estimates and judgment to determine amounts in our consolidated financial statements, are as follows:

 

•

Contracted concesional agreements.

 

•

Impairment of intangible assets.

 

•

Assessment of control.

 

•

Derivative financial instruments and fair value estimates.

 

•

Income taxes and recoverable amount of deferred tax assets.

As of the date of preparation of these combined financial statements, no relevant changes in the estimates made are anticipated and, therefore, no significant changes in the value of the assets and liabilities recognized at December 31, 2013, are expected.

 

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Although these estimates and assumptions are being made using all available facts and circumstances, it is possible that future events may require management to amend such estimates and assumptions in future periods. Changes in accounting estimates are recognized prospectively, in accordance with IAS 8, in the combined income statement of the year in which the change occurs.

Note 3.- Financial risk management

Abengoa Yield’s activities are exposed to various financial risks: market risk (including currency risk and interest rate risk), credit risk and liquidity risk. Risk is managed by the Company’s Risk Management and Finance Department, which are responsible for identifying and evaluating financial risks quantifying them by project, region and company, in accordance with mandatory internal management rules. Written internal policies exist for global risk management, as well as for specific areas of risk. In addition, there are official written management regulations regarding key controls and control procedures for each company and the implementation of these controls is monitored through internal audit procedures.

 

a)	Market risk

The Company is exposed to market risk, such as movement in foreign exchange rates and interest rates. All of these market risks arise in the normal course of business and we do not carry out speculative operations. For the purpose of managing these risks, we use a series of swaps and options on interest rates. None of the derivative contracts signed has an unlimited lose exposure.

 

•

Interest rate risk

Interest rate risk arises when the Company’s activities are exposed to changes in foreign interest rates, which arises from financial liabilities at variable interest rates. The main interest rate exposure for the Company relates to the variable interest rate with reference to the Libor and Euribor. To minimize the interest rate risk, the Company primarily uses interest rate swaps and interest rate options (caps), which, in exchange for a fee, offer protection against an increase in interest rates. The Company does not use derivatives for speculative purposes.

As a result, the notional amounts hedged, strikes contracted and maturities, depending on the characteristics of the debt on which the interest rate risk is being hedged, are very diverse, including the following:

 

1)

Non-recourse debt in U.S. dollars: between 75% and 100% of the notional amount, maturities until 2028 average guaranteed interest rates of between 2.515% and 3.787%.

 

2)

Non-recourse debt in euro: between 80% and 100% of the notional amount, maturities until 2030 and average guaranteed interest rates of between 0.75% and 3.75%.

In connection with our interest rate derivative positions, the most significant impacts on our combined financial statements are derived from the changes in EURIBOR or LIBOR, which represent the reference interest rate for the majority of our debt. In the event that Euribor and Libor had risen by 25 basis points as of December 31, 2013, with the rest of the variables remaining constant, the effect in the combined income statement would have been a loss of $ 195 thousand (a profit of $296 thousand in 2012) and an increase in hedging reserves of $16.328 thousand ($24,040 thousand in 2012). The increase in hedging reserves would be mainly due to an increase in the fair value of interest rate swaps designated as hedges.

A breakdown of the interest rates derivatives as of December 31, 2013 and 2012, is provided in note 9.

 

•

Currency risk

The main cash flows in the entities included in these combined financial statements are cash collections arising from long-term contracts with clients and debt payments arising from project finance repayment. Given that financing of the projects is always closed in the same currency in which the contract with client is signed, natural hedge exists for the main operations of the Company.

 

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b)	Credit risk

The company considers that it has a limited credit risk with clients as revenues derive from power purchase agreements with electric utilities and state-owned entities.

 

c)	Liquidity risk

Abengoa Yield’s liquidity and financing policy is intended to ensure that the Company maintains sufficient funds to meet our financial obligations as they fall due.

Project finance borrowing permits the Company to finance the project through non-recourse debt and thereby insulate the rest of its assets from such credit exposure. The Company incurs in project-finance debt on a project-by-project basis.

The repayment profile of each project is established on the basis of the projected cash flow generation of the business. This ensures that sufficient financing is available to meet deadlines and maturities, which mitigates the liquidity risk significantly.

Note 4.- Financial information by segment

Abengoa Yield’s segment structure reflects how management currently makes financial decisions and allocates resources. Its operating segments are based on the following geographies where the contracted concessional assets are located:

 

•

North America

 

•

South America

 

•

Europe

Based on the type of business, the Company has identified the following business sectors:

Renewable energy: Our renewable energy assets include two CSP plants in the United States, Solana and Mojave, each with a gross capacity of 280 MW and located in Arizona and California, respectively. Solana reached COD on October 9, 2013, and Mojave has substantially completed construction and is in operation test stage, with expected COD by October 2014. Additionally, we own a wind farm in Uruguay, Palmatir, with a gross capacity of 50 MW. The construction of Palmatir is complete and COD is expected in May 2014. Finally, Solaben 2 and Solaben 3 are two CSP plants located in Spain. Both projects have been in operation since mid-2012 and receive regulated revenues under the framework for renewable projects in Spain.

Conventional power: Our conventional power asset consist of ACT, a 300 MW cogeneration plant in Mexico, which is party to a 20-year take-or-pay contract with Pemex for the sale of electric power and steam.

Electric transmission lines: Our electric transmission assets include (i) two lines in Peru, ATN, and ATS, spanning a total of 931 miles; (ii) three lines in Chile, Quadra 1, Quadra 2 and Palmucho, spanning a total of 87 miles. ATN reached COD in 2011 and ATS reached COD on January 17, 2014. Quadra 1 and Quadra 2 have been in operation since February 2014. Palmucho reached COD in October 2007.

Abengoa Yields’ Chief Operating Decision Maker (CODM) assesses the performance and assignment of resources according to the identified operating segments. The CODM considers the revenues as a measure of the business activity and Adjusted EBITDA (earnings before interest, tax, share of (loss)/profit of associates, depreciation amortization and impairment) as measure of the performance of each segment. In order to assess performance of the business, the CODM receives reports of each reportable segment using revenues and Adjusted EBITDA. Net interest expense evolution is assessed on a consolidated basis. Financial expense and amortization are not taken into consideration by CODM for the allocation of resources.

 

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a)

The following tables show Revenues and Adjusted EBITDA by operating segments and business sectors for the years 2013 and 2012:

 

Geography		Revenue								Adjusted EBITDA
		2013				2012				2013				2012
North America		$	113,998			$	62,268			$	96,712			$	61,106
South America			25,392				16,986				18,979				10,191
Europe			71,517				27,929				42,838				16,670
Total		$	210,907			$	107,183			$	158,529			$	87,967

 

Business Sectors		Revenue								Adjusted EBITDA
		2013				2012				2013				2012
Renewable energy		$	82,714			$	27,929			$	55,797			$	16,121
Conventional power			102,801				62,268				83,277				61,106
Electric transmission lines			25,392				16,986				19,455				10,740
Total		$	210,907			$	107,183			$	158,529			$	87,967

The reconciliation of segment Adjusted EBITDA with the profit/(loss) attributable to the Company is as follows:

 

Line item		For the year ended 12.31.13				For the year ended 12.31.12
Total segment Adjusted EBITDA		$	158,529			$	87,967
Depreciation, amortization, and impairment charges			(46,943	)			(20,234	)
Financial expense, net			(125,219	)			(63,167	)
Share in profits/(losses) associates			13				(404	)
Income tax			11,762				(4,021	)
Profit attributable to non-controlling interests			(1,559	)			1,195
Profit attributable to the Company		$	(3,417	)		$	1,336

 

b)

The long term assets and liabilities by operating segments (and business sector) at the end of 2013 and 2012 are as follows:

Assets and liabilities by geography as of December 31, 2013:

 

Item		North America				South America				Europe				Balance as of 12.31.13
Assets allocated
Contracted concessional assets		$	2,678,436			$	1,034,768			$	704,916			$	4,418,120
Investments carried under the equity method			387,324				—				—				387,324
Current financial investments			230,046				36,317				—				266,363
Cash and cash equivalents			206,298				86,681				64,685				357,664
Subtotal allocated		$	3,502,104			$	1,157,766			$	769,601			$	5,429,471
Unallocated assets
Other non-current assets															81,636
Other current assets															102,841
Subtotal unallocated														$	184,477
Total assets														$	5,613,948

 

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Item		North America				South America				Europe				Balance as of 12.31.13
Liabilities allocated
Long-term and short-term non-recourse project financing		$	1,842,817			$	605,397			$	446,436			$	2,894,650
Subtotal allocated		$	1,842,817			$	605,397			$	446,436			$	2,894,650
Unallocated liabilities
Other non-current liabilities															1,209,497
Other current liabilities															222,603
Subtotal unallocated														$	1,432,100
Total liabilities														$	4,326,750
Equity unallocated														$	1,287,198
Total liabilities and equity unallocated														$	2,719,298
Total liabilities and equity														$	5,613,948

Assets and liabilities by geography as of December 31, 2012:

 

Item		North America				South America				Europe				Balance as of 12.31.12
Assets allocated
Contracted concessional assets		$	570,198			$	780,939			$	707,804			$	2,058,941
Investments carried under the equity method			734,083				—				—				734,083
Current financial investments			47,607				28,432				51,608				127,647
Cash and cash equivalents			8,967				55,538				32,994				97,499
Subtotal allocated		$	1,360,855			$	864,909			$	779,406			$	3,018,170
Unallocated assets
Other non-current assets														$	73,847
Other current assets														$	106,077
Subtotal unallocated														$	179,924
Total assets														$	3,198,094

 

Item		North America				South America				Europe				Balance as of 12.31.12
Liabilities allocated
Long-term and short-term non-recourse project financing		$	489,084			$	417,266			$	462,559			$	1,368,909
Subtotal allocated		$	489,084			$	417,266			$	462,559			$	1,368,909
Unallocated liabilities
Other non-current liabilities															502,194
Other current liabilities															187,182
Subtotal unallocated														$	689,376
Total liabilities														$	2,058,285
Equity unallocated														$	1,139,809
Total liabilities and equity unallocated														$	1,829,185
Total liabilities and equity														$	3,198,094

 

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Assets and liabilities by business sectors as of December 31, 2013:

 

Item		Renewable energy				Conventional power				Electric transmission lines				Balance as of 12.31.13
Assets allocated
Contracted concessional assets		$	2,888,622			$	635,849			$	893,649			$	4,418,120
Investments carried under the equity method			387,324				—				—				387,324
Current financial investments			122,795				107,255				36,313				266,363
Cash and cash equivalents			90,395				186,078				81,191				357,664
Subtotal allocated		$	3,489,136			$	929,182			$	1,011,153			$	5,429,471
Unallocated assets
Other non-current assets															81,636
Other current assets															102,841
Subtotal unallocated														$	184,477
Total assets														$	5,613,948

 

Item		Renewable energy				Conventional power				Electric transmission lines				Balance as of 12.31.13
Liabilities allocated
Long-term and short-term non-recourse project financing		$	1,667,174			$	729,318			$	498,158			$	2,894,650
Subtotal allocated		$	1,667,174			$	729,318			$	498,158			$	2,894,650
Unallocated liabilities
Other non-current liabilities															1,209,497
Other current liabilities															222,603
Subtotal unallocated														$	1,432,100
Total liabilities														$	4,326,750
Equity unallocated														$	1,287,198
Total liabilities and equity unallocated														$	2,719,298
Total liabilities and equity														$	5,613,948

Assets and liabilities by business sectors as of December 31, 2012:

 

Item		Renewable energy				Conventional power				Electric transmission lines				Balance as of 12.31.12
Assets allocated
Contracted concessional assets		$	757,626			$	570,198			$	731,117			$	2,058,941
Investments carried under the equity method			734,083				—				—				734,083
Current financial investments			51,608				47,607				28,432				127,647
Cash and cash equivalents			33,181				8,967				55,351				97,499
Subtotal allocated		$	1,576,498			$	626,772			$	814,900			$	3,018,170
Unallocated assets
Other non-current assets															73,847
Other current assets															106,077
Subtotal unallocated														$	179,924
Total assets														$	3,198,094

 

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Item		Renewable energy				Conventional power				Electric transmission lines				Balance as of 12.31.12
Liabilities allocated
Long-term and short-term non-recourse project financing		$	511,077			$	489,085			$	368,747			$	1,368,909
Subtotal allocated		$	511,077			$	489,085			$	368,747			$	1,368,909
Unallocated liabilities
Other non-current liabilities															502,194
Other current liabilities															187,182
Subtotal unallocated														$	689,376
Total liabilities														$	2,058,285
Equity unallocated														$	1,139,809
Total liabilities and equity unallocated														$	1,829,185
Total liabilities and equity														$	3,198,094

 

c)

The investment in contracted concessional assets and in entities under the equity method by operating segments and business sectors for the years 2013 and 2012 are as follows:

 

Geography		Capex
		2013				2012
North America		$	347,397			$	628,011
South America			294,658				293,909
Europe			262				150,851
Total		$	642,317			$	1,072,771

 

Business sectors		Capex
		2013				2012
Renewable energy		$	323,251			$	753,878
Conventional power			106,757				73,735
Electric transmission lines			212,309				245,158
Total		$	642,317			$	1,072,771

 

d)

The amount of depreciation and amortization expense recognized for the years ended December 31, 2013 and 2012, are as follows

 

Depreciation and amortization by geography		Year ended December 31,
		2013				2012
North America		$	(16,182	)		$	—
South America			(10,853	)			(10,871	)
Europe			(19,908	)			(9,363	)
Total		$	(46,943	)		$	(20,234	)

 

Depreciation and amortization by business sectors		Year ended December 31,
		2013				2012
Renewable energy		$	(36,090	)		$	(9,363	)
Conventional power			—				—
Electric transmission lines			(10,853	)			(10,871	)
Total		$	(46,943	)		$	(20,234	)

 

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Note 5.- Changes in the scope of the combined financial statements

On October 13, 2013, Arizona Solar One, LLC, the Company that holds the assets in Solana, which was recorded under the equity method during its construction period, entered into operation and started to be fully consolidated once control over this company was gained.

The Company reassesses whether or not it controls an investee when facts and circumstances indicate that there are changes to the elements that determine control (power over the investee, exposure to variable returns of the investee and ability to use its power to affect its returns). The Company concluded that during the construction phase of Solana plant all the relevant decisions were subject to the control and approval of a third party . As a result, the Company did not have control over these assets during this period. IFRS 10 (B80) establishes that control requires a continuous assessment and that the Company shall reassess if it controls on investee if facts and circumstances indicate that there are changes to the elements of control. Once the project entered into operation, the decision making process changed such that the Company makes decisions about the relevant activities of the investee, the investee was controlled and it started to be fully consolidated.

As during the construction period the assets were included in the investee’s accounts under the scope of IFRIC 12, the book value of the combined assets and liabilities is the same as its fair value. The amount of assets and liabilities integrated is shown in the following table:

 

		As of October 13, 2013
Current assets		$	10,494
Contracted concessional assets (note 6)			2,027,642
Other current and non-current assets			18,931
Non-recourse project financing (note 13)			(1,035,681	)
Other current and non-current liabilities			(433,974	)
Book value of previously held interest (note 7)			(587,412	)
Total		$	—

The results of operations of Arizona Solar One have been included in the Company’s renewable energy activities from the date in which it started to be fully consolidated.

Note 6.- Contracted concessional assets

 

a)

The following table shows the movements of contracted concessional assets included in the heading ‘Contracted Concessional assets’ for 2013:

 

Cost		Total
Total as of January 1, 2013		$	2,085,032
Additions			401,678
Translation differences			29,987
Change in the scope of the combined financial statements (note 5)			2,027,642
Reclassifications and other movements			(52,051	)
Total as of December 31, 2013		$	4,492,286
Accumulated amortization		Total
Total as of January 1, 2013		$	(26,091	)
Additions			(46,943	)
Translation differences			(1,132	)
Total accum. amort. as of December 31, 2013		$	(74,166	)
Net balance at December 31, 2013		$	4,418,120

 

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During 2013 contracted concessional assets increased mainly due to the full consolidation of Arizona Solar One, company that holds the Solana plant, once control over the company was gained with the entry into operation of the plant (see note 5).

In addition, contracted concessional assets increased due to the construction of contracted concessions which were not yet in operation, mainly the cogeneration plant in Mexico ($107 million), electric transmission lines in Peru ($158 million), electric transmission lines in Chile ($54 million) and Palmatir wind farm in Uruguay ($82 million). No losses from impairment of ‘Contracted concessional assets in projects’ were recorded during 2013.

The decrease included in “reclassification and other movements” is mainly due to the reclassification from the long to the short term, of the current portion of the contracted concessional financial assets (see note 23).

As of December 31, 2013, contracted concessional financial assets amount to $722,989 thousand.

 

b)

The following table shows the movements of contracted concessional assets included in the heading ‘Contracted concessional assets’ for 2012:

 

Cost		Total
Total as of January 1, 2012		$	1,552,409
Additions			518,495
Translation differences			14,608
Reclassifications and other movements			(480	)
Total as of December 31, 2012		$	2,085,032
Accumulated amortization		Total
Total as of January 1, 2012		$	(5,614	)
Additions			(20,234	)
Translation differences			(243	)
Total accum. amort. as of December 31, 2012		$	(26,091	)
Net balance at December 31, 2012		$	2,058,941

During 2012 contracted concessional assets increased due to the construction of contracted concessions which were not yet in operation, mainly CSP plants in Spain ($142 million), as well as the cogeneration plant in Mexico ($73 million) and electric transmission lines in Peru ($215 million).

No losses from impairment of ‘Contracted concessional assets in projects’ were recorded during 2012.

As of December 31, 2012, contracted concessional financial assets amount to $ 608,717 thousand.

 

c)

Capitalized interest cost for the year ended December 31, 2013, amounts to $101,218 thousand ($79,938 thousand in 2012).

 

d)

There are no intangible assets with indefinite useful lives. There are no intangible assets restricted for use or pledged as security for liabilities.

For further details of projects subject to the application of IFRIC 12, please see Appendix III.

 

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Note 7.- Investments carried under the equity method

The table below shows the breakdown and the movement of the investments held in associates for 2013 and 2012:

 

Investments in associates		2013				2012
Initial balance		$	734,083			$	180,210
Capital contributions			240,639				554,276
Change in the scope of the combined financial statements (note 5)			(587,412	)			—
Share of (loss)/profit			13				(404	)
Final balance		$	387,324			$	734,083

The decrease in 2013 is due to the entity Arizona Solar One, which is fully consolidated since the plant entered into operation in October 2013 (see note 5).

The increase in 2013 and 2012 was due to the equity contribution to Arizona Solar One, and Mojave Solar.

The tables below show a breakdown of assets, revenues and profit and loss as well as other information of interest for the years 2013 and 2012 of the associated companies:

 

Company		% Shares				Non- current assets				Current assets				Non- current liabilities				Current liabilities				Revenue				Operating profit/ (loss)				Net profit/ (loss)				Investment under the equity method
Mojave Solar LLC			100.00			$	1,450,923			$	22,347			$	1,034,729			$	57,293			$	—			$	(132	)		$	13			$	381,248
Evacucion Valdecaballeros, S.L.			28.56				28,041				2,588				368				421				452				(854	)			(664	)			6,076
As of December 31, 2013						$	1,478,964			$	24,935			$	1,035,097			$	57,714			$	452			$	(956	)		$	(651	)		$	387,324

 

Company		% Shares				Non- current assets				Current assets				Non- current liabilities				Current liabilities				Revenue				Operating profit/ (loss)				Net profit/ (loss)				Investment under the equity method
Arizona Solar One LLC			100.00			$	1,802,307			$	10,615			$	1,195,682			$	110,061			$	—			$	(75	)		$	(50	)		$	507,179
Mojave Solar LLC			100.00				1,179,511				100				657,276				301,507				—				(354	)			(354	)			220,828
Evacucion Valdecaballeros, S.L.			28.56				25,008				5,495				340				957				87				(309	)			(336	)			6,076
As of December 31, 2012						$	3,006,826			$	16,210			$	1,853,298			$	412,525			$	87			$	(738	)		$	(740	)		$	734,083

None of the associated companies referred to above is a listed company.

 

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Note 8.- Financial instruments by category

Financial instruments are primarily deposits, derivatives, trade and other receivables and loans. Financial instruments by category (current and non-current), reconciled with the statement of financial position, are as follows:

 

Category		Notes		Loans and receivables / payables				Hedging derivatives				Balance as of 12.31.13
Derivative assets		9		$	—			$	13,622			$	13,622
Financial accounts receivables					281,593				—				281,593
Clients and other receivables		11			97,597				—				97,597
Cash and cash equivalents		12			357,664				—				357,664
Total Financial assets				$	736,854			$	13,622			$	750,476
Non-recourse financing		13			2,894,650				—				2,894,650
Related parties		10			492,534				—				492,534
Trade payables and other current liabilities		15			204,013				—				204,013
Derivative liabilities		9			—				44,221				44,221
Total Financial liabilities				$	3,591,197			$	44,221			$	3,635,418

 

Category		Notes		Loans and receivables / payables				Hedging derivatives				Balance as of 12.31.12
Derivative assets		9		$	—			$	5,604			$	5,604
Financial accounts receivables					135,648				—				135,648
Clients and other receivables		11			106,077				—				106,077
Cash and cash equivalents		12			97,499				—				97,499
Total Financial assets				$	339,224			$	5,604			$	344,828
Non-recourse financing		13			1,368,909				—				1,368,909
Related parties		10			222,946				—				222,946
Trade payables and other current liabilities		15			186,048				—				186,048
Derivative liabilities		9			—				134,673				134,673
Total Financial liabilities				$	1,777,903			$	134,673			$	1,912,576

As of December 31, 2013 and 2012, all the financial instruments measured at fair value have been classified as Level 2.

Financial accounts receivable include the short-term portion of contracted concessional assets (see Note 6).

Note 9.- Derivative financial instruments

The breakdowns of the fair value amount of the derivative financial instruments as of December 31, 2013 and 2012 are as follows:

 

Concept		Balance as of 12.31.13								Balance as of 12.31.12
		Assets				Liabilities				Assets				Liabilities
Interest rate derivatives – cash flow hedge		$	13,622			$	44,221			$	5,604			$	134,673

All the derivatives are interest rate cash-flow hedges. All are classified as non-current assets or non-current liabilities, as they hedge long-term financing agreements.

 

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As stated in note 3 to these combined financial statements, the general policy is to hedge variable interest rates of financing agreements purchasing call options (caps) in exchange of a premium to fix the maximum interest rate cost and floating to fixed interest rate swaps.

As a result, the notional amounts hedged, strikes contracted and maturities, depending on the characteristics of the debt on which the interest rate risk is being hedged, can be diverse:

 

•

Non-recourse financing in Euros: we hedge between 80% and 100% of the notional amount, maturities until 2030 and average guaranteed interest rates of between 0.75 % and 3.75%.

 

•

Non-recourse financing in U.S. dollars: we hedge between 75% and 100% of the notional amount, including maturities until 2028 and average guaranteed interest rates of between 2.515% and 3.787%.

The table below shows a breakdown of the maturities of notional amounts of interest rate derivatives designated as cash flow hedges as of December 31, 2013 and 2012.

 

Notionals		Balance as of 12.31.13								Balance as of 12.31.12
		Cap				Swap				Cap				Swap
Up to 1 year		$	9,178			$	25,303			$	5,006			$	124,987
Between 1 and 2 years			9,581				29,840				7,473				22,530
Between 2 and 3 years			10,378				36,839				7,987				24,583
Subsequent years			231,694				682,384				203,095				751,581
Total		$	260,831			$	774,366			$	223,561			$	923,681

The table below shows a breakdown of the maturity of the fair values of interest rate derivatives designated as cash flow hedges as of December 31, 2013 and 2012. The net position of the fair value of caps and swaps for each year end reconciles with the net position of derivative assets and derivative liabilities in the combined statement of financial position:

 

Fair value		Balance as of 12.31.13								Balance as of 12.31.12
		Cap				Swap				Cap				Swap
Up to 1 year		$	290			$	(4,537	)		$	56			$	(20,145	)
Between 1 and 2 years			310				(4,236	)			187				(16,137	)
Between 2 and 3 years			334				(3,940	)			200				(14,121	)
Subsequent years			10,799				(29,619	)			5,161				(84,270	)
Total		$	11,733			$	(42,332	)		$	5,604			$	(134,673	)

The net amount of the fair value of interest rate derivatives designated as cash flow hedges transferred to the combined income statement is a loss of $27,513 thousand (loss of $5,916 thousand in 2012). The amount of 2013 includes $8,785 thousand which corresponds to a one-time loss caused by the transfer to the income statement of the entire accumulated amount in equity as the hedged financing agreement was cancelled and replaced by a new financing. Additionally, the net amount of the time value component of the cash flow derivatives fair value recognized in the combined income statement for the years 2013 and 2012 has been a gain of $513 thousand and a loss of $1,007 thousand respectively.

The after-tax losses accumulated in equity in connection with derivatives designated as cash flow hedges at the years ended December 31, 2013 and 2012, amount to $36,600 thousand and $103,547 thousand respectively.

Note 10.- Related parties

During the normal course of business, the Company has conducted operations with related parties (Abengoa´s companies), mainly through loan contracts and advisory services. The transactions were completed at market rates.

 

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Services agreements

Certain combined entities have entered into one-year contractual arrangements with Abengoa from which the Company receives certain administrative services. Such services include general services related to supporting functions such as financing, human resources management, and administration. The fee incurred by the operating companies is based on anticipated annual sales.

In addition, other operating expenses include an allocation of certain general and administrative services provided by Abengoa. Allocated costs include general and administrative costs deemed allocable to the Company. Measurement of allocated costs is based principally on time devoted to the Company by employees of Abengoa. The Company believes that including the allocated costs, the combined statements of operations include a reasonable estimate of actual costs incurred to operate the business.

Furthermore, some of the entities included in these combined financial statements receive engineering, procurement, construction operation and maintenance services from related parties for those concessions which are still under construction.

Credit agreements

Abengoa maintains a pooled central treasury account in which all of its subsidiaries deposit excess funds and may borrow funds from as needed. Under this arrangement, the combined entities could borrow funds from Abengoa. Borrowings under this credit arrangement have borne interest at 10.05% and 8.96% in 2013 and 2012 respectively.The contracts are long terms as agreed between the parties.

In addition, some entities included in the Company have incurred in long-term subordinated debt with related parties.

Details of balances with related parties as of December 31, 2013 and 2012 are as follows:

 

		As of December 31,
		2013				2012
Trade payables (current)		$	25,077			$	55,558
Total current payables with related parties		$	25,077			$	55,558
Trade payables (non-current)			5,107				3,343
Credit payables (non-current)			487,427				219,603
Total non-current payables with related parties		$	492,534			$	222,946

The operations carried out by entities included in these combined financial statements with Abengoa and with subsidiaries of Abengoa not included in the combined group during 2013 and 2012 have been as follows:

 

		Year ended December 31,
		2013				2012
Sales		$	11,925			$	5,089
Construction costs			(364,715	)			(558,620	)
Services rendered			2,804				3,527
Services received			(24,403	)			(8,742	)
Purchases			(2,669	)			(177	)
Financial income			468				575
Financial expenses			(11,209	)			(4,525	)

Services include operation and maintenance services received by some plants, the fee incurred by some operating under the services agreement with Abengoa, and the allocation of general and administrative services explained above. Sales include mainly sale of energy by Spanish CSP plants.

 

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Construction costs include construction work subcontracted to Abengoa for the construction of the assets, which is recorded in these combined financial statements due to the fact that contracted concessional assets are included in the combined financial statements during the construction phase, according to IFRIC 12.

Note 11.- Clients and other receivable

Clients and other receivable as of December 31, 2013 and 2012, consist of the following:

 

Item		Balance as of 12.31.13				Balance as of 12.31.12
Trade receivables		$	26,649			$	11,194
Tax receivables			61,888				81,595
Other debtors			9,060				13,288
Total		$	97,597			$	106,077

As of December 31, 2013 and 2012, the fair value of clients and other receivable accounts does not differ significantly from its carrying value.

Trade receivables according to foreign currency as of December 31, 2013 and 2012, are as follows:

 

Currency		Balance as of 12.31.13				Balance as of 12.31.12
Euro		$	5,409			$	7,369
Peruvian Sol			—				3,825
Total		$	5,409			$	11,194

The following table shows the maturity of Trade receivables as of December 31, 2013 and 2012:

 

Maturity		Balance as of 12.31.13				Balance as of 12.31.12
Up to 3 months		$	26,649			$	11,162
Between 3 and 6 months			—				32
Total		$	26,649			$	11,194

Note 12.- Cash and cash equivalents

The following table shows the detail of Cash and cash equivalents as of December 31, 2013 and 2012:

 

Concept		Balance as of 12.31.13				Balance as of 12.31.12
Cash at bank and on hand		$	351,042			$	88,535
Bank deposits			6,622				8,964
Total		$	357,664			$	97,499

The following breakdown shows the main currencies in which cash and cash equivalent balances are denominated:

 

Currency		Balance as of 12.31.13				Balance as of 12.31.12
U.S. dollar		$	289,172			$	61,448
Euro			64,685				32,994
Peruvian sol			291				2,301
Others			3,516				756
Total		$	357,664			$	97,499

 

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Note 13.- Non-recourse financing (project financing)

The main purpose of the Company is the long-term ownership and management of contracted concessional assets, such as renewable energy, conventional power and electric transmission line assets, which are financed through non-recourse project finance. This note shows the non-recourse financing linked to the contracted concessional assets included in note 6 of these combined financial statements.

Non-recourse financing is generally used to finance our contracted assets, exclusively using as guarantee the assets and cash flows of the company or group of companies carrying out the activities financed. In most of the cases, the assets and/or contracts are set up as guarantee to ensure the repayment of the related financing.

Compared with corporate financing, non-recourse financing has certain key advantages, including a greater leverage period permitted and a clearly defined risk profile.

The movements for 2013 and 2012 of non-recourse financing have been as follows:

 

		Non-recourse financing - long term				Non-recourse financing - short term				Total
Balance as of January 1, 2013		$	1,320,042			$	48,867			$	1,368,909
Increases			1,047,099				92,572				1,139,671
Decreases (reimbursement)			(589,203	)			(78,581	)			(667,784	)
Currency translation differences			17,445				728				18,173
Reclassifications			399,254				(399,254	)			—
Changes in the scope of the combined financial statements (note 5)			647,701				387,980				1,035,681
Balance as of December 31, 2013		$	2,842,338			$	52,312			$	2,894,650

During 2013, the increase in non-recourse financing was mainly due to drawings in connection with the construction of electric transmission lines in Peru and Chile ($220 million) and with the construction of ACT ($735 million). In addition, non-recourse financing increased due to the full consolidation of Arizona Solar One resulting from the business combination of the plant in October 2013 (see note 5).

A decrease also occurred mainly due to the cancellation of previous debt by ACT, with the new financing obtained as indicated above ($501 million).

 

		Non-recourse financing - long term				Non-recourse financing - short term				Total
Balance as of January 1, 2012		$	1,003,239			$	78,674			$	1,081,913
Increases			338,830				720				339,550
Decreases (reimbursement)			(9,396	)			(52,224	)			(61,620	)
Currency translation differences			8,714				352				9,066
Reclassifications			(21,345	)			21,345				—
Balance as of December 31, 2012		$	1,320,042			$	48,867			$	1,368,909

The increase in 2012 was mainly due to drawings in connection with the construction of Solaben 2 and Solaben 3 for $110 million, to the construction of ATN and ATS for $121 million, and ACT in Mexico for $60 million.

Within cash and cash equivalent and financial receivables (current), there are debt service reserve accounts in the amount of $70 million relating to project finance as of December 31, 2013, ($15 million as of December 31, 2012).

 

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The repayment schedule for non-recourse project financing, at the end of 2013 is as follows and is consistent with the projected cash flows of the related projects.

 

2014		2015		2016		2017		2018		Subsequent years		Total
52,312		166,821		86,710		92,190		340,518		2,156,099		2,894,650

In September 2013, ATN, Abengoa Transmision Norte, S.A. issued a total of US $110 million of ordinary bonds. The main use of proceeds was the repayment of the debt this company had with the BCP (Banco de Credito del Peru). The bonds bear fixed interest payable quarterly. From the total amount, $15 million mature in 2018, $50 million mature in 2028 (with a grace period of 5 years) and $45 million mature in 2039 (with a grace period of 15 years).

Non-recourse financing projects entered into in 2013 and 2012 (in millions of U.S. dollars) are as follows:

 

Project		Year				Country				Amount committed				Amount drawn
Abengoa Transmision Norte, S.A. (ATN)			2013				Peru			$	110			$	110
Abengoa Cogeneracion Tabasco, S. de R.L. de C.V. (ACT)			2013				Mexico				660				660
Total year 2013										$	770			$	770
Quadra I			2012				Chile			$	40				—
Quadra II			2012				Chile				34				—
Abengoa Transmision Norte, S.A. (ATN)			2012				Peru				90				84
Total year 2012										$	164			$	84

Current and non-current loans with credit entities include amounts in foreign currencies for a total of $452,997 thousand ($468,369 thousand in 2012).

The equivalent in U.S. dollars of the most significant foreign-currency-denominated debts held by the Company is as follows:

 

Currency		Balance as of 12.31.13				Balance as of 12.31.12
Euro		$	446,436			$	462,559
Chilean peso			6,561				5,810
Total		$	452,997			$	468,369

All of the Company’s financing agreements have a carrying amount close to its fair value.

Note 14.- Grants and other liabilities

 

Concept		Balances as of 12.31.13				Balances as of 12.31.12
Grants		$	416,264			$	—
Long-term trade payables			234,639				129,217
Grants and other non-current liabilities		$	650,903			$	129,217

As of December 31, 2013, the amount recorded in Grants corresponds mainly to loans with interest rates below market rates. Loans with the Federal Financing Bank guaranteed by the Department of Energy related to the Solana project bear interest at a rate below market rates for these types of projects and terms. The difference between proceeds received from these loans and its fair value, “Grants” is subsequently recorded in “Other operating income” starting at the entry into operation of the plant.

 

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The increase in Long-term trade payables was primarily due to the investment from Liberty Interactive Corporation (‘Liberty’) made on October 2, 2013 for an amount of USD 300 million. The investment was made in class A shares of Arizona Solar Holding, the holding of Solana CSP plant in the United States. Such investment was made in a tax equity partnership which permits the partners to have certain tax benefits such as accelerated depreciation and Investment Tax Credits (ITC).

According to the stipulations of IAS 32 and in spite of the fact that the investment of Liberty is in shares, it does not qualify as equity and has been classified as a liability as of December 31, 2013, the non-current portion of the liability is recorded in Grants and other liabilities for an amount of $ 235 million and its current portion is recorded in other current liabilities for the remaining amount. This liability has been initially valued at fair value, calculated as the present value of expected cash-flows during the useful life of the concession, and will be measured at amortized cost according with the effective interest method.

The control and management of the CSP plant is a responsibility of Abengoa and the plant is fully consolidated in these combined financial statements.

As of December 31, 2013, the fair value of this financial liability is close to its carrying amount.

Note 15.- Trade payables and other current liabilities

Trade payable and other current liabilities as of December 31, 2013 and 2012 are as follows:

 

Item		Balance as of 12.31.13				Balance as of 12.31.12
Trade suppliers		$	101,409			$	111,781
Credits for services			18,484				7,745
Down payments from clients			4,711				4,248
Remunerations payable			144				124
Suppliers of intangible assets current			308				51,131
Other accounts payable			78,957				11,019
Total		$	204,013			$	186,048

Nominal values of Trade payables and other current liabilities are considered to approximately equal to fair values and the effect of discounting them is not significant.

The table above includes amounts payable of $67 million at December 31, 2013, ($51 million in 2012) being ‘Confirming without recourse’ relating to various agreements entered into with a number of financial entities in which the Company receives ‘confirming’ services in connection with cash advances from trade receivables. There are linked cash and cash equivalents for an amount of $67 million at December 31, 2013, ($51 million in 2012 classified under the financial accounts receivable) over the abovementioned cash payments. Other account payable line includes the amount of $65 million related to the short term portion of Liberty´s investment (see note 14).

Note 16.- Income Tax

All the companies included in the Company file income taxes according to the tax regulations in force in each country on an individual basis or under consolidation tax regulations.

The combined income tax has been calculated as an aggregation of income tax expenses of each individual company. In order to calculate the taxable income of the combined entities individually, the accounting profit is adjusted for temporary and permanent differences, recording the corresponding deferred tax assets and liabilities. At each combined income statement date, a current tax asset or liability is recorded, representing income taxes

 

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currently refundable or payable. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial statement and income tax purposes, as determined under enacted tax laws and rates.

Income tax payable is the result of applying the applicable tax rate in force to each tax-paying entity, in accordance with the tax laws in force in the country in which the entity is registered. Additionally, tax deductions and credits are available to certain entities, primarily relating to inter-company trades and tax treaties between various countries to prevent double taxation.

As of December 31, 2013 and 2012, the analysis of deferred tax assets and deferred tax liabilities is as follows:

 

Concept		Balance as of 12.31.13				Balance as of 12.31.12
Tax credits for tax loss carryforwards		$	24,999			$	3,720
Tax credits for deductions pending application			—				1,712
Temporary differences derivatives financial instruments			23,353				50,377
Other			4,432				4,433
Total deferred tax assets		$	52,784			$	60,242

 

Concept		Balance as of 12.31.13				Balance as of 12.31.12
Temporary differences tax amortization		$	19,048			$	14,046
Temporary differences derivatives financial instruments			195				—
Other temporary differences			2,596				1,312
Total deferred tax liabilities		$	21,839			$	15,358

Most of the tax credits for net operating loss carryforwards correspond to Peru ($11 million) and ACT ($11 million).

In relation to tax loss carryforwards and deductions pending to be used recorded as deferred tax assets, the entities evaluate its recoverability projecting forecasted taxable income for the upcoming years and taking into account their tax planning strategy. Deferred tax liabilities reversals are also considered in these projections, as well as any limitation established by tax regulations in force in each tax jurisdiction.

The movements in deferred tax assets and liabilities during the years ended December 31, 2013 and 2012, were as follows:

 

Deferred tax assets		Amount
As of January 1, 2012		$	44,115
Increase/decrease through the combined income statement			6,529
Increase/decrease through other combined comprehensive income (equity)			9,214
Other movements			384
As of December 31, 2012		$	60,242
Increase/decrease through the combined income statement			17,474
Increase/decrease through other combined comprehensive income (equity)			(26,715	)
Other movements			1,783
As of December 31, 2013		$	52,784

 

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Deferred tax liabilities		Amount
As of January 1, 2012		$	4,652
Increase/decrease through the combined income statement			10,486
Other movements			220
As of December 31, 2012		$	15,358
Increase/decrease through the combined income statement			5,007
Increase/decrease through other comprehensive income (equity)			1,581
Other movements			(107	)
As of December 31, 2013		$	21,839

Details regarding income tax for the years ended December 31, 2013 and 2012, are as follows:

 

Item		For the year ended 12.31.13				For the year ended 12.31.12
Current tax		$	(705	)		$	(64	)
Deferred tax			12,467				(3,957	)
Total income tax benefit/(expense)		$	11,762			$	(4,021	)

The reconciliation between the theoretical income tax resulting from applying an average statutory tax rate to income before income tax and the actual income tax expense recognized in the combined income statements for the years ended December 31, 2013 and 2012, are as follows:

 

Concept		For the year ended 12.31.13				For the year ended 12.31.12
Combined profit before taxes		$	(13,620	)		$	4,162
Regulatory tax rate			30	%			30	%
Corporate income tax at regulatory tax rate		$	4,086			$	(1,249	)
Income tax of associates, net			4				(121	)
Differences in foreign tax rates			340				(88	)
Permanent differences			16,062				(3,882	)
Incentives, deductions, and tax losses carryforwards			339				(233	)
Other non-taxable income/(expense)			(9,069	)			1,552
Corporate income tax		$	11,762			$	(4,021	)

Permanent differences are mainly due to inflationary effects in ACT (Mexico). The heading ‘Other non-taxable income/(expense)’ corresponds mainly to US disregarded entities for tax purposes.

Note 17.- Third-party guarantees and commitments

Third-party guarantees

At the close of 2013 the overall sum of Bank Bond and Surety Insurance directly deposited by the Company as a guarantee to third parties (clients, financial entities and other third parties) amounted to $7,118 thousand attributed to operations of technical nature.

 

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Contractual obligations

The following table shows the breakdown of the third-party commitments and contractual obligations as of December 31, 2013 and 2012:

 

2013		Total				2014				2015 and 2016				2017 and 2018				Subsequent
Loans with credit institutions		$	2,786,093			$	49,540			$	247,654			$	426,275			$	2,062,624
Notes and bonds			108,558				2,772				5,877				6,434				93,475
Purchase commitments			1,132,137				48,556				109,654				115,953				857,968
Accrued interest estimate during the useful life of loans			1,318,097				97,431				193,226				189,272				838,168

 

2012		Total				2013				2014 and 2015				2016 and 2017				Subsequent
Loans with credit institutions		$	1,368,909			$	48,868			$	134,870			$	106,395			$	1,078,776
Purchase commitments			361,982				89,026				26,413				29,687				216,856
Accrued interest estimate during the useful life of loans			925,106				58,421				169,642				189,882				507,161

Note 18.- Other operating income and expenses

The table below shows the detail of Other Operating Income and Expenses for the years ended December 31, 2013 and 2012:

 

Other operating income		For the year ended 12.31.13				For the year ended 12.31.12
Grants		$	10,118			$	—
Income from various services			4,811				1,752
Income from subcontracted construction services for our assets and concessions			364,715				558,620
Total		$	379,644			$	560,372

 

Other operating expenses		For the year ended 12.31.13				For the year ended 12.31.12
Leases and fees		$	(1,850	)		$	(405	)
Repairs and maintenance			(12,753	)			(876	)
Independent professional services			(22,579	)			(9,632	)
Transportation			(437	)			(191	)
Supplies			(3,322	)			(651	)
Other external services			(5,479	)			(1,763	)
Duties			(6,605	)			(437	)
Other expenses			(3,165	)			(935	)
Constructions costs			(364,715	)			(558,620	)
Total		$	(420,905	)		$	(573,510	)

Income from subcontracted construction services for our assets and concessions corresponds to income resulting from the construction of the contracted concessional assets. Entities included in these combined financial statements have signed with the grantor of the concession contracts for the construction, operation and maintenance and they subcontract the construction of the contracted assets to Abengoa. Given that these projects are included within the scope of IFRIC 12, the Company has recorded income to the construction in the combined income statement. Construction works were more intense during the year 2012, mainly due to costs incurred in construction of ACT, which entered into operation in 2013 and the construction of ATS, which was close to entry into operation in 2012. As a result income from construction decreased in 2013 with respect to 2012.

 

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Other operating expenses include an allocation of certain general and administrative services provided by Abengoa. The Company believes that by including the allocated costs, the combined income statement includes a reasonable estimate of actual costs incurred to operate the business. However, such expenses may not be indicative of the actual level of expense that would have been incurred by the Predecessor if it had operated as an independent, publicly-traded company during the periods prior to the offering or of the costs expected to be incurred in the future.

Construction services are subcontracted to Abengoa and recorded in other operating expenses, Construction costs and their decrease has caused the decrease of other operating expenses in 2013 when compared with the previous year. This decrease has been partially offset by the increase in costs related to the entry into operation of Solana and ACT, and to a full year of operation of Solaben 2 and 3. Repairs and maintenance in 2013 mainly includes costs related to the maintenance of ACT in Mexico.

For the year ended December 31, 2013, other operating expenses have increased with respect to the same period of the previous year mainly due to the entering into operation of ACT, Solaben 2 and 3 and Solana.

Note 19.- Financial income and expenses

Financial income and expenses

The following table sets forth our financial income and expenses for the years ended December 31, 2013 and 2012:

 

Financial income		For the year ended 12.31.13				For the year ended 12.31.12
Interest income from loans and credits		$	640			$	718
Interest rates benefits derivatives: cash flow hedges			513				—
Total		$	1,153			$	718
Financial expenses		For the year ended 12.31.13				For the year ended 12.31.12
Expenses due to interest:
- Loans from credit entities		$	(78,644	)		$	(53,633	)
- Other debts			(17,113	)			(4,525	)
Interest rates losses derivatives: cash flow hedges			(28,027	)			(5,946	)
Total		$	(123,784	)		$	(64,104	)

Financial expenses increased during the year 2013 primarily due to interest expense from loans and credits associated with projects that have entered into operation during the year (interest expense is capitalized during the construction period) and losses from interest rate derivatives designated as cash flow hedges.

The main non-recourse projects that entered into operation during the year 2013 was ACT in Mexico and Arizona Solar One in North America, On the other hand, losses from interest-rate derivatives designated as cash flow hedges for an amount of $28,027 thousand in 2013 are due to transfers from equity to financial expense when the hedged item is impacting the combined income statement and to a one – time loss of $8,785 thousand caused by the transfer to the income statement of all of the accumulated amount in equity as the hedged financing agreement of ATN was cancelled and replaced.

Losses from interest rates cash flow hedges in 2012 are due to transfers from equity to financial expense and to a decrease in time value of the interest rate options of Solaben 2 and Solaben 3 ($1,008 thousand).

 

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Other net financial income and expenses

The following table sets out ‘Other net financial income and expenses’ in years ended December 31, 2013 and 2012:

 

Other financial income		For the year ended 12.31.13				For the year ended 12.31.12
Other financial income		$	618			$	1,170
Other financial losses			(2,172	)			(1,256	)
Outsourcing of payables			(139	)			(87	)
Total		$	(1,693	)		$	(173	)

‘Other finance losses’ include in previous and current years financial expenses mainly related to financial guarantees and letters of credit, to wire transfers and other bank fees and other minor financial expenses.

Note 20.- Other information

20.1 Restricted Net assets

Certain of our combined entities are restricted from remitting certain funds to us in the form of cash dividends or loans by a variety of regulations, contractual or statutory requirements. These restrictions are related to standard requirements to maintain debt service coverage ratios. Also for certain project finance entities that are in construction, no dividends may be distributed until activity commences or, after construction completion, or payment of the first debt service. At December 31, 2013, the accumulated amount of the restrictions for the whole restricted term of these affiliates was $1,121 million. The company expects in the future to extract cash from the entities and to pay dividends to their shareholders. Taking into account only the companies which are in operation, the accumulated amount of restrictions amounts to $97 million.

The Company performed a test on the restricted net assets of combined subsidiaries in accordance with Securities and Exchange Commission Regulation S-X Rule 4-08 (e) (3) ‘General Notes to Financial Statements’ and rule 5-04 (c) ‘what schedules are to be filed’ and concluded the restricted net assets exceed 25% of the combined net assets of the Company as of December 31, 2013. Therefore the separate condensed financial statements of Abengoa Yield, Ltd. should be presented (see Appendix IV (Schedule I) for details).

20.2 Subsequent events

After the end of the year 2013, following regulatory changes introduced in July 2013 by Royal Decree 9/2013, the Spanish Ministry of Industry, Energy and Tourism submitted to the National Competition and Markets Commission for its consideration a draft of the ministerial order establishing the parameters in which to apply a new remuneration system to electricity-generation facilities using renewable energy sources in Spain, which include Solaben 2 and Solaben 3. This draft represents additional information regarding the new remuneration system. It includes the necessary parameters to estimate the impact of the new regulation on future cash flows of the abovementioned contracted assets, so therefore, we have taken this draft ministerial order into account when preparing these financial statements.

 

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Appendices

Appendix I

Entities included in the Company as subsidiaries as of December 31, 2013

 

Company name		Project name		Registered address		% of nominal share				Business
Abengoa Cogeneracion Tabasco, S.R.L. de C.V.		ACT		Santa Barbara (MX)			100.0				(2	)
Abengoa Solar US Holding Inc.		ABSU		Colorado (US)			100.0				(3	)
Abengoa Transmision Norte, S.A.		ATN		Lima (PE)			100.0				(1	)
Abengoa Yield Ltd		Abengoa Yield		Leeds (UK)			100.0				(3	)
Abengoa Transmision Sur, S.A.		ATS		Lima (PE)			100.0				(1	)
Arizona Solar One Holding, LLC		ASOH		Colorado (US)			100.0				(3	)
Arizona Solar One, LLC		ASO		Colorado (US)			100.0				(3	)
Mojave Solar Holding, LLC		MSH		Delaware (US)			100.0				(3	)
Palmatir, S.A.		Palmatir		Montevideo (UY)			100.0				(3	)
Palmucho, S.A.		Palmucho		Santiago (CL)			100.0				(1	)
Solaben Electricidad Dos, S.A.		Solaben 2		Caceres (ES)			70.0				(3	)
Solaben Electricidad Tres, S.A.		Solaben 3		Caceres (ES)			70.0				(3	)
Transmisora Baquedano, S.A.		Quadra 1		Santiago (CL)			99.9				(1	)
Transmisora Mejillones, S.A.		Quadra 2		Santiago (CL)			99.9				(1	)

 

(1)	Business sector: Electric transmission lines

(2)	Business sector: Conventional power

(3)	Business sector: Renewable energy

The Appendices are an integral part of the notes to the combined financial statements.

 

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Appendices

Appendix I

Entities included in the Company as subsidiaries as of December 31, 2012

 

Company name		Project name		Registered address		% of nominal share				Business
Abengoa Cogeneracion Tabasco, S.R.L. de C.V.		ACT		Santa Barbara (MX)			100.0				(2	)
Abengoa Transmision Norte, S.A.		ATN		Lima (PE)			100.0				(1	)
Abengoa Transmision Sur, S.A.		ATS		Lima (PE)			100.0				(1	)
Arizona Solar One Holding, LLC		ASOH		Colorado (US)			100.0				(3	)
Mojave Solar Holding, LLC		MSH		Delaware (US)			100.0				(3	)
Palmatir, S.A.		Palmatir		Montevideo (UY)			100.0				(3	)
Palmucho, S.A.		Palmucho		Santiago (CL)			100.0				(1	)
Solaben Electricidad Dos, S.A.		Solaben 2		Caceres (ES)			70.0				(3	)
Solaben Electricidad Tres, S.A.		Solaben 3		Caceres (ES)			70.0				(3	)
Transmisora Baquedano, S.A.		Quadra 1		Santiago (CL)			99.9				(1	)
Transmisora Mejillones, S.A.		Quadra 2		Santiago (CL)			99.9				(1	)

 

(1)	Business sector: Electric transmission lines

(2)	Business sector: Conventional power

(3)	Business sector: Renewable energy

The Appendices are an integral part of the notes to the combined financial statements.

 

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Appendices

Appendix II

Investments recorded under the equity method as of December 31, 2013

 

Company name

Project name

Registered address

% of nominal share

Business

Evacuacion Valdecaballeros, S.L.

Valdecaballeros

Caceres (ES)

28.6

(3

)

Mojave Solar, LLC

Mojave

California (US)

100.0

(3

)

Investments recorded under the equity method as of December 31, 2012

 

Company name

Project name

Registered address

% of nominal share

Business

Arizona Solar One, LLC

Solana

Colorado (US)

100.0

(3

)

Evacuacion Valdecaballeros, S.L.

Valdecaballeros

Caceres (ES)

28.6

(3

)

Mojave Solar, LLC

Mojave

California (US)

100.0

(3

)

 

(1)	Business sector: Electric transmission lines

(2)	Business sector: Conventional power

(3)	Business sector: Renewable energy

The Appendices are an integral part of the notes to the combined financial statements.

 

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Appendices		Appendix III-1

Projects subject to the application of IFRIC 12 interpretation based on the concession of

services as of December 31, 2013 and 2012

Description of the Arrangements

Solana

Solana is a 250 MW net (280 MW gross) solar electric generation facility located in Maricopa County, Arizona, approximately 70 miles southwest of Phoenix. Arizona Solar One LLC, or Arizona Solar, owns the Solana project. Solana includes a 22-mile 230kV transmission line and a molten salt thermal energy storage system. The construction of Solana commenced in December 2010 and Solana reached COD on October 9, 2013.

Solana has a 30-year, PPA with Arizona Public Service, or APS, approved by the Arizona Corporation Commission (ACC). The PPA provides for the sale of electricity at a fixed price per MWh with annual increases of 1.84% per year. The PPA includes limitations on the amount and condition of the energy that is received by APS with minimum and maximum thresholds for delivery capacity that must not be breached.

Mojave

Mojave is a 250 MW net (280 MW gross) solar electric generation facility located in San Bernardino County, California, approximately 100 miles northeast of Los Angeles. Abengoa commenced construction of Mojave in September 2011. We expect that the project will reach COD by October 2014. Mojave Solar LLC, or Mojave Solar, owns the Mojave project.

Mojave has a 25-year, PPA with Pacific Gas & Electric Company, or PG&E, approved by the California Public Utilities Commission (CPUC). The PPA will begin on COD. The PPA provides for the sale of electricity at a fixed base price per MWh without any indexation mechanism, including limitations on the amount and condition of the energy that is received by PG&E with minimum and maximum thresholds for delivery capacity that must not be breached.

Palmatir

Palmatir is an on-shore wind farm facility in Uruguay with nominal installed capacity of 50 MW. Palmatir has 25 wind turbines and each turbine has a nominal capacity of 2 MW. UTE (Administracion Nacional de Usinas y Transmisiones Electricas), Uruguay’s state-owned electricity company, has agreed to purchase all energy produced by Palmatir pursuant to a 20-year PPA.

Construction is complete and we expect to reach COD by May 2014. The wind farm is located in Tacuarembo, 170 miles north of the city of Montevideo.

Palmatir signed a PPA with UTE on September 14, 2011 for 100% of the electricity produced, approved by URSEA (Unidad Reguladora de Servicos de Energia y Agua). UTE will pay a fixed-price tariff per MWh under the PPA, which is denominated in U.S. dollars and will be partially adjusted in January of each year according to a formula based on inflation.

Solaben 2 & Solaben 3

The Solaben 2 and Solaben 3 are two 50 MW Concentrating Solar Power facilities and are part of Abengoa’s Extremadura Solar Complex. The Extremadura Solar Complex consists of four Concentrating Solar Power plants (Solaben 1, Solaben 2, Solaben 3 and Solaben 6), and is located in the municipality of Logrosan, Spain. Abengoa commenced construction of Solaben 2 and Solaben 3 in August 2010. Solaben 2 reached COD in June 2012 and Solaben 3 reached COD in October 2012. Solaben Electricidad Dos, S.A., or SE2, owns Solaben 2 and Solaben Electricidad Tres, S.A., or SE3, owns Solaben 3.

 

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Renewable energy plants in Spain, like Solaben 2 and Solaben 3, are regulated by the Government through a series of laws and rulings which guarantee the owners of the plants a reasonable remuneration for their investments. Solaben 2 and Solaben 3 sell the power they produce into the wholesale electricity market, where offer and demand are matched and the pool price is determined, and also receive additional payments from the Comision Nacional de los Mercados y de la Competencia, or CNMC, the Spanish state-owned regulator.

ACT

The ACT plant is a gas-fired cogeneration facility with a rated capacity of approximately 300 MW and between 550 and 800 metric tons per hour of steam. The plant includes a substation and an approximately 52 mile and 115-kilowatt transmission line.

On September 18, 2009, Abengoa Cogeneracion Tabasco entered into the Pemex Conversion Services Agreement, or the Pemex CSA, with Petroleos Mexicanos, or Pemex. Pemex is a state-owned oil and gas company supervised by the Comision Reguladora de Energía (CRE), the Mexican state agency that regulates the energy industry. The Pemex CSA has a term of 20 years from the in-service date and will expire on March 31, 2033.

According to the Pemex CSA, ACT must provide, in exchange for a fixed price with escalation adjustments, services including the supply and transformation of natural gas and water into thermal energy and electricity. Part of the electricity is to be supplied directly to a Pemex facility nearby, allowing the Comision Federal de Electricidad (CFE) to supply less electricity to that facility. Approximately 90% of the electricity must be injected into the Mexican electricity network to be used by retail and industrial end customers of CFE in the region. Pemex is then entitled to receive an equivalent amount of energy in more than 1,000 of their facilities in other parts of the country from CFE, following an adjustment mechanism under the supervision of CFE.

The Pemex CSA is denominated in U.S. dollars. The price is a fixed tariff and will be adjusted annually, part of it according to inflation and part according to a mechanism agreed in the contract that on average over the life of the contract reflects expected inflation. The components of the price structure and yearly adjustment mechanisms were prepared by Pemex and provided to bidders as part of the request for proposal documents.

ATN

Abengoa Transmision Norte, or the ATN Project, in Peru is part of the SGT (Sistema Garantizado de Transmision), which includes all transmission line concessions allocated by a bidding process by the government and is comprised of the following facilities:

 

(i)

the approximately 356 mile, 220kV line from Carhuamayo-Paragsha-Conococha-Kiman-Ayllu-Cajamarca Norte;

 

(ii)

the 4.3 mile, 138kV link between the existing Huallanca substation and Kiman Ayllu substations;

 

(iii)

the 1.9 mile, 138kV link between the 138kV Carhuamayo substation and the 220kV Carhuamayo substation;

 

(iv)

the new Conococha and Kiman Ayllu substations; and

 

(v)

the expansion of the Cajamarca Norte, 220kV Carhuamayo, 138kV Carhuamayo and 220kV Paragsha substations.

Pursuant to the initial concession agreement, the Ministry of Energy, on behalf of the Peruvian Government, granted ATN a concession to construct, develop, own, operate and maintain the ATN Project. The initial concession agreement became effective on May 22, 2008 and will expire 30 years after COD of the first tranche of the line, which took place in January 2011. ATN is obliged to provide the service of transmission of electric energy through the operation and maintenance of the electric transmission line, according to the terms of the contract and the applicable law.

The laws and regulations of Peru establish the key parameters of the concession contract, the price indexation mechanism, the rights and obligations of the operator and the procedures that have to be followed in order to fix the applicable tariff, which occurs through a regulated bidding process. Once the bidding process is complete and

 

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the operator is granted the concession, the pricing of the power transmission service is established in the concession agreement. ATN has a 30-year concession agreement with a fixed-price tariff base denominated in U.S. dollars that is adjusted annually after COD of each line, in accordance with the U.S. Finished Goods Less Food and Energy Index published by the U.S. Department of Labor.

ATS

The Abengoa Transmision Sur, or ATS Project, in Peru is part of the Guaranteed Transmission System, or (Sistema Garantizado de Transmisión) which includes all transmission line concessions allocated by a bidding process by the government, and is comprised of:

 

(i)

one 500kV electric transmission line and two short 220kV electric transmission lines, which are linked to existing substations;

 

(ii)

three new 500kV substations; and

 

(iii)

three existing substations (two existing 220kV substations and one existing 550/220kV substation), through the development of new transformers, line reactors, series reactive compensation and shunt reactions in some substations.

Pursuant to the initial concession agreement, the Ministry of Energy, on behalf of the Peruvian Government, granted ATS a concession to construct, develop, own, operate and maintain the ATS Project. The initial concession agreement became effective on July 22, 2010 and will expire 30 years after COD, which took place in January 2014. ATS is obliged to provide the service of transmission of electric energy through the operation and maintenance of the electric transmission line, according to the terms of the contract and the applicable law.

The laws and regulations of Peru establish the key parameters of the concession contract, the price indexation mechanism, the rights and obligations of the operator and the procedure that has to be followed in order to fix the applicable tariff, which occurs through a regulated bidding process. Once the bidding process is complete and the operator is granted the concession, the pricing of the power transmission service is established in the concession agreement. ATS has a 30-year concession agreement with fixed-price tariff base denominated in U.S. dollars that is adjusted annually after COD of each line, in accordance with the U.S. Finished Goods Less Food and Energy Index published by the U.S. Department of Labor.

Quadra 1 & Quadra 2

Transmisora Mejillones, or Quadra 1, is a 49-mile transmission line project and Tranmisora Baquedano, or Quadra 2, is a 32-mile transmission line project, each connected to the Sierra Gorda substations.

Both projects have concession agreements with Sierra Gorda SCM. The agreements are denominated in U.S. dollars and are indexed mainly to CPI. The concession agreements each have a 21-year term that began on COD, which took place in April 2014 and March 2014 for Quadra 1 and Quadra 2, respectively.

Quadra 1 and Quadra 2 belong to the Northern Interconnected System (SING), one of the two interconnected systems into which the Chilean electricity market is divided and structured for both technical and regulatory purposes.

As part of the SING, Quadra 1 and Quadra 2 and the service they provide are regulated by several regulatory bodies, in particular: the Superintendent’s office of Electricity and Fuels (Superintendencia de Electricidad y Combustibles, SEC), the Economic Local Dispatch Center (Centro de Despacho Economico de Cargas, CDEC), the National Board of Energy (Comision Nacional de Energia, CNE) and the National Environmental Board (Comision Nacional de Medio Ambiente, CONAMA) and other environmental regulatory bodies.

 

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In all these concession arrangements, the operator has all the rights necessary to manage, operate and maintain the assets and the obligation to provide the services defined above, which are clearly defined in each concession contract and in the applicable regulations in each country.

The Appendices are an integral part of the notes to the combined financial statements.

 

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Appendices

Appendix III-2

Projects subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 2013

 

Project name

Country

Status(1)

% of Nominal Share(2)

Period of Concession(5)(6)

Offtaker(9)

Financial/ Intangible(3)

Assets/ Investment

Accumulated Amortization

Construction Revenue(4)

Operating Profit/(Loss)

Arrangement Terms (price)

Description of the Arrangement

Renewable energy:

Solana

USA

(O)

100.0

30 Years

APS

(I

)

2,058,884

(16,297

)

—

(2,580

)

Fixed price per MWh with annual increases of 1.84% per year

30-year PPA with APS regulated by ACC

Mojave

USA

(C)

100.0

25 Years

PG&E

N/A(8)

N/A(8)

N/A(8)

N/A(8)

N/A(8)

Fixed price per MWh without any indexation mechanism

25-year PPA with PG&E regulated by CPUC and CAEC

Palmatir

Uruguay

(C)

100.0

20 Years

UTE, Uruguay Administration

(I

)

141,119

—

91,297

(477

)

Fixed price per MWh in USD with annual increases based on inflation

20-year PPA with UTE, Uruguay state-owned utility

Solaben 2

Spain

(O)

70.0

25 Years

Kingdom of Spain

(I

)

366,776

(13,426

)

—

11,112

Regulated revenue base(7)

Regulated revenue established by different laws and rulings in Spain

Solaben 3

Spain

(O)

70.0

25 Years

Kingdom of Spain

(I

)

368,800

(17,234

)

—

11,909

Regulated revenue base(7)

Regulated revenue established by different laws and rulings in Spain

Conventional power:

ACT

Mexico

(O)

100.0

20 Years

Pemex

(F

)

635,849

—

96,575

83,278

Fixed price to compensate both investment and O&M costs, established in USD and adjusted annually partially according to inflation and partially according to a mechanism agreed in contract

20-year Services Agreement with Pemex, Mexican oil & gas state-owned company

Electric transmission lines:

ATN

Peru

(O)

100.0

30 Years

Republic of Peru

(I

)

319,939

(27,208

)

—

989

Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index

30-year Concession Agreement with the Peruvian Government

ATS

Peru

(C)

100.0

30 Years

Republic of Peru

(I

)

513,779

—

127,766

(90

)

Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index

30-year Concession Agreement with the Peruvian Government

Quadra 1

Chile

(C)

100.0

21 Years

Sierra Gorda

(F

)

38,480

—

25,545

3,224

Fixed price in USD with annual adjustments indexed mainly to US CPI

21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others

Quadra 2

Chile

(C)

100.0

21 Years

Sierra Gorda

(F

)

41,441

—

23,532

2,912

Fixed price in USD with annual adjustments indexed mainly to US CPI

21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others

 

(1)	In operation (O), Construction (C) as of December 31, 2013.

(2)

Liberty Interactive Corporation agreed to invest $300 million in Class A membership interests in exchange for a share of the dividends and the taxable loss generated by Solana on October 2, 2013. Legally, General Electric held a 15% interest and a preferred equity interest in ACT as of December 31, 2013. From an accounting perspective, this investment is considered as non-recourse debt. Itochu Corporation holds 30% of the economic rights to each of Solaben 2 and Solaben 3.

(3)	Classified as concessional financial asset (F) or as intangible assets (I).

(4)	Same amount as construction costs incurred during the period.

(5)	The infrastructure is used for its entire useful life. There are no obligations to deliver assets at the end of the concession periods, except for ATN and ATS.

(6)	Generally, there are no termination provisions other than customary clauses for situations such as bankruptcy or fraud from the operator, for example.

(7)	Sales to wholesale markets and additional fixed payments established by the Spanish government.

(8)	Recorded under the equity method.

(9)	In each case the offtaker is the grantor

The Appendices are an integral part of the notes to the combined financial statements.

 

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Projects subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 2012

 

Project name

Country

Status(1)

% of Nominal Share(2)

Period of Concession(5)(6)

Offtaker(9)

Financial/ Intangible(3)

Assets/ Investment

Accumulated Amortization

Construction Revenue(4)

Operating Profit/(Loss)

Arrangement Terms (price)

Description of the arrangement

Renewable energy:

Solana

USA

(C)

100.0

25 Years

APS

N/A(8)

N/A(8)

N/A(8)

N/A(8)

N/A(8)

Fixed price per MWh with annual increases of 1.84% per year

30-year PPA with APS regulated by ACC

Mojave

USA

(C)

100.0

25 Years

PG&E

N/A(8)

N/A(8)

N/A(8)

N/A(8)

N/A(8)

Fixed price per MWh without any indexation mechanism

25-year PPA with PG&E regulated by CPUC and CAEC

Palmatir

Uruguay

(C)

100.0

30 Years

UTE, Uruguay Administration

(I

)

49,822

—

48,751

(547

)

Fixed price per MWh in USD with annual increases based on inflation

20-year PPA with UTE, Uruguay state-owned utility

Solaben 2

Spain

(O)

70.0

25 Years

Kingdom of Spain

(I

)

358,963

(2,907

)

90,656

(118

)

Regulated revenue base(7)

Regulated revenue established by different laws and rulings in Spain

Solaben 3

Spain

(O)

70.0

25 Years

Kingdom of Spain

(I

)

358,445

(6,697

)

51,308

7,432

Regulated revenue base(7)

Regulated revenue established by different laws and rulings in Spain

Conventional power:

ACT

Mexico

(C)

100.0

20 Years

Pemex

(F

)

570,198

—

135,768

61,105

Fixed price to compensate both investment and O&M costs, established in USD and adjusted annually partially according to inflation and partially according to a mechanism agreed in contract

20-year Services Agreement with Pemex, Mexican oil & gas state-owned company

Electric transmission lines:

ATN

Peru

(O)

100.0

30 Years

Republic of Peru

(I

)

319,256

(16,486

)

—

708

Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index

30-year Concession Agreement with the Peruvian Government

ATS

Peru

(C)

100.0

20 Years

Republic of Peru

(I

)

389,829

—

201,294

(838

)

Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index

30-year Concession Agreement with the Peruvian Government

Quadra 1

Chile

(C)

100.0

30 Years

Sierra Gorda

(F

)

12,935

—

12,935

—

Fixed price in USD with annual adjustments indexed mainly to US CPI

21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others

Quadra 2

Chile

(C)

100.0

21 Years

Sierra Gorda

(F

)

17,909

—

17,909

—

Fixed price in USD with annual adjustments indexed mainly to US CPI

21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others

 

(1)	In operation (O), Construction (C) as of December 31, 2012.

(2)

Liberty Interactive Corporation agreed to invest $300 million in Class A membership interests in exchange for a share of the dividends and the taxable loss generated by Solana on October 2, 2013. Legally, General Electric holds a 15% interest and a preferred equity interest in ACT. From an accounting perspective, this investment is considered as non-recourse debt. Itochu Corporation holds 30% of the economic rights to each of Solaben 2 and Solaben 3.

(3)	Classified as concessional financial asset (F) or as intangible assets (I).

(4)	Same amount as construction costs incurred during the period.

(5)	The infrastructure is used for its entire useful life. There are no obligations to deliver assets at the end of the concession periods, except for ATN and ATS.

(6)	Generally, there are no termination provisions other than customary clauses for situations such as bankruptcy or fraud from the operator, for example.

(7)	Sales to wholesale markets and additional fixed payments established by the Spanish government.

(8)	Recorded under the equity method.

(9)	In each case the offtaker is the grantor.

The Appendices are an integral part of the notes to the combined financial statements.

 

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Appendices

Appendix IV (Schedule I)

Financial Statements of Abengoa Yield plc

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Abengoa Yield plc (formerly Abengoa Yield Limited)

Leeds, United Kingdom

We have audited the accompanying balance sheet of Abengoa Yield plc (the “Company”, formerly Abengoa Yield Limited) as at 31 December 2013. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such financial statement presents fairly, in all material respects, the financial position of Abengoa Yield plc (formerly Abengoa Yield Limited) as at 31 December 2013, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

/s/ DELOITTE LLP

London, United Kingdom

April 1, 2014

 

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Appendices

Appendix IV (Schedule I)

Abengoa Yield plc (formerly, Abengoa Yield Limited)

Balance sheet as at December 31, 2013

 

		Notes				2013 $
Non-current assets
Loans to parent undertakings			3			$	14
Non-current assets						$	14
Net assets						$	14
Equity
Share capital			4			$	14
Equity attributable to owners of the Company						$	14

The Appendices are an integral part of the notes to the combined financial statements. The notes on pages F-53 to F-54 form part of these financial statements.

 

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Abengoa Yield plc (formerly Abengoa Yield Limited)

Notes to the financial statements

Appendix IV (Schedule I) has been provided pursuant to the requirements of Rule 12-04(a), 5-04-(c) and 3-01(a) of Regulation S-X, of the US Securities and Exchange Commission (SEC) which require condensed financial information as to the financial position, change in financial position, results of operations of a parent company, other comprehensive income statement and cash flow statement as of the same dates and for the same periods for which audited consolidated financial statements have been presented when the restricted net assets of consolidated subsidiaries exceed 25 percent of consolidated net assets as of the end of the most recently completed fiscal year. Certain information and footnote disclosures normally included in financial statements prepared in accordance with International Financial Reporting Standards have been condensed or omitted. The footnote disclosures contain supplemental information only and, as such, these statements should be read in conjunction with the notes to the accompanying consolidated financial statements.

1. General

Abengoa Yield plc (the “Company”) was incorporated on December 17, 2013 under the name Abengoa Yield Limited, with a registered number 8818211 and a registered address of 1 Park Row, Leeds LS1 5AB, United Kingdom. The Company has not engaged in any business or trading activities since its incorporation.

Abengoa Concessions Investments Limited directly holds 100% of the Company’s shares. Abengoa Concessions Investments Limited forms part of a group of companies whose ultimate parent company is Inversión Corporativa IC, S.A.. As at the balance sheet date the Company has only share capital and an intercompany loan receivable from Abengoa Concessions Investments Limited.

2. Significant accounting policies

The financial statement of the Company as at December 31, 2013 was authorized for issue in accordance with a resolution of the Directors on February 25, 2014.

Basis of accounting

The financial statement has been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”).

The financial statement has been prepared on a historical cost basis, in U.S. dollars.

This financial statement represents the Company’s first IFRS financial statements, and accordingly it has been prepared in accordance with International Financial Reporting Standard 1, First-time Adoption of International Financial Reporting Standards. Accordingly, the Company has prepared this financial statement in compliance with IFRS applicable for periods ending on or after 31 December 2013. No comparative information has been prepared as this financial statement is the first the Company has prepared due to its incorporation in December 2013.

Accounting standards amendments

At the date of authorisation of this financial statement, the following Standards and Interpretations which have not been applied in the preparation of this financial statement, were in issue but not yet effective:

 

IFRS 1 (amended)		Severe Hyperinflation and Removal of Fixed Dates for First-time Adopters
IFRS 7 (amended)		Disclosures – Transfers of Financial Assets
IFRS 9		Financial Instruments
IAS 1 (amended)		Presentation of Items of Other Comprehensive Income
IAS 12 (amended)		Deferred Tax: Recovery of Underlying Assets

 

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The Directors are currently evaluating the impact of adoption of these Standards on the financial statements of the Company in future periods.

3. Loans to parent undertakings

Loans to parent undertakings are denominated in U.S. dollars, the Company’s functional currency, and represent financial assets. Financial assets are initially recognized at fair value, including directly attributable transaction costs, and subsequently accounted for at amortised cost.

4. Share Capital

As at December 31, 2013 shareholders’ equity was divided into one hundred (100) registered shares with a par value of €0.10, of one class of ordinary shares which carry no right to fixed income. The shares are issued but unpaid.

The amounts and movements of share capital for the period ended December 31, 2013 is as follows:

 

		Balance as of December 17, 2013				Issue of Share capital				Distribution of results				Results for the period				Balance as of December 31, 2013
Share Capital			—			$	14				—				—			$	14
Total Equity			—			$	14				—				—			$	14

5. Related party transactions

Related party transactions in the period are limited to the issue of shares to Abengoa Concessions Investments Limited as discussed in Note 3.

6. Subsequent Events

On March 19, 2014, Abengoa Yield Limited reregistered as a public limited company under the name Abengoa Yield plc. On March 20, 2014, the Company redenominated its entire issued share capital of 571,000 ordinary shares with a nominal value of €0.10 per share into 571,000 ordinary shares with a nominal value of $0.138 per share. The entire issued share capital of the Company was subsequently consolidated and sub-divided pursuant to Section 618 of the Companies Act 2006, or the Companies Act, to leave the Company with an issued share capital of 787,000 ordinary shares with a nominal value of $0.10 per share.

 

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             Ordinary Shares

 

            Ordinary Shares

 

 

PRELIMINARY PROSPECTUS

                    , 2014

 

 

 

Citigroup				BofA Merrill Lynch

 

 

Until                     , 2014 (25 days after the date of this prospectus), all dealers that buy, sell, or trade our ordinary shares, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealers’ obligation to deliver a prospectus when acting as underwriter and with respect to their unsold allotments or subscriptions.

 

 

 

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

 

Item 6.

Indemnification of Directors and Officers

The registrant’s articles of association provide that, subject to the U.K. Companies Act 2006, every person who is or was at any time a director or other officer (excluding an auditor) of the registrant may be indemnified out of the assets of the registrant against all costs, charges, expenses, losses or liabilities incurred by him in performing his duties or the exercise of his powers or otherwise in relation to or in connection with his duties, powers or office.

The registrant plans to maintain insurance for its directors regarding negligence, fault, breach of trust and breach of duty under the terms allowed by the U.K. Companies Act 2006.

In the underwriting agreement, the underwriters will agree to indemnify, under certain conditions, the registrant, members of the registrant’s board of directors, members of the executive management board and persons who control the registrant within the meaning of the Securities Act, against certain liabilities. See “Item 9. Undertakings” for a description of the Commission’s position regarding such indemnification provisions.

 

Item 7.

Recent Sales of Unregistered Securities

None.

 

Item 8.

Exhibits and Financial Statement Schedules

 

(a)

The following documents are filed as part of this registration statement:

The Exhibit Index attached hereto is incorporated herein by reference.

 

(b)

Financial Statement Schedules

All schedules have been omitted because the information required to be set forth in the schedules is either not applicable or is shown in the financial statements or notes thereto.

 

Item 9.

Undertakings

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreements certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended, or the Securities Act, may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities, other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding, is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless, in the opinion of its counsel, the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question, whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

 

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The undersigned registrant hereby undertakes that:

 

(1)

if the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness, provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

 

(2)

for purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A, and contained in the form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act, as amended, shall be deemed to be part of this registration statement as of the time it was declared effective.

 

(3)

for the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

(4)

for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

 

(i)

any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

 

(ii)

any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

 

(iii)

the portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

 

(iv)

any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form F-1 and has duly caused this Amendment No. 2 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Washington, D.C. on this 13th day of May, 2014.

 

Pursuant to the requirements of the Securities Act of 1933, this Amendment No. 2 to the Registration Statement on Form F-1 has been signed by the following persons in the capacities indicated on May 13, 2014.

 

Signature		Title
* Manuel Sanchez Ortega		Director and Chairman of the Board
* Santiago Seage		Chief Executive Officer and Director (Principal executive officer)
* Eduard Soler		Executive Vice President and Chief Financial Officer (Principal financial officer)
* Marta Jorge		Chief Accounting Officer (Principal accounting officer)
* Maarten Hoogstraate		Director
* Christopher B. Hansmeyer		Authorized Representative in the United States

 

*	The undersigned by signing his name here to, signs and executes this Amendment No. 2 to the Registration Statement pursuant to the Powers of Attorney executed by the above named signatures and filed previously with the Securities and Exchange Commission on April 1, 2014.

 

 

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EXHIBIT INDEX

 

Exhibit Number		Exhibit
1.1*		Form of Underwriting Agreement.
3.1**		Form of Articles of Association.
5.1*		Opinion of Linklaters LLP.
8.1*		Opinion of Linklaters LLP as to certain U.S. federal income taxation matters.
8.2*		Opinion of Linklaters LLP as to certain United Kingdom taxation matters.
10.1**		Form of Right of First Offer Agreement by and between Abengoa Yield plc and Abengoa, S.A.
10.2**		Form of Executive Services Agreement by and between Abengoa Yield plc and Abengoa Concessions, S.L.
10.3**		Form of Support Services Agreement by and between Abengoa Yield plc and Abengoa Concessions, S.L.
10.4**		Form of Financial Support Agreement by and between Abengoa Yield plc and Abengoa, S.A.
10.5**		Form of Trademark License Agreement by and between Abengoa Yield plc and Abengoa, S.A.
10.6**		Form of Deed between Abengoa Yield plc and Abengoa Concessions Investments Limited.
10.7**		Form of Shareholders Agreement by and among Abengoa Construcao Brasil Ltd., Sociedad Inversora Lineas de Brasil S.L., Abengoa Concessions, S.L. and Abengoa Concessoes Brasil Holding, S.A.
10.8**		Operation and Maintenance Agreement between Abengoa Solar Espana, S.A. and Solaben Electricidad Dos, S.A., dated December 10, 2012.
10.9**		Operation and Maintenance Agreement between Abengoa Solar Espana, S.A. and Solaben Electricidad Tres, S.A., dated December 10, 2012.
21.1**		List of Subsidiaries.
23.1		Consent of Deloitte, S.L., independent registered public accounting firm.
23.2		Consent of Deloitte LLP, independent registered public accounting firm.
23.3*		Consent of Linklaters LLP (included in Exhibit 5.1, Exhibit 8.1 and Exhibit 8.2).
24.1**		Powers of Attorney (included on signature page).
99.1**		Consent of Director Nominees.
99.2**		Consent of Director Nominee.

 

*	To be filed by amendment.

**	Previously filed.

 

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the use in this Amendment No. 2 of the Registration Statement on Form F-1 of our report dated February 28, 2014, (which report expresses an unqualified opinion and contains an explanatory paragraph in relation to 1) the basis of preparation of the combined financial statements of Abengoa Yield Limited as a combination of the historical accounts of companies that compose the Abengoa Concessions Businesses that include expense allocations for certain corporate functions historically provided by Abengoa, S.A. which may not be reflective of the actual expense which would have been incurred had the Company operated as a separate entity apart from Abengoa, S.A. and 2) the adoption of IFRS 10 for all years presented in the combined financial statements) with respect to the combined financial statements of Abengoa Yield Limited as of December 31, 2013 and 2012 and for each of the years then ended. We also consent to the reference to us under the heading “Experts” in such Registration Statement.

/s/ Deloitte, S.L.

Seville, Spain

May 13, 2014

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the use in this Amendment No. 2 of the Registration Statement on Form F-1 of our report dated April 1, 2014, relating to the financial statement of Abengoa Yield plc (formerly Abengoa Yield Limited) appearing in the Prospectus, which is a part of such Registration Statement, and to the reference to us under the headings “Experts” in such Prospectus.

/s/ DELOITTE LLP

London, United Kingdom

May 12, 2014