Form 20-F

20-F 1 d875453d20f.htm FORM 20-F Form 20-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20–F

(Mark One)

¨	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

¨	SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report

For the transition period from to .

Commission file number: 001-36487

Abengoa Yield plc

(Exact name of Registrant as specified in its charter)

Not applicable

(Translation of Registrant’s name into English)

England and Wales

(Jurisdiction of incorporation or organization)

Great West House, GW1, 17th floor

Great West Road

Brentford, United Kingdom TW8 9DF

Tel: + 44 207 098 4384

(Address of principal executive offices)

Santiago Seage

Great West House, GW1, 17th floor

Great West Road

Brentford, United Kingdom TW8 9DF

Tel: + 44 207 098 4384

(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act.


Title of each class		Name of each exchange on which registered
Ordinary Shares, nominal value $0.10 per share		NASDAQ Global Select Market

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report: 80,000,000 ordinary shares, nominal value $0.10 per share.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ¨ Yes x No

If this report is an annual or transaction report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. ¨ Yes x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.


Large accelerated filer ¨		Accelerated filer ¨		Non-accelerated filer x

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP ¨

International Financial Reporting Standards as issued

by the International Accounting Standards Board x

Other ¨

If “Other” has been checked in response to the previous question indicate by check mark which financial statement item the registrant has elected to follow. ¨ Item 17 ¨ Item 18

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

ABENGOA YIELD PLC

TABLE OF CONTENTS


CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS		4
CURRENCY PRESENTATION AND DEFINITIONS		5
PRESENTATION OF FINANCIAL INFORMATION		8
PRESENTATION OF INDUSTRY AND MARKET DATA		9
PART I.		11
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS		11
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE		11
ITEM 3. KEY INFORMATION		11
A.	Selected Financial Data	11

B.	Capitalization and Indebtedness	16

C.	Reasons for the Offer and Use of Proceeds	16

D.	Risk Factors	16

ITEM 4. INFORMATION ON THE COMPANY		42
A.	History and Development of the Company	42

B.	Business Overview	43

C.	Organizational Structure	105

D.	Property, Plant and Equipment	105

ITEM 4A. UNRESOLVED STAFF COMMENTS		106
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS		106
A.	Operating Results	106

B.	Liquidity and Capital Resources	126

C.	Research and Development	138

D.	Trend Information	138

E.	Off Balance Sheet Arrangements	138

F.	Tabular Disclosure of Contractual Obligations	138

G.	Safe Harbor	139

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES		139
A.	Directors and Senior Management	139

B.	Compensation	142

C.	Board Practices	143

D.	Employees	144

E.	Share Ownership	145

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS		145
A.	Major Shareholders	145

B.	Related Party Transactions	146

C.	Interests of Experts and Counsel	153


ITEM 8. FINANCIAL INFORMATION		153
A.	Consolidated Statements and other Financial Information	153

B.	Significant Changes	156

ITEM 9. THE OFFER AND LISTING		157
A.	Offering and Listing Details	157

B.	Plan of Distribution	157

C.	Markets	157

D.	Selling Shareholders	157

E.	Dilution	157

F.	Expenses of the Issue	157

ITEM 10. ADDITIONAL INFORMATION.		157
A.	Share Capital	157

B.	Memorandum and Articles of Association	157

C.	Material Contracts	158

D.	Exchange Controls	158

E.	Taxation	158

F.	Dividends and Paying Agents	162

G.	Statement by Experts	162

H.	Documents on Display	163

I.	Subsidiaries Information	163

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		163
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES		165
A.	Debt Securities	165

B.	Warrants and Rights	165

C.	Other Securities	165

D.	American Depositary Shares	165

PART II.		166
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES		166
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS		166
ITEM 15. CONTROLS AND PROCEDURES		166
ITEM 16. [Reserved]		166
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT		166
ITEM 16B. CODE OF ETHICS		166
ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES		166
ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES		168
ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS		168
ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT		168
ITEM 16G. CORPORATE GOVERNANCE		168
ITEM 16H. MINE SAFETY DISCLOSURE		169
PART III.		169
ITEM 17. FINANCIAL STATEMENTS		169


ITEM 18. FINANCIAL STATEMENTS			169
ITEM 19. EXHIBITS			170
SIGNATURE			172
ABENGOA YIELD PLC INDEX TO FINANCIAL STATEMENTS			F-1

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

This annual report 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 annual report, 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 annual report 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 “Item 3.D—Risk Factors” and the description of our segments and business sectors in the section entitled “Item 4.B—Business—Overview” 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:

•

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

•

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

•

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

•

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

•

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;

•

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

•

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;

•

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

•

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

•

New technology or changes in industry standards;

•

Inability to manage exposure to credit, interest rates, foreign currency exchange rates, supply and commodity price risks;

•

Reliance on third-party contractors and suppliers;

•

Risks associated with acquisitions and investments;

•

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;

•

Insufficient insurance coverage and increases in insurance cost;

•

Litigation and other legal proceedings;

•

Reputational risk, including damage to the reputation of Abengoa;

•

Revocation or termination of our concession agreements;

•

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;

•

Variations in market electricity prices;

•

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

•

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

•

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

•

Failure to receive dividends from all project and investments;

•

Variations in meteorological conditions;

•

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

•

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

•

Changes to our relationship with Abengoa;

•

Failure to meet certain covenants under our financing arrangements;

•

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

•

Various other factors, including those factors discussed under “Item 3.D—Risk Factors” and “Item 5.A—Operating Results” 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.

CURRENCY PRESENTATION AND DEFINITIONS

In this annual report, all references to “U.S. dollar” and “$” are to the lawful currency of the United States and all 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.

Definitions

Unless otherwise specified or the context requires otherwise in this annual report:

•

references to “2019 Notes” refer to the 7.000% Senior Notes due 2019 in an aggregate principal amount of $255 million issued on November 17, 2014, as further described in “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—2019 Notes;”

•

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 that are in operation, and any other renewable energy, conventional power, electric transmission and water asset that is expected to generate contracted revenue and that Abengoa has transferred to an investment vehicle that are located 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 expect to evaluate for future acquisition, for which Abengoa will provide us a right of first offer to purchase if offered for sale by Abengoa or an investment vehicle to which Abengoa has transferred them;

•

references to “ACBH” refer to Abengoa Concessoes Brasil Holding S.A., 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 “Annual Consolidated Financial Statements” refer to the audited annual consolidated financial statements as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 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 annual report;

•

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

•

references to “Call Option Agreement” refer to the call option agreement we entered into with Abengoa on December 9, 2014 pursuant to which we have the option, exercisable by us or through any of our subsidiaries during a 10-month period starting on January 22, 2015, to purchase from Abengoa up to $100 million in equity or subordinated debt of additional operational contracted assets at a yield of 12%, as further described in “Item 7.B—Related Party Transactions—Call Option Agreement;”

•

references to “cash available for distribution” refer to the cash distributions received by the Company from its subsidiaries minus all cash expenses of the Company, including debt service and transaction costs;

•

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

•

references to “Credit Facility” refer to the credit facility of up to $125 million dated December 3, 2014 entered into by us, as the borrower, and our subsidiaries Abengoa Concessions Infrastructures, S.L.U., or ACIN, Abengoa Concessions Peru, S.A., or ACP, ACT Holding, S.A. de C.V., or ACTH, Abengoa Solar Holdings USA Inc, or ASHUSA, and Abengoa Solar US Holdings Inc., or ASUSHI, as guarantors, with HSBC Bank plc, as administrative agent, HSBC Corporate Trust Company (UK) Limited, as collateral agent and Banco Santander, S.A., Bank of America, N.A., Citigroup Global Markets Limited, HSBC Bank plc and RBC Capital Markets, as joint lead arrangers and joint bookrunners, as further described in “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—Credit Facility;”

•

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

•

references to “EMEA” refer to Europe, Middle East and Africa;

•

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

•

references to “Exchange Act” refer to the U.S. Securities Exchange Act of 1934, as amended, or any successor statute, and the rules and regulations promulgated by the Commission thereunder;

•

references to “Executive Services Agreement” refer to the agreement we entered into with Abengoa on June 13, 2014 pursuant to which Abengoa has arranged for a team of executives to provide executive management services to us until June 2015;

•

references to the “First Dropdown Assets” refer to (i) a solar power plant in Spain, Solacor 1/2, with a capacity of 100 MW; (ii) a solar power plant in Spain, PS10/20, with a capacity of 31 MW; and (iii) one on-shore wind farm in Uruguay, Cadonal, with a capacity of 50 MW, each as further described in “Item 4.B—Business Overview—First Dropdown Assets;”

•

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—Non-GAAP Financial Measures;”

•

references to the “Governance MOU” refer to the memorandum of understanding we entered into with Abengoa on December 9, 2014 pursuant to which we and Abengoa agreed to work jointly on certain governance related matters, as further described in “Item 7.B—Related Party Transactions—Governance MOU;”;

•

references to “gross capacity” refers 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 annual report;

•

references to “GW” refer to gigawatts;

•

references to “IFRIC 12” refer to International Financial Reporting Interpretations Committee’s Interpretation 12—Service Concessions Arrangements;

•

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

•

reference to “IPO” refer to our initial public offering of ordinary shares in June 2014;

•

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 “M ft3” refer to million cubic feet;

•

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;

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

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

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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;

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references to “PV” refer to photovoltaic;

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references to “ROFO Agreement” refer to the agreement we entered into with Abengoa on June 13, 2014, as amended and restated on December 9, 2014, that provides us a right of first offer to purchase any of the Abengoa ROFO Assets offered for sale by Abengoa or an investment vehicle to which Abengoa has transferred them, as further amended and restated from time to time;

•

references to “RPS” refer to renewable portfolio standards adopted by 29 U.S. 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 respective state from eligible renewable generation resources, such as solar or wind generation facilities, by a specific date;

•

references to the “Second Dropdown Assets” refer to (i) a 25.5% and a 34.17% stake, respectively, in the legal entities holding two water desalination plants in Algeria, Honaine and Skikda, with an aggregate capacity of 10.5 M ft3 per day; (ii) a 40% stake in an 81-mile transmission line in Peru,

ATN2; (iii) usufruct rights over a 29.6% stake in the legal entity holding a solar power asset in Spain, Helioenergy 1/2, with a capacity of 100 MW; and (iv) a 20% stake in the legal entity holding a solar power asset in the United Arab Emirates, Shams, with a capacity of 100 MW, each as further described in “Item 4.B—Business Overview—Our Operations—Water” and “Item 4.B—Business Overview—Second Dropdown Assets;”

•

references to “Support Services Agreement” refer to the agreement we entered into with Abengoa on June 13, 2014, pursuant to which Abengoa and certain of its affiliates provide certain administrative and support services to us and some of our subsidiaries;

•

references to “t” and “tons” are to metric tons (one metric ton being equal to 1,000 kilograms or 2,205 pounds);

•

references to “TWh” refer to terawatt hours;

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references to “UTE” refer to Administracion Nacional de Usinas y Transmisiones Electricas, the Republic of Uruguay’s state-owned electricity company;

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references to “U.K.” refer to the United Kingdom;

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references to “U.S.” or “United States” refer to the United States of America; and

•

references to “we,” “us,” “our” and the “Company” refer to Abengoa Yield plc and its subsidiaries, unless the context otherwise requires.

PRESENTATION OF FINANCIAL INFORMATION

The selected financial information as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 is derived from, and qualified in its entirety by reference to, our Annual Consolidated Financial Statements, which are included elsewhere in this annual report and prepared in accordance with IFRS as issued by the IASB. The selected financial information as of December 31, 2012 is derived from, and qualified in its entirety by reference to the annual combined financial statements as of and for the years ended December 31, 2013 and 2012, which are included in the prospectus filed with the SEC on January 16, 2015 and prepared in accordance with IFRS as issued by the IASB.

On June 18, 2014, we closed our IPO. Prior to the consummation of our IPO, Abengoa contributed, through a series of transactions, which we refer to collectively as the “Asset Transfer,” certain concessional assets and liabilities described in this annual report, certain holding companies and a preferred equity investment in ACBH. For all periods prior to our IPO, the financial information herein represents the combination of the assets that we acquired and was prepared using Abengoa’s historical basis in the assets and liabilities and the term “Abengoa Yield” represents the accounting predecessor, or the combination of the acquired businesses. For all periods subsequent to our IPO, the financial information herein represents our and our subsidiaries’ consolidated financial results.

Certain numerical figures set out in this annual report, 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 annual report 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 “Item 5—Operating and Financial Review and Prospects” are calculated using the numerical data in our Annual Consolidated Financial Statements or the tabular presentation of other data (subject to rounding) contained in this annual report, as applicable, and not using the numerical data in the narrative description thereof.

Non-GAAP Financial Measures

This annual report contains non-GAAP financial measures including Further Adjusted EBITDA.

depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements, and dividends received from our preferred equity investment in ACBH. Further Adjusted EBITDA for the year ended December 31, 2014 includes preferred dividends received from ACBH for the first time during the third and fourth quarters of 2014.

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.

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 Further Adjusted EBITDA does not reflect any cash requirements that would be required for such replacements;

•

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

•

the fact that other companies in our industry may calculate Further Adjusted EBITDA 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.

PRESENTATION OF INDUSTRY AND MARKET DATA

In this annual report, 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 annual report were obtained from internal surveys, market research, governmental and other publicly available 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 annual report, 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 annual report 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 annual report. We have not independently verified the information and cannot guarantee its accuracy.

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.

PART I.

ITEM 1.

IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2.

OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3.

KEY INFORMATION

A.	Selected Financial Data

The following tables present selected consolidated financial and business level information for Abengoa Yield as of and for each of the years ended December 31, 2014, 2013 and 2012.

The selected financial information as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 is derived from, and qualified in its entirety by reference to, our Annual Consolidated Financial Statements, which are included in this annual report and prepared in accordance with IFRS as issued by the IASB. The selected financial information as of December 31, 2012 is derived from, and qualified in its entirety by reference to the annual combined financial statements as of and for the years ended December 31, 2013 and 2012, which are included in the prospectus filed with the SEC on January 16, 2015 and prepared in accordance with IFRS as issued by the IASB. Given that we are an “emerging growth company,” we are not required to present selected financial data in accordance with Item 301 of Regulation S-K for any period prior to the earliest audited period presented in our initial registration statement.

The selected financial information as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 is not intended to be an indicator of our financial condition or results of operations in the future. You should review such selected financial information together with our Annual Consolidated Financial Statements and notes thereto, included elsewhere in this annual report.

The following tables should be read in conjunction with “Item 5—Operating and Financial Review and Prospects” and our Annual Consolidated Financial Statements and related notes included elsewhere in this annual report.

Consolidated income statements for the years ended December 31, 2014, 2013 and 2012


	Year ended December 31,
	2014			2013			2012
	($ in millions)

Revenue		362.7			210.9			107.2
Other operating income		79.9			379.6			560.4
Raw materials and consumables used		(21.3	)		(8.7	)		(4.3	)
Employee benefit expense		(1.7	)		(2.4	)		(1.8	)
Depreciation, amortization and impairment charges		(125.5	)		(46.9	)		(20.2	)
Other operating expenses		(120.8	)		(420.9	)		(573.6	)


Operating profit/(loss)		173.3			111.6			67.7


Financial income		4.9			1.2			0.7
Financial expense		(210.3	)		(123.8	)		(64.1	)
Net exchange differences		2.1			(0.9	)		0.4
Other financial income/(expense), net		5.9			(1.7	)		(0.2	)


Financial expense, net		(197.4	)		(125.2	)		(63.2	)


Share of profit/(loss) of associates carried under the equity method		(0.8	)		—			(0.4	)


Profit/(loss) before income tax		(24.9	)		(13.6	)		4.1


Income tax		(4.4	)		11.8			(4.0	)


Profit/(loss) for the year		(29.3	)		(1.8	)		0.1


Profit/(loss) attributable to non-controlling interest		(2.3	)		(1.6	)		1.2

Profit/(loss) for the year attributable to the parent company		(31.6	)		(3.4	)		1.3

Less Predecessor Loss prior to Initial Public Offering on June 12, 2014		(28.2	)		—			—
Net profit/(loss) attributable to Abengoa Yield plc subsequent to Initial Public Offering		(3.4	)		—			—
Weighted average number of ordinary shares outstanding (thousands)		80,000			—			—
Basis earnings per share attributable to Abengoa Yield (U.S. dollar per share)⁽¹⁾		(0.04	)		—			—
Dividend paid per share⁽²⁾		0.2962			—			—

(1)

Earnings per share has been calculated for the period subsequent to our IPO, considering net profit/(loss) attributable to equity holders of Abengoa Yield generated after our IPO divided by the number of shares outstanding. Basic earnings per share equals diluted earnings per share for the periods presented.

(2)

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 interest expense and reserves for the prudent conduct of our business. “Item 8.A—Consolidated Statements and Other Financial Information—Dividend Policy.” On December 15, 2014, we paid a dividend of $0.2962 per share to shareholders of record as of November 28, 2014, corresponding to the sum of the first quarterly dividend corresponding to the third quarter of 2014 amounting to $0.2592 per share, representing $1.04 on an annualized basis, and the pro-rata dividend corresponding to the days since our IPO on June 12, 2014 until June 30, 2014, amounting to $0.0370 per share. In addition, on February 23, 2015, our board of directors declared a quarterly dividend corresponding to the fourth quarter of 2014 amounting to $0.2592 per share, representing $1.04 on an annualized basis. We expect this dividend to be paid on or about March 16, 2015.

Consolidated statements of financial position as of December 31, 2014, 2013 and 2012


	As of December 31,
	2014		2013		2012
	($ in millions)

Non-current assets:
Contracted concessional assets		6,725.2		4,418.1		2,058.9
Investments carried under the equity method		5.7		387.3		734.1
Financial investments		373.6		28.9		13.7
Deferred tax assets		124.2		52.8		60.2


Total non-current assets		7,228.7		4,887.1		2,866.9


Current assets:
Inventories		22.0		5.2		—
Clients and other receivables		129.7		97.6		106.1
Financial investments		229.4		266.4		127.6
Cash and cash equivalents		354.2		357.7		97.5


Total current assets		735.3		726.9		331.2


Total assets		7,964.0		5,614.0		3,198.1


Total equity		1,839.6		1,287.2		1,139.8


Non-current liabilities:
Long-term corporate debt		376.2		—		—
Long-term project debt		3,491.9		2,842.3		1,320.0
Other liabilities		1,675.3		1,209.5		502.2


Total non-current liabilities		5,543.4		4,051.8		1,822.2


Current liabilities:
Short-term corporate debt		2.3		—		—
Short-term project debt		331.2		52.4		48.9
Other liabilities		247.5		222.6		187.2


Total current liabilities		581.0		275.0		236.1


Equity and total liabilities		7,964.0		5,614.0		3,198.1

Consolidated cash flow statements for the years ended December 31, 2014, 2013 and 2012


	Year ended December 31,
	2014			2013			2012
	($ in millions)
Gross cash flows from operating activities
Profit/(loss) for the year		(29.3	)		(1.8	)		0.1
Adjustments to reconcile after-tax profit to net cash generated by operating activities		290.6			92.4			22.8

Profit for the year adjusted by non-monetary items		261.3			90.6			22.9

Net interest / taxes paid		(149.7	)		(62.4	)		(41.6	)
Variations in working capital		(68.0	)		9.2			66.6

Total net cash flow provided by operating activities		43.6			37.4			47.9

Net cash flows from investing activities
Investments		(122.8	)		(694.6	)		(1,098.7	)
Acquisitions		(222.4	)		—			—

Total net cash flows used in investing activities		(345.2	)		(694.6	)		(1,098.7	)


Net cash flows provided by financing activities		304.4			914.9			1,107.3


Net increase/(decrease) in cash and cash equivalents		2.9			257.7			56.5

Cash, cash equivalents and bank overdrafts at beginning of the year		357.7			97.5			40.2
Translation differences cash or cash equivalents		(6.4	)		2.5			0.8


Cash and cash equivalents at the end of the year		354.2			357.7			97.5

Geography and business sector data

Revenue by geography


	Year ended December 31,
Revenue by geography	2014		2013		2012
	($ in millions)

North America		195.5		114.0		62.3
South America		83.6		25.4		17.0
Europe		83.6		71.5		27.9


Total revenue		362.7		210.9		107.2

Revenue by business sector


	Year ended December 31,
Revenue by business sector	2014		2013		2012
	($ in millions)

Renewable energy		170.7		82.7		27.9
Conventional power		118.8		102.8		62.3
Electric transmission lines		73.2		25.4		17.0


Total revenue		362.7		210.9		107.2

Non-GAAP Financial Data

Further Adjusted EBITDA by geography


	Year ended December 31,
Further Adjusted EBITDA by geography	2014		2013		2012
	($ in millions)

North America		175.4		96.7		61.1
South America		77.2		19.0		10.2
Europe		55.4		42.8		16.6


Further Adjusted EBITDA⁽¹⁾		308.0		158.5		87.9

Further Adjusted EBITDA by business sector


	Year ended December 31,
Further Adjusted EBITDA by business sector	2014		2013		2012
	($ in millions)

Renewable energy		137.8		55.8		16.1
Conventional power		101.9		83.3		61.1
Electric transmission lines		68.3		19.4		10.7


Further Adjusted EBITDA⁽¹⁾		308.0		158.5		87.9

(1)

Further Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest from continued operations, income tax, share of profit/(loss) of associates carried under the equity method, finance expense net, depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements, and dividends received from our preferred equity investment in ACBH. Further Adjusted EBITDA for the year ended December 31, 2014 includes preferred dividends by ACBH for the first time during the third and fourth quarters of 2014. Further Adjusted EBITDA is not a measure of performance under IFRS as issued by the IASB and you should not consider Further 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 Further 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. Further 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. Further Adjusted EBITDA may not be indicative of our historical operating results, nor is it meant to be predictive of potential future results. See “Presentation of Financial Information—Non-GAAP Financial Measures.”

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


	Year ended December 31,
Reconciliation of profit/(loss) for the year to Further Adjusted EBITDA	2014			2013			2012
	($ in millions)

Profit/(loss) for the year attributable to the parent company		(31.6	)		(3.4	)		1.3

Profit/(loss) attributable to non-controlling interest from continued operations		2.3			1.6			(1.2	)

Income tax		4.4			(11.8	)		4.0


	Year ended December 31,
Reconciliation of profit/(loss) for the year to Further Adjusted EBITDA	2014		2013		2012
	($ in millions)

Share of loss/(profit) of associates carried under the equity method		0.8		—		0.4

Financial expenses, net		197.4		125.2		63.2

Operating profit/(loss)		173.3		111.6		67.7


Depreciation, amortization and impairment charges		125.5		46.9		20.2

Dividend from preferred equity investment		9.2		—		—

Further Adjusted EBITDA		308.0		158.5		87.9

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


	Year ended December 31,
Reconciliation of Further Adjusted EBITDA to net cash generated by operating activities	2014			2013			2012
	($ in millions)

Further Adjusted EBITDA		308.0			158.5			87.9

Other cash finance costs and other		(46.7	)		(67.9	)		(65.0	)

Variations in working capital		(68.0	)		9.2			66.6

Income tax (paid)/received		(0.4	)		(0.1	)		(0.2	)

Interests (paid)/received		(149.3	)		(62.3	)		(41.4	)


Net cash generated by operating activities		43.6			37.4			47.9

B.	Capitalization and Indebtedness

Not applicable.

C.	Reasons for the Offer and Use of Proceeds

Not applicable.

D.	Risk Factors

Investing in our securities involves a high degree of risk. You should carefully consider the risks and uncertainties described below, together with the other information contained in this annual report, including our Annual Consolidated Financial Statements and related notes, included elsewhere in this annual report, before making any investment decision. The risks described below may not be the only risks we face. We have only described those risks that we currently consider to be material and there may be additional risks that we do not currently consider to be material or of which we are not currently aware. 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 securities 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 (or, each, a Member State) from the Eurozone, such as Greece, 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. Various European left-wing parties who question the EU’s recent austerity policies are becoming more relevant, adding some political instability to the region.

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.

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 North America (the United States and Mexico), South America (Peru, Chile, Uruguay and Brazil), and Europe (Spain) and also have a minority presence in Africa, and we expect to expand our operations to certain countries in the Middle East, maintaining North America, South America and Europe as our core regions. 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 U.S. dollar-denominated contracts in Algeria, Mexico and Peru 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 ended September 30, 2013. These cuts affected, among others, the United States Department of the Treasury, or U.S. Treasury, program providing for cash grants in lieu of investment tax credits, or ITCs. See “Item 4.B—Regulation—Regulation in the United States—U.S. Federal Income 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.

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

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, borrowings under credit facilities and, if applicable, under our revolving credit line with Abengoa, to fund our acquisitions and potential growth capital expenditures. See “Item 8.A—Consolidated Statements and Other Financial Information—Dividend Policy.” 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 “Item 8.A—Consolidated Statements and Other Financial Information—Dividend Policy—Our Ability to Grow Our Business and Dividend.”

We 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 are no limitations in our articles of association on our ability to issue equity securities, including securities ranking senior to our shares. The issuance of additional debt securities and/or the incurrence of additional bank borrowings or other debt by us or by intermediate subsidiaries or by our project-level subsidiaries to finance our growth strategy could result in increased interest expense and the imposition of additional or more restrictive covenants, which, in turn, may impact the cash available to be distributed 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 operational assets from Abengoa pursuant to the ROFO Agreement and the Call Option 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 energy 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 “Item 4.B—Regulation—Regulation in the United States—U.S. Federal Income 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 certain 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 solar power plants in the United States and the benefits of ITC for new projects might be lower beginning in 2017.

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 or debt 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, debt securities 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 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 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.

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 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. See “Item 4.B—Regulation.” 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:

•

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

•

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

•

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 clean-up 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 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 24 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 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 “Item 5.A—Operating Results—Factors Affecting Our Results of Operations—Interest Rates”). Although most of our long-term contracts are denominated in, indexed or hedged 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, such as Africa and the Middle East, 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.

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, which in some cases may be subsidiaries of Abengoa, 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, including Abengoa and its subsidiaries, 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 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. We will also hold a minority stake in the Second Dropdown Assets when we complete the pending acquisitions and, consequently, we will not have control over some of those assets. 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 may approve acquisitions and investments at any time. This could result in our making acquisitions or investments in assets that are located in different jurisdictions and are different from, and possibly riskier than, those described in this annual report. 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 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 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 “Item 4.B—Business Overview—Legal Proceedings.”

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, poor financial or operating performance, changes in financial condition or otherwise, we could be adversely affected due to our relationship with Abengoa. For example, on November 13 and 14, 2014, Abengoa’s share and bond prices significantly declined, thereby affecting our stock price. Any 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.

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 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 PPA, 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 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 solar power, in 2013 and 2012 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 “Item 4.B—Regulation—Regulation in the United States—U.S. Federal Income 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, particularly if the cost of renewable energy exceeds the cost of generation of energy from other means. 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 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 exchangeable preferred equity investment in ACBH is subject to inherent risks

We own an exchangeable preferred equity investment in ACBH which grants 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. We and the selling shareholder entered into a deed pursuant to which certain subordination measures are implemented to protect our right to receive such preferred dividend in full. Our exchangeable preferred equity investment in ACBH is 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 “Item 3.D—Risk Factors—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 date of this annual report. 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.

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 and may not perform as expected

The construction of Solana, ACT, Quadra 1, Quadra 2, Palmatir, ATS, Mojave and Cadonal was completed during 2013 or 2014. Our expectations regarding the operating performance of Mojave (which reached COD on December 1, 2014 and which we expect will be our largest source of cash available for distribution in the short- and medium-term) and our other 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. Our projections 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.

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.

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 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.

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

Risks Related to Our Relationship with Abengoa

Abengoa is our controlling shareholder and exercises substantial influence over Abengoa Yield and we are highly dependent on Abengoa

Abengoa currently beneficially owns approximately 51.1% of our shares and is entitled to vote a majority of our outstanding shares. As a result of this ownership, Abengoa has a substantial influence on our affairs and its ownership interest and voting power 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, 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 has 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 “Item 7.B—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 the purchasers of our shares or that Abengoa will act in a manner that is in our best interests.

Furthermore, we 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 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.

On January 22, 2015, Abengoa closed an underwritten public offering and sale in the United States of 10,580,000 of our ordinary shares for total proceeds of $327,980,000 (or $31 per share) before underwriting fees and expenses. Abengoa continues to beneficially own a majority of our outstanding shares but, as a result of such offering, reduced its stake in us from approximately 64.3% to 51.1% of our shares. If Abengoa ceases to beneficially own a majority of our outstanding shares, as a result of either future sales of our ordinary shares

or equity offerings by us resulting in dilution of Abengoa’s stake, certain investors might find our shares less attractive. Abengoa has publicly stated its intention to further reduce their stake in us to below 50% by the end of the first half of 2015, with the objective of maintaining a long-term stake in the range of 40-49%.

In addition, a reduction in Abengoa’s shareholding in us to below a majority interest may trigger the requirement to seek waivers, authorizations or approvals from agencies, governments, financing providers, concession contract counterparties or any other relevant contract counterparty. Any failure by Abengoa to secure any required waivers, authorizations or approvals may entitle the lenders or other parties under certain of our project-level financing agreement or other contract counterparties to accelerate our indebtedness or terminate their agreements with us, which would have a material adverse effect on our business, financial conditions, 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 in operation. Although Abengoa has agreed to grant us a right of first offer with respect to certain contracted revenue assets in operation that Abengoa may elect to sell in the future (as described in “Item 7.B—Related Party Transactions—Right of First Offer”), Abengoa is 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 or sell assets to third parties prior to their entry into operation. Furthermore, Abengoa has no obligation to source acquisition opportunities specifically for us. In addition, Abengoa may not be successful in sourcing, financing or developing potential acquisition opportunities. In particular, developing projects requires substantial financial resources and Abengoa may not have access to such resources either from internal funds, borrowings or external partners. Abengoa announced on January 6, 2015 that it has entered into a non-binding agreement with EIG Global Energy Partners with the objective of jointly investing in a new company for the development of the already contracted portfolio of Abengoa’s projects under construction. Failure to enter into definitive documentation and/or closing such transaction or another one of similar nature with a different investor may not allow Abengoa to develop all of its existing new projects and, therefore, may result in potentially fewer acquisition opportunities for us in the future, which could in turn limit our ability to grow our cash available for distribution. There are a number of other 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. Furthermore, Abengoa may offer and sell to third parties assets that are not yet contracted revenue assets without first offering such assets to us. See “Item 3.D—Risk Factors—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.

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

We 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 provide executive management services to us until June 2015. We are currently in the process of transferring this senior management team to us and the Executive Services Agreement will be terminated once this process is completed. See “Item 7.B—Related Party Transactions—Executive Services Agreement.” Our future success will depend on the continued service of these individuals, who are not obligated to remain employed with us or 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 our or 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 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 has a tie-breaking vote, are affiliated with Abengoa. Ten of our senior managers are 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 we are currently in the process of transferring these senior managers to us. Although our directors and executive officers owe fiduciary duties to our shareholders, these shared Abengoa executives have fiduciary and other duties to Abengoa during the period before we directly employ them. In addition, Abengoa and its representatives, agents and affiliates have access to our confidential information. Although some of these persons are 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.

Abengoa is 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 paid by us, 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 acquisition of any Abengoa ROFO Asset) is subject to our related party transaction policy, which requires prior approval of such transaction by a majority of the independent members of our board of directors (as discussed in “Item 7.B—Related Party Transactions—Procedures for Review, Approval and Ratification of Related Party Transactions; Conflicts of Interest”). The existence 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.

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 rely on Abengoa to provide us with executive management until June 2015 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 during that interim period. We are currently in the process of transferring this senior management team to us and the Executive Services Agreement will be terminated once this process is completed. See “Item 7.B—Related Party Transactions—Executive Services Agreement.” 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, significantly affect our ability to run our business successfully and to execute our growth strategy. If we were to lose access to the 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 provides that Abengoa cannot terminate the agreement unilaterally; however, the Support Services Agreement provides 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 the Acquisition of the Second Dropdown Assets

There can be no assurance that the acquisition of Second Dropdown Assets will be consummated on the terms or timetable currently anticipated or at all

On February 2, 2015, pursuant to the ROFO Agreement, we entered into an agreement with Abengoa setting the framework for the acquisition by us of the Second Dropdown Assets for an aggregate purchase price of $142 million. On February 3, 2015, we completed the acquisition of a 25.5% stake in Honaine and a 34.17% stake in Skikda. Simultaneously, we entered into a two-year call and put option agreement with Abengoa by which we have put option rights to require Abengoa to purchase back these assets at the same price paid by us and Abengoa has call option rights to require us to sell back these assets if certain indemnities and guarantees provided by Abengoa related to past circumstances reach a certain threshold.

The acquisition of the 40% equity interest in ATN2, usufruct rights over the 29.6% stake in Helioenergy 1/2 and the 20% equity stake in Shams has not been consummated as of the date of this annual report and there can be no assurance that it will be consummated on the terms or timetable currently anticipated or at all. In order to consummate the acquisition of these assets, we must enter into definitive documentation with Abengoa, which would be on arm’s length basis, and obtain certain approvals in a timely manner, including approvals from financing institutions and, in some cases, from partners in joint ventures. In the case of ATN2, the acquisition is also subject to the beginning of the generation of revenues by the project, unless such conditions are waived by Abengoa and us. If the conditions are not met by June 30, 2015, each party may terminate the agreement.

If we do not agree on definitive documentation with Abengoa, if the relevant waivers or consents are not received, or if ATN2 does not start generating revenues, or they are delayed, the acquisition of the remaining Second Dropdown Assets may not occur as currently envisaged or at all. Failure to close the acquisition of the Second Dropdown Assets could have a material adverse effect on our business, financial condition and results of operations.

The acquisition of the Second Dropdown Assets, if completed for the pending assets, may not achieve its intended results, and we may be unable to successfully integrate the assets and operations acquired

We acquired a 25.5% stake in Honaine and a 34.17% stake in Skikda, and are working to complete the acquisition of a 40% stake in ATN2, a 29.6% stake in Helioenergy 1/2 and a 20% stake in Shams, with the expectation that it will result in various benefits. Achieving the anticipated benefits of the acquisition of the Second Dropdown Assets is subject to a number of uncertainties, including whether the assets acquired can be integrated in an efficient and effective manner.

It is possible that the acquired assets do not perform as expected. Performance of the assets acquired by us is subject to the risks that affect the operations of the rest of our assets. In addition, integration process could

take longer than anticipated and could result in the disruption of each company’s ongoing businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect our ability to achieve the anticipated benefits of the acquisition. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect the combined company’s future business, financial condition, operating results and prospects. See “Item 3.D—Risk Factors—Risks Related to Our Business and the Markets in Which We Operate—We may be adversely affected by risks associated with acquisitions or investments.”

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 December 31, 2014, we had approximately (i) $3,823.1 million of total indebtedness under various project-level debt arrangements and (ii) $378.5 million of total indebtedness under our corporate debt arrangements, which includes the 2019 Notes and our drawdown under the Credit Facility. Additionally, we have a $50 million revolving credit line with Abengoa under which we do not intend to make borrowings in the short-term. 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 operating and financial restrictions and covenants in the indenture governing the 2019 Notes and the credit agreement governing the Credit Facility may adversely affect our ability to finance our future operations or capital needs, to engage in other business activities that may be in our interest and to execute our business strategy as we intend to do so. If we or any of our applicable subsidiaries violate any of these covenants, a default may result, which, if not cured or waived, could result in the acceleration of our debt and could limit the ability of our subsidiaries to make distributions to us or our ability to pay dividends.

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 our long-term best interests. The extent of the restrictions on our subsidiaries’ ability to transfer assets to us through loans, advances or cash dividends without the consent of third parties is significant, requiring us to include condensed financial information regarding Abengoa Yield plc as part of our Annual Consolidated Financial Statements. 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 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, including covenants under our 2019 Notes and the Credit Facility, may entitle the related noteholders or lenders, as applicable, 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 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, Abengoa or other persons 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 “project debt.” As of December 31, 2014, we had $3,823.1 million of outstanding indebtedness under various project-level debt arrangements.

While the lenders under our project debt 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 events of default related to Abengoa’s financial condition and cross-default provisions such that a default under one particular financing arrangement in Abengoa could automatically trigger defaults under some of our financing arrangements or events of default related to the performance by Abengoa of certain technical obligations related to the construction of our assets (i.e., performance guarantees). Certain of such agreements also contain cross-default provisions related to the financing arrangements of other project sponsors unrelated to us. As a result, a significant deterioration in Abengoa’s financial condition, a default under any indebtedness above certain thresholds in Abengoa or such other parties or an event of default related to such technical obligations could result in a substantial loss to us or could otherwise have a material adverse effect on our business, financial condition, results of operation and cash flows.

Any of these events could have a material adverse effect on our financial condition, results of operations or 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 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, the 2019 Notes, the Credit Facility 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 “Item 4.B—Business Overview—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 “Item 8.A—Consolidated Statements and Other Financial Information—Dividend Policy.”

We are a holding company and our only material assets are our interests 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 consist of our interests in our subsidiaries. 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 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.

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

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. 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 of our shares.

In addition, the market price of our shares may fluctuate in the event of 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 or Abengoa and/or speculation in the press or investment community regarding us or Abengoa.

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

In order to finance the growth of our business through future acquisitions, 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 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 any of our previous 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, Abengoa, 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 future sales by Abengoa of such shares in the market, or the perception that these sales could occur. 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. Abengoa has publicly stated its intention to further reduce their stake in us to below 50% by the end of the first half of 2015, with the objective of maintaining a long-term stake in the range of 40-49%.

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 Commission 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 to their purchases and sales of our shares. Moreover, we are not required to file periodic reports and financial statements with the Commission 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.

We will be a “foreign private issuer” so long as we are incorporated outside the United States except if as of the last business day of our most recently completed second quarter more than 50% of our outstanding voting securities are directly or indirectly owned by residents of the United States, and any of the following: (i) a majority of our executive officers or directors are U.S. citizens or residents, (ii) more than 50% of our assets are located in the United States or (iii) our business is principally administered in the United States. If we were to lose our “foreign private issuer” status, as a result of further sales by Abengoa of our shares or otherwise, we would no longer be exempt from certain provisions of the U.S. securities laws described above, we would be required to commence reporting on forms required of U.S. companies, such as Forms l0-K, 10-Q and 8-K, rather than the forms currently available to us, such as Forms 20-F and 6-K, we would be required to prepare our financial statements in U.S. GAAP, rather than IFRS, and we would likely incur increased compliance and other costs, among other consequences, any of which could material adverse effect on our business, financial condition, results of operations and cash flows.

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 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, 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 “Item 10.B—Memorandum and Articles of Association.”

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, 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 net operating loss carryforwards sufficient to offset our taxable income

We expect to generate net operating losses and net operating loss carryforwards (collectively, “NOLs”) 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 10 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 our IPO (which was consummated in June 2014).

While we expect these NOLs 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 NOLs 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, and increased by a certain portion of any “built-in-gains.” The long-term tax-exempt rate for February 2015 is 2.68%. Future sales of our shares by Abengoa, or sales of shares of Abengoa, as well as future issuances by us or Abengoa could contribute to a potential ownership change.

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 “Item 10.E—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 IRC (a “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 was a PFIC for its 2014 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 Abengoa Yield 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 distributions, interest charges on certain taxes treated as deferred, and additional reporting requirements. See “Item 10.E—Taxation—Material U.S. Federal Income Tax Considerations—Passive foreign investment company rules.”

ITEM 4.

INFORMATION ON THE COMPANY

A.	History and Development of the Company

Abengoa, listed on the Madrid and Barcelona Stock Exchange and the NASDAQ Global Select Market under the symbol “ABGB,” 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.

We were incorporated in England and Wales as a private limited company on December 17, 2013 by Abengoa under the name “Abengoa Yield Limited.” On March 19, 2014, we were re-registered as a public limited company, under the name “Abengoa Yield plc.”

We are a dividend growth-oriented company formed to serve as the primary vehicle through which Abengoa owns, manages and acquires renewable energy, conventional power, electric transmission lines and water, and other contracted revenue-generating assets in operation, initially focused on North America (the United States and Mexico), South America (Peru, Chile, Uruguay and Brazil), and Europe (Spain). We also have a minority presence in Africa and we intend to expand to certain countries in the Middle East, maintaining North America, South America and Europe as our core geographies.

On June 12, 2014, we completed our IPO and listed our shares on the NASDAQ Global Select Market under the symbol “ABY.” Prior to the consummation of our IPO, Abengoa transferred to us ten assets representing an initial portfolio 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. The assets in the initial portfolio consisted of:

•

Renewable energy assets include (i) two 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 solar power plants in Spain, Solaben 2 and Solaben 3, with a gross capacity of 50 MW each.

•

Conventional power asset consist of Abengoa Cogeneracion Tabasco, or ACT, a 300 MW cogeneration plant in Mexico.

•

Electric transmission lines in the initial portfolio consist of (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.

Upon our IPO, we 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.”

In September 2014, pursuant to the ROFO Agreement, we agreed to acquire the First Dropdown Assets from Abengoa, which comprise an aggregate of 131 MW of solar power generation and 50 MW of wind power generation. The First Dropwdown Assets consist of (i) a solar power plant in Spain, Solacor 1/2, with a capacity of 100 MW; (ii) a solar power plant in Spain, PS10/20, with a capacity of 31 MW; and (iii) one on-shore wind farm in Uruguay, Cadonal, with a capacity of 50 MW. See “Item 4.B—Business Overview—Our Operations—Renewable Energy” for a description of such assets.

In February 2015, pursuant to the ROFO Agreement, we agreed to acquire the Second Dropdown Assets from Abengoa, which comprise an aggregate of 200 MW of solar power generation, 10.5 M ft3 per day of water desalination and an 81-mile transmission line. The Second Dropdown Assets consist of (i) a 25.5% and a 34.17% stake, respectively, in the legal entities holding two water desalination plants in Algeria, Honaine and Skikda, with an aggregate capacity of 10.5 M ft3 per day; (ii) a 40% stake in an 81-mile transmission line in Peru, ATN2; (iii) usufruct rights over a 29.6% stake in the legal entity holding a solar power asset in Spain, Helioenergy 1/2, with a capacity of 100 MW; and (iv) a 20% stake in the legal entity holding a solar power asset in the United Arab Emirates, Shams, with a capacity of 100 MW. On February 3, 2015, we completed the acquisition of the 25.5% stake in Honaine and the 34.17% stake in Skikda. See “Item 4.B—Business Overview—Our Operations—Water” for a description of such assets. The completion of the acquisition of the 40% stake in ATN2, the 29.6% stake in Helioenergy 1/2 and the 20% stake in Shams is subject to satisfaction of customary conditions, including approvals from financing institutions and, in certain cases, from partners in joint ventures. In the case of ATN2, the acquisition is also subject to the beginning of the generation of revenues by the project, unless such conditions are waived by Abengoa and us. If the conditions are not met by June 30, 2015, each party may terminate the agreement. The total aggregate consideration for the Second Dropdown Assets will be $142 million and will be financed with a portion of the proceeds of the Credit Facility and available cash. See “Item 4.B—Business Overview—Second Dropdown Assets.”

B.	Business Overview

Overview

As of the date of this annual report, we own or have interests in 15 assets, comprising 891 MW of renewable energy generation, 300 MW of conventional power generation, 10.5 M ft3 per day of water desalination and 1,018 miles of electric transmission lines, as well as an exchangeable preferred equity investment in ACBH. Each of the assets we own has a project-finance agreement in place. All of our assets have contracted revenues (regulated revenues in the case of our Spanish assets) with low-risk off-takers and collectively have a weighted average remaining contract life of approximately 24 years as of December 31, 2014.

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, offers us a lower cost of capital than that of a traditional engineering and construction company or independent power producer and provides 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 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 are focused on high-quality, newly-constructed and long-life facilities with creditworthy counterparties that we expect will produce stable, long-term cash flows. 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 Africa, the Middle East and Asia. We refer to the contracted assets subject to the ROFO Agreement as the “Abengoa ROFO Assets.” See “Item 4.B—Business Overview—Our Growth Strategy” and “Item 7.B—Related Party Transactions—Right of First Offer.”

On November 18, 2014, we completed the acquisition of Solacor 1/2 through a 30-year usufruct rights contract over the related shares (which includes the option to purchase such shares for one euro during a four-year term); on December 4, 2014, we completed the acquisition of PS10/20; and on December 29, 2014, we completed the acquisition of Cadonal. Together, these three First Dropdown Assets, which we agreed in September 2014 to acquire from Abengoa pursuant to the ROFO Agreement, comprise an aggregate of 131 MW of solar power generation and 50 MW of wind power generation. See “Item 4.B—Business Overview—Our Operations—Renewable Energy” for a description of such assets. The total aggregate consideration for the First Dropdown Assets was $312 million (which consideration was determined in part by converting the portion of the purchase price of Solacor 1/2 and PS10/20 denominated in euros into U.S. dollars based on the exchange rate on the date on which the payment was made).

Pursuant to our cash dividend policy, we pay a cash dividend each quarter to holders of our shares. Our quarterly dividend for the third quarter of 2014, paid in December 2014, was set at $0.2592 per share, or $1.04 per share on an annualized basis. On February 23, 2015, our board of directors declared a quarterly dividend corresponding to the fourth quarter of 2014 amounting to $0.2592 per share, representing $1.04 on an annualized basis. We expect this dividend to be paid on or about March 16, 2015. See “Item 8.A—Consolidated Statements and Other Financial Information—Dividend Policy.”

Based on the acquisition opportunities available to us, which include the Abengoa ROFO Assets, to the extent offered for sale by Abengoa or any investment vehicle to which Abengoa has transferred them, 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 increase our cash dividends per share over time. Prospective investors should read “Item 5.B—Liquidity and Capital Resources—Cash dividends to investors” and “Item 3.D—Risk Factors,” including the risks and uncertainties related to our forecasted results, acquisition opportunities and growth plan, in their entirety.

Purpose of Abengoa Yield

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.

Current Operations

We own a diversified portfolio of renewable energy, conventional power, electric transmission line and water contracted assets in North America (the United States and Mexico), South America (Peru, Chile, Uruguay and Brazil), Europe (Spain) and Africa (Algeria). We intend to expand to certain countries in the Middle East, maintaining North America, South America and Europe as our core geographies. Our portfolio consists of seven renewable energy assets, a cogeneration facility, several electric transmission lines and minority stakes in two desalination plants, all of which are fully operational. 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 electric transmission lines. All of our assets have contracted revenues (regulated revenues in the case of our Spanish assets) with low-risk off-takers and collectively have a weighted average remaining contract life of approximately 24 years as of December 31, 2014. We expect that the majority of our cash available for distribution over the next four years will be in U.S. dollars, indexed to the U.S. dollar or in euros. We intend to use currency hedging contracts to maintain a ratio of 90% of our cash available for distribution denominated in U.S. dollars. 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.

The following table provides an overview of our current assets (excluding our exchangeable preferred equity investment in ACBH), following completion of the acquisition of Honaine and Skikda, which are part of the Second Dropdown Assets:

Assets

Type

Ownership

Location

Currency⁽¹⁾

Capacity
(Gross)

Status

Off-taker

Counterparty
Credit

Rating⁽²⁾

COD

Contract
Years
Left

Solana

Renewable (Solar)

100

Class B

⁽³⁾

Arizona
(USA)

U.S.
dollars

280 MW

Operational

APS

A-/A3/BBB+

4Q 2013

Mojave

Renewable (Solar)

100

California
(USA)

U.S.
dollars

280 MW

Operational

PG&E

BBB/A3/
BBB+

4Q 2014

Palmatir

Renewable (Wind)

100

Uruguay

U.S.
dollars

50 MW

Operational

UTE

BBB-/
Baa2/
BBB-⁽⁴⁾

2Q 2014

Cadonal

Renewable (Wind)

100

Uruguay

U.S.
dollars

50 MW

Operational

UTE

BBB-/
Baa2/
BBB-⁽⁴⁾

4Q 2014

Solaben 2/3⁽⁵⁾

Renewable (Solar)

%⁽⁶⁾

Spain

Euro

2x50 MW

Operational

Whole-sale market/
Spanish electric system

BBB/
Baa2/
BBB+

2Q 2012 &
4Q 2012

Solacor 1/2⁽⁷⁾

Renewable (Solar)

%⁽⁸⁾

Spain

Euro

100 MW

Operational

Whole-sale market/
Spanish electric system

BBB/
Baa2/
BBB+

2Q 2012 &
4Q 2012

PS10/20⁽⁹⁾

Renewable (Solar)

100

Spain

Euro

31 MW

Operational

Whole-sale market/
Spanish electric system

BBB/
Baa2/
BBB+

1Q 2007 &
2Q 2009

ACT

Conventional
Power

100

Mexico

U.S.
dollars

300 MW

Operational

Pemex

BBB+/
A3/
BBB+

2Q 2013

Assets

Type

Ownership

Location

Currency⁽¹⁾

Capacity
(Gross)

Status

Off-taker

Counterparty
Credit

Rating⁽²⁾

COD

Contract
Years
Left

ATN

Transmission Line

100

Peru

U.S.
dollars

362 Miles

Operational

Peru

BBB+/
A3/
BBB+

1Q 2011

ATS

Transmission Line

100

Peru

U.S.
dollars

569 Miles

Operational

Peru

BBB+/
A3/
BBB+

1Q 2014

Quadra 1

Transmission Line

100

Chile

U.S.
dollars

43 Miles

Operational

Sierra Gorda

N/A

2Q 2014

Quadra 2

Transmission Line

100

Chile

U.S.
dollars

38 Miles

Operational

Sierra Gorda

N/A

1Q 2014

Palmucho

Transmission Line

100

Chile

U.S.
dollars

6 Miles

Operational

Endesa Chile⁽¹⁰⁾

BBB+/
Baa2/
BBB+

4Q 2007

Honaine

Water

25.5

%⁽¹¹⁾

Algeria

U.S.
dollar

7M
ft3/day

Operational

Sonatrach & ADE

N/A

3Q 2012

Skikda

Water

34.17

%⁽¹²⁾

Algeria

U.S.
dollar

3.5M
ft3/day

Operational

Sonatrach & ADE

N/A

1Q 2009

(1)	Certain contracts denominated in U.S. dollars are payable in local currency.

(2)	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.

(3)

On September 30, 2013, Liberty Interactive Corporation agreed to invest $300 million in Class A shares of Arizona Solar Holding, the holding company of the Solana plant, in exchange for a share of the dividends and the taxable loss generated by Solana. See note 1 to our Annual Consolidated Financial Statements.

(4)	Refers to the credit rating of Uruguay, as UTE is unrated.

(5)	Solaben 2 and Solaben 3 are separate special purpose vehicles with separate agreements, but they are treated as a single platform.

(6)	Itochu Corporation, a Japanese trading company, holds 30% of the shares in each of Solaben 2 and Solaben 3. We hold a 30-year right of usufruct over the remaining shares of Solaben 2 and Solaben 3 and a call option to purchase such shares for one euro during a four-year term.

(7)	Solacor 1 and Solacor 2 are separate special purpose vehicles with separate agreements but they are treated as a single platform.

(8)	JGC Corporation, a Japanese engineering company, holds 26% of the shares in each of Solacor 1 and Solacor 2. We hold a 30-year right of usufruct over the remaining shares of Solacor 1 and Solacor 2 and a call option to purchase such shares for one euro during a four-year term.

(9)	PS10 and PS20 are separate special purpose vehicles with separate agreements but they are treated as a single platform.

(10)	Refers to Empresa Nacional de Electricidad, S.A, or Endesa Chile, which is owned by the Enel Group.

(11)	Algerian Energy Company, SPA owns 49% of Honaine and Sadyt owns the remaining 25.5%.

(12)	Algerian Energy Company, SPA owns 49% of Skikda and Sadyt owns the remaining 16.83%.

Our assets and operations are organized into the following four business sectors:

Renewable Energy: Our renewable energy assets include two 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 PPA 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 reached COD on December 1, 2014.

Additionally, we own the following two onshore wind farms in Uruguay: Palmatir and Cadonal, each with a gross capacity of 50 MW. Each wind farm is subject to a 20-year U.S. dollar-denominated PPA with a state-owned utility company in Uruguay. Palmatir reached COD in May 2014 and Cadonal reached COD in December 2014.

Finally, we own the following solar power plants in Spain with a total gross capacity of 231 MW: (i) a 30-year usufruct of the economic and political rights over the shares of Solaben 2/3, in operation since 2012

(with an option to purchase such shares for one euro during a four-year term), (ii) a 30-year usufruct of the economic and political rights over the shares of Solacor 1/2, in operation since 2012 (with an option to purchase such shares for one euro during a four-year term) and (iii) PS10/20, in operation since 2007 and 2009, respectively. All such projects receive market and regulated revenues under the economic 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 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 in January 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 20 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 22 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 electric transmission lines (see “Item 4.B—Business Overview—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 have the right to 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) exchange the preferred equity for ordinary shares of specific project companies owned by ACBH.

Water: Our water assets consist of minority stakes in two desalination plants in Algeria, Honaine and Skikda, with an aggregate capacity of 10.5 M ft3 per day, acquired in February 2015. We intend to further expand our presence in the water sector through the acquisition of water treatment assets and water transportation assets.

Our Business Strategy

Our primary business strategy is to grow 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 stable, long-term 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.

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. In addition, we may also explore additional acquisition opportunities outside of our two main geographies. 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.

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. Our Palmatir facility reached COD in May 2014 and our Cadonal facility reached COD in December 2014. Both Palmatir and Cadonal are expected to generate increased cash flows. In addition, Mojave achieved COD on December 1, 2014, whereby we obtained a new revenue-generating asset that we expect will result in a significant increase to our cash flow generation. See “Item 3.D—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 number of acquisition opportunities that will allow us to achieve accretive growth over the next few years. 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 to the extent Abengoa wishes to sell such assets. 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 cash flow generation by further expanding into water assets. We believe that contracted water assets, including 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. On February 3, 2015, we completed the acquisition of a 25.5% stake in Honaine and a 34.17% stake in Skikda from Abengoa under the ROFO Agreement, two water desalination plants in Algeria with an aggregate capacity of 10.5 M ft3 per day. In addition, the assets we expect Abengoa to offer to us under the ROFO Agreement include other water assets. 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.

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 assets, 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. We expect that Abengoa, as our larger 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, indexed or hedged 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.

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 24 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 U.K. 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 U.K. taxation due to the U.K.’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 10 years due to existing net operating losses, or NOLs, except for ACT in Mexico, where we do not expect to pay significant income taxes until the fifth or sixth year after our IPO (which was consummated in June 2014) once we use existing NOLs. See “Item 3.D—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,” “Item 3.D—Risk Factors—Risks Related to Taxation—Our ability to use U.S. NOLs to offset future income may be limited” and “Item 3.D—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 the jurisdictions in which we operate. See “Item 3.D—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. Our management team has significant and valuable expertise in developing, financing, operating and managing renewable energy, conventional power and electric transmission assets. We believe 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 stable, long-term cash flow generation that will benefit all of our shareholders.

Our relationship and our agreements with Abengoa. We believe our relationship with Abengoa, regardless Abengoa’s expressed intention to further reduce their stake in us to below 50% by the end of the first half of 2015, with the objective of maintaining a long-term stake in the range of 40-49%, 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 us with a significant pipeline of opportunities in our targeted sectors and geographies and has announced that it is analyzing ways to increase its development capabilities and we have amended our ROFO Agreement to take account of this development. Abengoa usually targets an internal rate of return for its projects that is higher than the expected cost of our equity, thus both parties could benefit from the sale of assets by 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 10 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.

•

Abengoa Financing Experience. Over the last 10 years, Abengoa has financed through project debt 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 2,275 renewable and 7,800 conventional 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 M ft3 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 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.

Geographically diverse multi-technology portfolio. 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

Renewable energy

The following table presents our renewable energy assets:

Assets

Type

Location

Capacity

Status

Off-taker

Currency

Counterparty
Credit Rating⁽¹⁾

COD

Contract
Years Left

Solana

Solar

Arizona

280 MW

Operational

APS

U.S. dollars

A-/A3/BBB+

4Q 2013

Mojave

Solar

California

280 MW

Operational

PG&E

U.S. dollars

BBB/A3/
BBB+

4Q 2014

Palmatir

Wind

Uruguay

50 MW

Operational

UTE

U.S. dollars

BBB-/Baa2/
BBB-⁽²⁾

2Q 2014

Cadonal

Wind

Uruguay

50 MW

Operational

UTE

U.S. dollars

BBB-/Baa2/
BBB-⁽²⁾

4Q 2014

Solaben 2/3

Solar

Spain

100 MW

Operational

Whole-sale
market/
Spanish
electric
system

Euro

BBB/Baa2/
BBB+

2Q 2012
& 4Q
2012

Solacor 1/2

Solar

Spain

100 MW

Operational

Whole-sale
market/
Spanish
electric
system

Euro

BBB/Baa2/
BBB+

2Q 2012
& 4Q
2012

PS10/20

Solar

Spain

31 MW

Operational

Whole-sale
market/
Spanish
electric
system

Euro

BBB/Baa2/
BBB+

1Q 2007
& 2Q
2009

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

(2)	Refers to the credit rating of Uruguay, as UTE is unrated.

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 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 13 50-MW parabolics trough facilities in Spain, including Solaben 2/3, 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 US 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 A- from S&P, A3 from Moody’s 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.

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 LLC, 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 and such tranche was fully repaid in April 2014. 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 $950 million as of December 31, 2014. 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 1.20x and the projected debt service coverage ratio for the next four fiscal quarters is at least 1.20x.

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 Consolidated Financial Statements for more information. All figures in this annual report 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 completed construction and reached COD on December 1, 2014. Mojave Solar LLC, or Mojave Solar, owns the Mojave project.

Mojave relies on a conventional parabolic trough 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 off-taker did not require one.

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 began 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 BBB from S&P, A3 from Moody’s and BBB+ from Fitch.

Engineering, Procurement and Construction Agreement. The construction of Mojave was 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 and reached COD on December 1, 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 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 million. 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 preliminary 1603 Cash Grant application for Mojave was filed on September 14, 2012. Since Mojave reached COD in December 2014, a final 1603 Cash Grant application was recently filed on February 5, 2015. See “Item 4.B—Business Overview—Regulation—Regulation in the United States—U.S. Federal Income Tax Incentives and Other Federal Considerations for Renewable Energy Generation Facilities—Section 1603 U.S. Treasury Grant Program.” The principal balance of this tranche was $248 million as of December 31, 2014. 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 $787 million as of December 31, 2014. 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 U.S. Treasury bond with the maturity of that disbursement.

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. Palmatir reached COD in 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 required us to connect Palmatir to UTE’s electrical grid by September 2014. Since Palmatir is connected to the electrical grid, UTE purchases all electricity produced during the 20-year term of the PPA. UTE pays 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/U.S. dollars exchange rate.

UTE is unrated and Uruguay has senior unsecured credit ratings of BBB- from S&P, Baa2 from Moody’s 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.

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, 2014 was $104 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.

Cadonal

Overview. On December 29, 2014, we completed the acquisition of Cadonal (one of the First Dropdown Assets) pursuant to the ROFO Agreement. Under the terms of a put option agreement entered into with Abengoa in the context with the acquisition of Cadonal, we have a put right whereby we have the irrevocable right to sell the asset back to Abengoa for the same price for which we acquired it if certain waiver conditions related to the Cadonal financing arrangements are not satisfied by the end of March 2015.

Cadonal is an on-shore wind farm facility in Uruguay with nominal installed capacity of 50 MW. Cadonal has 25 wind turbines of 2 MW each. UTE, Uruguay’s state-owned electricity company, has agreed to purchase all energy produced by Cadonal pursuant to a 20-year PPA. Cadonal reached COD in December 2014.

The wind farm is located in Flores, 105 miles north of the city of Montevideo. Gamesa, a global leader in the manufacture and maintenance of wind turbines, supplied the turbines.

Power Purchase Agreement. Cadonal signed a PPA with UTE on December 28, 2012 for 100% of the electricity produced. The PPA requires us to connect Cadonal to UTE’s electrical grid. After Cadonal 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 adjusted every January considering both U.S. and Uruguay’s inflation indexes and the exchange rate between Uruguayan pesos and U.S. dollars.

UTE is unrated and Uruguay has senior unsecured credit ratings of BBB- from S&P, Baa2 from Moody’s and BBB- from Fitch.

Engineering, Procurement and Construction Agreement. The construction of Cadonal 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. Cadonal connects to UTE’s grid at Trinidad Substation and will be done through a 12-mile overhead line (OHL) connecting the wind farm substation and UTE’s substation.

Operations & Maintenance. Cadonal signed an agreement with Epartir, a subsidiary of Abengoa, for the provision of operations and maintenance services for 20 years. Although this agreement covered turbine scheduled and unscheduled maintenance, supply of spare parts, wind farm monitoring and reporting, Epartir subcontracted the wind turbine O&M to the wind turbine manufacturer Gamesa.

Project Level Financing. On September 15, 2014, Cadonal executed an A/B loan agreement and a subordinated debt tranche. The first drawdown occurred on November 28, 2014. The A/B loan is denominated in U.S. dollars. The A tranche, with a tenor of 19.5 years, is a $40.5 million loan from Corporacion Andina de Fomento, or CAF, with a floating interest rate of LIBOR (6 months) plus 390 bps for as long as CAF has access to funding from BankBankengruppe Kreditanstalt fur Wiederaufbau, or KfW, a German public law development institution, through its program for the development of certain climate-relevant projects. The B tranche is a $40.5 million loan from DNB Bank with a floating interest rate of LIBOR (6 months) plus 365 bps for as long as CAF has access to funding from KfW, with a tenor of 17.5 years. The subordinated debt tranche was signed with CAF in the amount of $9.1 million, with a tenor of 19.5 years and a floating interest rate of LIBOR (6 months) plus 650 bps. This subordinated debt tranche may be prepaid in the future at no significant cost to improve the cash generation profile. A hedge (interest rate swap) was arranged in order to mitigate interest rate risk. Cash distributions are permissible every six months subject to a historical senior debt service coverage ratio for the previous twelve-month period of at least 1.20x, a total debt service coverage ratio of at least 1.10x and a projected senior debt service coverage ratio for the following twelve-month period of at least 1.10x, except in the case of the first distribution, in which case the projected senior debt service coverage ratio for the following twelve-month period must be at least 1.20x, the projected total debt service coverage for the following twelve-month period must be at least 1.10x, and both the historical senior debt coverage ratio and the historical total debt coverage ratio must be confirmed by the auditors.

Solaben 2/3

Overview. The Solaben 2 and Solaben 3 projects are two 50 MW solar power plants and are part of Abengoa’s Extremadura Solar Complex. The Extremadura Solar Complex consists of four 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 solar power system to generate electricity. The technology is similar to the technology used at Solana, Mojave and the 11 other 50 MW 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 10 years.

We hold a 30-year right of usufruct over the economic and political rights attached to 70% of the shares of the entity holding Solaben 2 and Solaben 3. We also have a call option to purchase such shares for one euro exercisable during a four-year term.

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 7.398%. This return can be reviewed by the regulator and government every six years, based on the cost of Spanish long-term sovereign bonds.

Solar power plants receive, in addition to the revenues from the sale of electricity in the market, two monthly payments. These payments consist 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 for that year 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. See “Item 4.B—Business Overview—Regulation—Regulation in Spain.”

Engineering, Procurement and Construction Agreement. The construction of Solaben 2/3 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 2/3, 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 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 2/3. ASE has operated solar power plants since 2007 and currently operates 681 MW of installed capacity, including Solaben 2/3, 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 2/3 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 euros. 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, 2014 was €155 million for Solaben 2 and €158 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.

Solacor 1/2

Overview. On November 18, 2014, we completed the acquisition of Solacor 1/2 (one of the First Dropdown Assets) through a 30-year usufruct rights contract over the related shares (which includes an option to purchase such shares for one euro during a four-year term) pursuant to the ROFO Agreement. The Solacor 1/2 project is a 100 MW solar power plant and is part of Abengoa’s El Carpio Solar Complex, located in the municipality of El Carpio, Spain. Abengoa commenced construction of Solacor 1/2 in September 2010. COD was reached in January 2012 for Solacor 1 and in March 2012 for Solacor 2. JGC Corporation, a Japanese engineering company, currently owns 26% of Solacor 1/2.

Solacor 1/2 relies on a conventional parabolic trough solar power system to generate electricity. The technology is similar to the technology used at Solana, Mojave and Solaben 2/3.

According to the tax accelerated depreciation regime established by the Spanish Corporate Income Tax Act, Solacor 1 and Solacor 2 are not expected to pay significant income taxes in the next 10 years.

We hold a 30-year right of usufruct over the economic and political rights attached to 74% of the shares of the entity holding Solacor 1 and Solacor 2. We also have a call option to purchase such shares for one euro exercisable during a four-year term.

Regulation. Renewable energy projects in Spain sell the power they produce into the wholesale electricity market and receive additional payments from the CNMC.

Spain has senior unsecured credit ratings of BBB from S&P, Baa2 from Moody’s and BBB+ from Fitch.

Transmission and Interconnection. Solacor 1/2 delivers its electricity through an underground line 132 kV from the substation of the plant to the SET Pabellones 132 kV. This SET Pabellones connects directly with the line 132 kV Andujar/Lancha of Sevillana Endesa, where the connection point of the plants is located.

Operations & Maintenance. ASE is the contractor for O&M services at Solacor 1/2. ASE has operated solar power plants since 2007 and currently operates 681 MW of installed capacity, including Solacor 1/2, in five 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 Solacor 1/2 in connection with the procurement of all necessary support and ancillary services.

The O&M agreements are 20-year, all-in contracts that expire on the 20^th anniversary of the COD. Each contract provides for the payment of fixed fees of €3.5 million for the equivalent of 75% of the annual targeted output in each O&M agreement, 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 between 100% and 120% of the target output. All amounts are indexed annually to Spanish CPI.

Project Level Financing. Solacor 1/2 entered into 20-year loan agreements with a syndicate of banks formed by BNP Paribas, Mizuho, HSBC and SMBC on August 6, 2010. The loans are denominated in euros. The loans for Solacor 1/2 totaled €353 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 the loans is a floating rate based on EURIBOR plus a margin of 1.5%. The loans were initially approximately 82% hedged with the same banks providing the financing. The hedge was structured 66% through a swap set at approximately 3.20% and 34% through a cap with a 3.25% strike. The total outstanding amount of these loans as of December 31, 2014 was €314 million for Solacor 1/2 project.

These 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. JGC Corporation, a Japanese engineering company, purchased a 26% stake in the economic rights in Solacor 1/2 in August 2010.

PS10/20

Overview. On December 4, 2014, we completed the acquisition of PS10/20 (one of the First Dropdown Assets) pursuant to the ROFO Agreement. PS10/20 is a 31 MW solar power plant and is part of Abengoa’s Solucar Solar Complex, located in the municipality of Sanlucar la Mayor, Spain. Construction of PS10 commenced in June 2004 and construction of PS20 commenced in November 2006. PS10 reached COD in June 2007 and PS20 reached COD in April 2009.

Regulation. Renewable energy projects in Spain sell the power they produce into the wholesale electricity market and receive additional payments from CNMC.

Spain has senior unsecured credit ratings of BBB from S&P, Baa2 from Moody’s and BBB+ from Fitch.

Transmission and Interconnection. PS10/20 evacuate their electricity through an overhead line of 66 kV from the substation of PS10/20 to the SET Sanlucar la Mayor 66 kV. This SET Sanlucar la Mayor is part of the grid of Sevillana Endesa, where the connection point of the plants is located.

Operations & Maintenance. ASE is the contractor for O&M services at PS10/20. ASE has operated solar power plants since 2007 and currently operates 681 MW of installed capacity, including PS10/20, 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 PS10/20 in connection with the procurement of all necessary support and ancillary services.

The O&M agreement for PS10 is a 21-year all-in contract that expires on the 21^st anniversary of the COD. The contract provides for the payment of a fixed fee of €0.321 million for the equivalent of 60% of the annual targeted output in the O&M agreement and a variable fee thereafter equivalent to approximately €22.06 per MWh until 80% of the target output is reached and a fixed fee of €0.406 and a variable fee of €51.50 per MWh for any production between 80% and 100% of the target output. All amounts are indexed annually to Spanish CPI.

The O&M agreement for PS20 is a 21-year all-in contract that expires on the 21^st anniversary of the COD. The contract provides for the payment of a fixed fee of €0.572 million for the equivalent of 60% of the annual targeted output in the O&M agreement and a variable fee thereafter equivalent to approximately €22.06 per MWh until 80% of the target output is reached and a fixed fee of €0.796 and a variable fee of €59.7 per MWh for any production between 80% and 100% of the target output. All amounts are indexed annually to Spanish CPI.

Project Level Financing. PS10 entered into a 21.5-year loan agreement with a syndicate of banks formed by Bankia and Natixis on November 17, 2006. On June 14, 2007 the loan agreement was entered into a novation in order to include in the syndicate of banks the European Investment Bank and Caja de Ahorros del Mediterraneo, which was acquired by Banco Sabadell, S.A. The loan was for €43.4 million. The interest rate for the loan is a floating rate based on EURIBOR plus a margin of 1.0% to 1.10% (depending on the level of the debt service coverage ratio). The loan was initially 100% hedged with the same banks providing the financing. The hedge was structured 30% through a swap set at approximately 4.07% and 70% through a cap with a 4.25% strike. The outstanding amount of this loan as of December 31, 2014 was €32 million.

PS20 entered into a 24.5-year loan agreement with a syndicate of banks formed by Bankia and Natixis Banques Populaires, Spanish Branch on November 17, 2006. On June 14, 2007 the loan agreement was entered into a novation in order to include in the syndicate of banks the European Investment Bank and Caja de Ahorros del Mediterraneo, which was acquired by Banco Sabadell, S.A. The loan was for €94.6 million. The interest rate for the loan is a floating rate based on EURIBOR plus a margin of 1.0% to 1.10% (depending on the level of the debt service coverage ratio). The loan was initially 100% hedged with the same banks providing the financing. The hedge was structured 30% through a swap set at approximately 4.07% and 70% through a cap with a 4.25% strike. The outstanding amount of this loan as of December 31, 2014 was €77 million.

These 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.

Conventional Power

The following table provides an overview of our sole conventional power asset:

Assets

Location

Capacity

Status

Currency

Off-taker

Counterparty
Credit
Rating⁽¹⁾

COD

Contract
Years Left

ACT

Mexico

300 MW

Operational

U.S.
dollars⁽²⁾

Pemex

BBB+/A3/BBB+

2Q 2013

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

(2)	Payable in local currency.

Abengoa Cogeneracion Tabasco

Overview. Abengoa Cogeneracion Tabasco, or ACT, 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.

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 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 our IPO (which was consummated in June 2014) 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, A3 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 77 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 18 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.

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.

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 1.20x, or at any time provided that the last four quarters had a debt service coverage ratio of at least 1.20x.

The outstanding amount of these loans as of December 31, 2014 was $623 million.

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 Lines

The following table provides an overview of our electric transmission assets:

Assets

Location

Length

Status

Currency⁽¹⁾

Off-taker

Counterparty
Credit
Rating⁽²⁾

COD

Contract
Years Left

ATN

Peru

362 miles

Operational

U.S. dollars

Peru

BBB+/A3/BBB+

1Q 2011

ATS

Peru

569 miles

Operational

U.S. dollars

Peru

BBB+/A3/BBB+

1Q 2014

Quadra 1

Chile

43 miles

Operational

U.S. dollars

Sierra
Gorda

N/A

2Q 2014

Quadra 2

Chile

38 miles

Operational

U.S. dollars

Sierra
Gorda

N/A

1Q 2014

Palmucho

Chile

6 miles

Operational

U.S. dollars

Endesa
Chile

BBB+/Baa2/BBB+

4Q 2007

(1)	Certain contracts denominated in U.S. dollars are payable in local currency.

(2)	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 S.A., 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.

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 trust and as owner of 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, ATN owns all assets that it has 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 10 years.

Peru has a long-term credit rating of BBB+ from S&P A3 from Moody’s and BBB+ from Fitch.

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 with 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.

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 15-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, 2014, $106 million in aggregate principal amount 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. Abengoa Transmision Sur S.A., 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 Montalvo. 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 achieving COD, which was achieved on January 17, 2014. As part of the initial concession agreement, ATS agreed to construct the Montalvo substation second bus bar, which is a strip or bar of copper, brass or aluminum that conducts electricity within an electrical system. The second bus bar was not required for operation of the ATS Project and its construction was completed in December 2014.

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 10 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 achieving COD.

Pursuant to the initial concession agreement, ATS will own all assets it has 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 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, A3 from Moody’s and BBB+ from Fitch.

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, which was completed in December 2014. 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, provides 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 the 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 in shares of ATS in exchange for a share of the dividends and the taxable loss generated by the ATS Project. We purchased Cofides’ stake in ATS on October 2, 2014 and now indirectly own 100% of ATS.

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 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, 2014, 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.

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, 2014, 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 was signed in May 2014. As of December 31, 2014, $83 million in aggregate principal amount 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, 2014 was $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. The transfer of the preferred equity investment in ACBH was completed immediately prior to our IPO. Abengoa holds 100% of the ordinary shares of ACBH.

Pursuant to the shareholders’ agreement dated April 29, 2014 entered into among us, ACBH and the ordinary shareholders of ACBH, we have the following rights under the exchangeable preferred equity investment:

•

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 cash corresponding to such preferred dividends for the five-year period was deposited for this purpose in an account in New York City in U.S. dollars in the amount of $92 million.

•

Following the initial five-year period, we will have the option to (i) remain as a preferred equity holder with the right to receive 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 investment 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 Abengoa’s best efforts, the preferred equity investment 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 investment 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 parent support agreement entered into on December 9, 2014 among us, ACBH and Abengoa, Abengoa has guaranteed such dividend for the initial five-year period and in the event that, at any point in time, the amount deposited in New York City in U.S. dollars is lower than the preferred dividend payments that we have the right to receive as of such time, we will be able to retain all payments due to Abengoa and any of its affiliates, including dividends payable on our shares and payments related to all agreements entered into between us and/or our subsidiaries and Abengoa and/or its affiliates, without affecting their respective obligations to continue performing under the relevant contract.

Pursuant to the terms of a deed we entered into with the selling shareholder, 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 selling shareholder agreed that we can defer the payment of a portion of the dividend from us to the selling shareholder in an amount equal to such shortfall (similar arrangements will apply if the selling shareholder transfers any of our shares to its subsidiaries (other than us or our subsidiaries), any holding company of the selling shareholder or any other subsidiaries of such holding companies, or the ACI Group). However, any such deferral will be made only if and to the extent that the selling shareholder (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 us 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 us for the current fiscal year).

ACBH currently has a stake in 15 transmission lines, seven of which are in operation and the other eight are under construction or pre-construction. Each of these projects owned by ACBH 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.

Water

The following table presents our interests in water assets:

Assets

Type

Location

Capacity

Status

Off-taker

Currency⁽¹⁾

Counterparty
Credit Rating

COD

Contract
Years Left

Honaine

Water

Algeria

7 M
ft3/day

Operational

Sonatrach

U.S. dollar

N/A

2012

Skikda

Water

Algeria

3.5 M
ft3/day

Operational

Sonatrach

U.S. dollar

N/A

2009

(1)	Payable in local currency.

Honaine

Overview. On February 3, 2015, we completed the acquisition of 25.5% of Honaine (one of the Second Dropdown Assets) pursuant to the ROFO Agreement. Simultaneously, we entered into a two-year call and put option agreement with Abengoa by which we have put option rights to require Abengoa to purchase back this asset at the same price paid by us and Abengoa has call option rights to require us to sell back this asset if certain indemnities and guarantees provided by Abengoa related to past circumstances reach a certain threshold.

The Honaine project is a water desalination plant located in Taffsout, Algeria, near three important cities: Oran, to the northeast, and Sidi Bel Abbés and Tlemcen, to the southeast. Myah Bahr Honaine Spa, or MBH, is the vehicle incorporated in Algeria for the purposes of owning the Honaine project. Algerian Energy Company, SPA, or AEC, owns 49% and Sociedad Anonima Depuracion y Tratamientos, or Sadyt, a subsidiary of Sacyr, S.A., owns the remaining 25.5% of the Honaine project.

AEC is the Algerian agency in charge of delivering Algeria’s large-scale desalination program. It is a joint venture set up in 2001 between the national oil and gas company, Sonatrach, and the national gas and electricity company, Sonelgaz. Each of Sonatrach and Sonelgaz owns 50% of AEC.

The technology selected for the Honaine plant is currently the most commonly used in this kind of project. It consists of desalination using membranes by reverse osmosis. Honaine has a capacity of seven M ft3 per day of desalinated water and it is under operation since July 2012. The project represents approximately 9.0% of Algeria’s total desalination capacity and serves a population of 1.0 million.

Honaine has corporate income tax exemption until the tenth year after the date of COD. After that period, in case the exemption is not extended, a claim may be made under the contract for compensation in the tariff.

Concessions Agreement. The water purchase agreement is a U.S. dollar indexed 30-year take-or-pay contract with Sonatrach / Algérienne des Eaux, or ADE. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.

Engineering, Procurement and Construction Agreement. The construction of Honaine was carried out by subsidiaries of Abengoa under an arm’s-length, fixed price and date certain EPC contract executed in May 2007.

Operations & Maintenance. In May 2007, MBH signed an operation and maintenance contract and a membrane and chemical products supply contract with UTE Honaine O&M (a joint venture between Abengoa Water, S.L. and Sacyr, S.A., each holding 50%).

The O&M agreement is a 30 year contract from COD and is composed of a fixed fee of $6.9 million per year and a variable component. The fixed O&M cost covers mainly structural and staff costs. The variable O&M cost covers the chemical products, filters cost and membranes costs related to the water production.

Project Level Financing. In May 2007, MBH signed a financing agreement (as amended in November 2008 and June 2013) with the Crédit Populaire d’Algérie, or CPA. The final amount of the loan was $233 million and it accrues fixed interest rate of 3.75%. The repayment of the Honaine facility agreement consists of sixty quarterly payments, ending in April 2027.

The financing arrangements permit cash distribution to shareholders once per year under certain conditions, including that the audited financials for the prior fiscal year indicate a debt service coverage ratio of at least 1.25x.

Partnerships. 51% of the plant is owned by Geida Tlemcen, which is jointly owned by us (50%) and Sadyt (50%). The other 49% is held by AEC.

Skikda

Overview. On February 3, 2015, we completed the acquisition of 34.17% of Skikda (one of the Second Dropdown Assets) pursuant to the ROFO Agreement. Simultaneously, we entered into a two-year call and put option agreement with Abengoa by which we have put option rights to require Abengoa to purchase back these assets at the same price paid by us and Abengoa has call option rights to require us to sell back these assets if certain indemnities and guarantees provided by Abengoa related to past circumstances reach a certain threshold.

The Skikda project is a water desalination plant located in Skikda, Algeria. Skikda is located 510 km east of Alger. Aguas de Skikda, or ADS, is the vehicle incorporated in Algeria for the purposes of owning the Skikda project. AEC owns 49% and Sadyt owns the remaining 16.83% of the Skikda project.

The technology selected for the Skikda plant is currently the most commonly used in this kind of project. It consists of the use of membranes to obtain desalinated water by reverse osmosis. Skikda has a capacity of 3.5 M ft3 per day of desalinated water and is in operation since February 2009. The project represents approximately 4.5% of Algeria’s total desalination capacity and serves a population of 0.5 million.

Skikda has corporate income tax exemption until the tenth year after the date of commissioning. After that period, in case the exemption is not extended, a claim may be made under the contract for compensation in the tariff.

Concessions Agreement. The water purchase agreement is a U.S. dollar indexed 30-year take-or-pay contract with Sonatrach / ADE. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.

Engineering, Procurement and Construction Agreement. The construction of Skikda was carried out by subsidiaries of Abengoa under an arm’s-length, fixed price and date certain EPC contract executed in July 2005.

Operations & Maintenance. In July 2005, ADS signed an operation and maintenance contract and a membrane and chemical products supply contract with UTE Geida O&M (a joint venture between Abengoa Water, S.L. holding 67%, and Sacyr, S.A., holding 33%).

The O&M agreement is a 30 year contract from COD and is composed of a fixed fee of $4.3 million per year and a variable component. The fixed O&M cost covers mainly structural cost and staff costs. The variable O&M cost covers the chemical products, filters cost and membranes costs related to the water production.

Project Level Financing. In July 2005, ADS signed a financing agreement (as amended in May 2009) with the Banque Nationale d’Algérie, or BNA. The final amount of the loan was $108.9 million and it accrues fixed interest rate of 3.75%. The repayment of the Skikda facility agreement consists of sixty quarterly payments, ending in May 2024.

Partnerships. 51% of the plant is owned by Geida Skikda, which is jointly owned by us (67%) and Sadyt (33%). The other 49% is held by AEC.

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 and acquiring new contracted revenue-generating assets in operation from Abengoa under the ROFO Agreement, and assets from parties other than Abengoa. Abengoa has informed us of its intention, which is reflected in the ROFO Agreement, that we 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 that we have agreed with Abengoa in other selected regions. We believe 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 is not obligated to sell any of the Abengoa ROFO Assets to us by any date or at all. Abengoa may offer and sell to third parties assets that are not yet contracted revenue assets in operation. As a result, we do not know when, if ever, Abengoa will offer us any assets for acquisition. In addition, in the event that Abengoa elects to sell Abengoa ROFO Assets, Abengoa will not be required to accept any offer we make for any such Abengoa ROFO Asset.

We intend to leverage the ability of Abengoa to develop, build and operate assets in our target sectors and secure contracted assets that we expect to generate accretive growth for our shareholders once purchased by us. We intend to use the following investment guidelines in evaluating prospective acquisitions in order to successfully execute our accretive growth strategy:

•

high quality off-takers, with long-term contracted revenue, ideally longer than 20 years;

•

project financing in place at each project;

•

operations and maintenance contract in place at each project;

•

management and operational systems and processes at our 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, as well as selected countries in Africa and the Middle East; 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.

The ROFO Agreement provides us with a right of first offer to acquire the Abengoa ROFO Assets. In November and December 2014, pursuant to the ROFO Agreement, we completed the acquisition of the First Dropdown Assets from Abengoa under the ROFO Agreement. Together, the First Dropdown Assets comprise an aggregate of 131 MW of solar power generation and 50 MW of wind power generation. See “Item 4.B—Business Overview—Our Operations—Renewable Energy” for a description of such assets. In February 2015, pursuant to the ROFO Agreement, we agreed to acquire the Second Dropdown Assets from Abengoa, which comprise an aggregate of 200 MW of solar power generation, 10.5 M ft3 per day of water desalination and an 81-mile transmission line. On February 3, 2015, we completed the acquisition of the 25.5% stake in Honaine and the 34.17% stake in Skikda. See “Item 4.B—Business Overview—Our Operations—Water” for a description of such assets. The completion of the acquisition of the 40% stake in ATN2, the 29.6% stake in Helioenergy 1/2 and the 20% stake in Shams is subject to satisfaction of customary conditions, including approvals from financing institutions and, in certain cases, from partners in joint ventures. In the case of ATN2, the acquisition is also subject to the beginning of the generation of revenues by the project, unless such conditions are waived by Abengoa and us. If the conditions are not met by June 30, 2015, each party may terminate the agreement. See “Item 4.B—Business Overview—Second Dropdown Assets.”

We expect that, pursuant to the ROFO Agreement, Abengoa will from time to time present us with other 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 other potential buyers. Under the ROFO Agreement, Abengoa will not be obligated to 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 assets for acquisition. In addition, in the event that Abengoa elects to sell Abengoa ROFO Assets, Abengoa will not be required to accept any offer we make for any such 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 Abengoa ROFO 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 30 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 30-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.

The following table presents some of the projects that we expect Abengoa may present to us for acquisition in the future:


Possible ROFO Assets	Type	Location	Capacity	Status
A3T	Conventional	Mexico	220 MW	Construction
ATN3	Transmission Line	Peru	220 Miles	Construction
SPP1	Conventional	Algeria	150 MW	Operational
Palen	Renewable (Solar)	United States	150 MW	Development
Pahrump	Renewable (PV)	United States	90 MW	Development
San Antonio Vista Ridge	Water	United States	50 million gallons/day	Development
Norte III	Conventional	Mexico	924 MW	Development
Zapotillo	Water	Mexico	112 Miles	Pre-Construction
Atacama 1	Renewable (Solar)	Chile	210 MW	Development
Atacama 2	Renewable (Solar)	Chile	210 MW	Development
Leasing (Nicefield)	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-XXIV	Transmission Line	Brazil	3,863 Miles	Pre-Construction
Ashalim	Renewable (Solar)	Israel	110 MW	Pre-Construction
Kaxu	Renewable (Solar)	South Africa	100 MW	Construction
Khi	Renewable (Solar)	South Africa	50 MW	Construction
Xina	Renewable (Solar)	South Africa	100 MW	Pre-Construction
Tenes	Water	Algeria	7 M ft3/day	Construction
Nungua	Water	Ghana	2.1 M ft3/day	Construction
A4T	Conventional	Mexico	620 MW	Development

Abengoa may enter into agreements with other companies with the objective of jointly financing the construction of new projects consisting of concessional assets which are included in Abengoa’s current or future portfolio. On January 6, 2015, Abengoa announced that it and the energy and infrastructure investor EIG Global Energy Partners have entered into a non-binding agreement with the objective of jointly investing in a new company for the development of the already contracted portfolio of Abengoa’s projects under construction. Pursuant to the terms of the ROFO Agreement, we expect that any investing vehicle created by Abengoa and a potential partner with this purpose, including EIG Global Energy Partners, will sign the ROFO Agreement in the same terms of Abengoa.

Our agreements with Abengoa do not prohibit Abengoa from acquiring or operating contracted assets that fulfill our principles or selling any such assets prior to operation to third parties. See “Item 3.D—Risk Factors—Risks Related to our Relationship with Abengoa” and “Item 7.B—Related Party Transactions—Project-Level Management and Administration Agreements” for further information.

First Dropdown Assets

Pursuant to the terms and conditions of the ROFO Agreement with Abengoa, in September 2014 we agreed to purchase from Abengoa three renewable energy assets, or the First Dropdown Assets. The total aggregate consideration for the First Dropdown Assets was $312 million (which consideration was determined in part by converting the portion of the purchase price of Solacor 1/2 and PS10/20 denominated in euros into U.S. dollars based on the exchange rate on the date on which the payment was made). The First Dropdown Assets were financed with the proceeds of the 2019 Notes and with a portion of the proceeds of the Credit Facility. See “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—2019 Notes” and “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—Credit Facility.”

On November 18, 2014, we completed the acquisition of Solacor 1/2 through a 30-year usufruct rights contract over the related shares (which includes an option to purchase such shares for one euro during a four-year term); on December 4, 2014, we completed the acquisition of PS10/20; and on December 29, 2014, we completed the acquisition of Cadonal, although we have the right to unwind the acquisition of Cadonal under the terms a put option agreement entered into with Abengoa if certain conditions are met by the end of March 2015. Solacor 1/2 has a capacity of 100 MW, PS10/20 has a capacity of 31 MW and Cadonal has a capacity of 50 MW. Solacor 1/2 and PS10/20 are solar power plants located in Spain and Cadonal is an on-shore wind farm located in Uruguay. See “Item 4.B—Business Overview—Our Operations—Renewable Energy” for a description of such assets.

Second Dropdown Assets

Pursuant to the terms and conditions of the ROFO Agreement with Abengoa, in February 2015 we agreed to purchase from Abengoa a participation in five additional assets (Honaine, Skikda, ATN2, Helioenergy 1/2 and Shams), or the Second Dropdown Assets, which comprise an aggregate of 200 MW of solar power generation, 10.5 M ft3 per day of water desalination and an 81-mile transmission line.

On February 3, 2015, we completed the acquisition of a 25.5% stake in Honaine and a 34.17% stake in Skikda from Abengoa under the ROFO Agreement. Simultaneously, we entered into a two-year call and put option agreement with Abengoa by which we have put option rights to require Abengoa to purchase back these assets at the same price paid by us and Abengoa has call option rights to require us to sell back these assets if certain indemnities and guarantees provided by Abengoa related to past circumstances reach a certain threshold. Honaine and Skikda are two water desalination plants in Algeria with an aggregate capacity of 10.5 M ft3 per day. Revenues of these assets are indexed to U.S. dollars and payable in local currency. See “Item 4.B—Business Overview—Our Operations—Water” for a description of such assets.

The completion of the acquisition of the 40% stake in ATN2, an 81-mile transmission line in Peru, a 29.6% stake in Helioenergy 1/2, a 100 MW solar power asset in Spain, and a 20% stake in Shams, a 100 MW solar power asset in the United Arab Emirates, is subject to satisfaction of customary conditions, including approvals from financing institutions and, in certain cases, from partners in joint ventures. In the case of ATN2, the acquisition is also subject to the beginning of the generation of revenues by the project, unless such conditions are waived by Abengoa and us. If the conditions are not met by June 30, 2015, each party may terminate the agreement.

The total aggregate consideration for the Second Dropdown Assets will be $142 million and will be financed with a portion of the proceeds of the Credit Facility and available cash.

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 PPAs. We also employ concession contracts, typically ranging from 20 to 30 years. See the description of each asset under “Item 4.B—Business Overview—Our Operations” for more detail on each concession contract.

Our main contracts in our business also include the 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 “Item 4.B—Business Overview—Our Operations.”

Additionally, we have entered into a ROFO Agreement, an Executive Services Agreement, a Support Services Agreement, a Financial Support Agreement, a Trademark License Agreement, a Governance MOU and a Call Option Agreement with Abengoa. See “Item 7.B—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

On June 13, 2014, we entered into a licensing agreement with Abengoa pursuant to which Abengoa granted us a non-exclusive, royalty-free license to use the name “Abengoa” and the Abengoa logo. Other than under this limited license, we will not have a legal right to use the “Abengoa” name or the Abengoa logo. On September 10, 2014, Abengoa transferred 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. Abengoa is entitled to terminate the licensing agreement in the circumstances described under “Item 7.B—Related Party Transactions—Trademark License Agreement.”

Regulatory and Environmental Matters

See “Item 4.B—Business Overview—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 “Item 3.D—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 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

As of December 31, 2014, we had seven employees, all in one of our solar power assets in Spain. During the year 2014, we did not employ any member of our senior management team. Since February 1, 2015, we are in the process of transferring and employing directly our executive management team, including Mr. Seage, Mr. Soler, Mr. Silvan, Mr. Garcia, Mr. Merino and Ms. Hernandez. Once this process is completed, the Executive Services Agreement between Abengoa and us will be terminated. See “Item 7.B—Related Party Transactions—Executive Services Agreement.” For a discussion of our management team, see “Item 6—Directors, Senior Management and Employees.” In addition, we are in the process of employing directly some of the employees who were in Abengoa’s subsidiaries in 2014. As of the date of this annual report, we had 23 employees in our subsidiaries.

Properties

See “Item 4.B—Business Overview—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.

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, and 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 the FERC, which draws its jurisdiction from the FPA, as amended, 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 underlying 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 that are designed 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 result in a reduction in rates. FERC also has the authority to assess substantial civil penalties (up to $1.0 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 generating 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 generating facility to the grid, and faces restrictions in transacting business with affiliated regulated utilities.

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 generating capacity and ancillary services. Given the limited interconnections between power transmission systems in the United States and differences among market rules, regional markets have formed as part of the power 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.

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.

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, 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 1603 Cash Grant application for Solana was filed on November 14, 2013 with additional information provided to the U.S. Treasury in 2014. A final award from the U.S. Treasury was made as of October 2014. The preliminary 1603 Cash Grant application for Mojave was filed on September 14, 2012. Since Mojave reached COD in December 2014, a final 1603 Cash Grant application was recently filed on February 5, 2015.

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. For cash grant award letters issued on or after October 1, 2014 through September 30, 2015, the Office of Management and Budget has estimated that the sequestration reduction will be 7.3%. This reduction applies regardless of the date on which the application for a 1603 Cash Grant was received by U.S. Treasury.

Federal Loan Guarantee Program

The DOE, in an effort to promote the rapid deployment of renewable energy and electric power transmission projects, is authorized to grant guarantees with respect to certain loans to renewable energy projects and related manufacturing facilities and electric power 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. Loan guarantees under Section 1703 continue to be available for solar. However, eligibility is limited. The applicant must be located in the United States and may include foreign ownership so long as the project is located in one of the 50 states, the District of Columbia or a United States territory. The project must employ a new or significantly improved technology that is not a commercial technology. A commercial technology is defined as in general use in the commercial marketplace in the United States at the time the term sheet is issued by the DOE. A technology is considered to be in commercial use if it has been installed in and is being used in three or more commercial projects in the United States and has been in operation in each such commercial project for at least five years. The project must also pay prevailing wages under the Davis-Bacon Act.

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 solar power projects, such as Solana and Mojave, qualifies for five-year depreciation under MACRS. In addition, some equipment used in solar power projects may qualify for bonus depreciation for equipment placed in service.

DOE Research Grants, State Energy Funding, Workforce Training, and Other Initiatives under the ARRA

The DOE received funding under the ARRA, which it has disbursed or is in the process of disbursing, to increase solar power production. Some funds were allocated as grants to support research and the development, demonstration, and deployment of projects. Funds were awarded to states on the basis of their electric consumption to fund energy efficiency, renewable energy, and other energy programs. ARRA funds were allocated with the purpose of providing workforce training with respect to renewable energy and energy efficiency. A number of initiatives were funded by the DOE with ARRA monies, including initiatives addressing solar market transformation, the integration of PV generation into the distribution system, and base load solar power generation.

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 in Arizona and California. Information about the regulatory frameworks in Arizona and California is provided below.

United States State-Level Incentives

In addition to federal legislation, many states have enacted legislation, principally in the form of renewable portfolio standards, or RPS, which generally require electric utilities to generate or purchase a certain percentage of their electricity supplied to consumers from renewable resources. In certain states, it is not only mandatory to meet these percentages from renewable resources, which in general are on the increase, but also electric utilities may be required to generate or purchase a percentage of their electricity supplied to consumers from specific renewable energy technologies, including solar technology. Depending upon the state, various certifications, permits, contracts and approvals may be required in order for a project to qualify for particular RPS programs. Some states, for example, require that only renewable energy generated in-state counts towards the RPS. According to the Database of State Incentives for Renewable Energy, as of August 2014, 49 states and United States territories have adopted some type of RPS standards. 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. In RPS states where a liquid REC market does not exist, renewable energy can be bought or sold through “bundled” PPAs, where the PPA price includes the price for renewable energy attributes. Some states require that RECs and the associated electricity be purchased together in order to count towards the RPS. In states that do not have RPS requirements, certain entities buy RECs voluntarily. These RECs generally have lower prices than RECs that are used to meet RPS obligations. The price of RECs can vary significantly, depending on their availability, which in turn depends upon the amount of renewable generation that has been put in service in a state that has implemented RPS requirements. In some states, the number of successful projects has generated more RECs than required to meet the applicable RPS requirements for a given year or years, leading to steep drops in the market price for RECs. Additionally, demand for RECs can be driven by requirements (such as those imposed under the California Environmental Quality Act) that development projects mitigate potential significant GHG impacts identified in connection with environmental clearances.

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, or IOUs. In addition, the California Solar Initiative, or CSI, sets a goal of 1,940 MW of solar capacity by the end of 2016. The CSI provides monetary incentives for solar installation between 1 kW and 5 MW in size as well as grants for research, development, and demonstration. California’s feed-in tariff program

obligates IOUs to purchase solar generation at a standard price until a purchase threshold is crossed. Colorado set an RPS of 30% by 2020 for IOUs, permits the trading of RECs, and requires that 3% of the RPS be met by distributed generation in 2020 for IOUs. Arizona set an RPS of 15% by 2025, with 30% of the RPS to be met from distributed generation. A Texas law signed in August 2005 requires that 5,880 MW of new renewable generation be built by 2015. The law also set a target of having 10,000 MW of renewable generation capacity by 2025. Additionally, Texas law establishes a minimum of 500 MW of non-wind renewable generation, and doubles the RPS compliance value provided by non-wind 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. In addition, a number of states collect electricity surcharges on residential and commercial users and through public benefit funds reinvest some of these funds in renewable energy projects. 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 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.

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 with 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 Finding of No Significant Impact (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.

Regulations Affecting Operating Generating 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 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 CEC, 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 CEC is comprised of five commissioners, two of whom oversee all hearings, workshops and related proceedings on a specific project. The CEC’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.

On August 10, 2009, Mojave’s AFC for its nominal 250 MW project was filed with the CEC. The CEC approved Mojave’s AFC with the CEC decision issued on September 8, 2010. The CEC monitors the power plant’s construction, operational phase and eventual decommissioning through a compliance proceeding.

Regulations Affecting Operating Generating Facilities in California

Mojave must maintain compliance with the CEC 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 CEC staff. Per the CEC 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 Operator 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.

Pursuant to the Mexican Constitution, the electricity industry in Mexico was entirely 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 was the only entity authorized to provide electricity directly to the public and to supply services to the Mexican wholesale market. CFE was also responsible for the construction and maintenance of infrastructure necessary for the delivery of electricity, such as the national electric grid, the Sistema Electrico Nacional, or SEN.

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. With the enactment of the secondary legislation, the generation, transmission, distribution and commercialization of power in Mexico will be governed by a new legal framework which will likely improve the development of the sector.

Notwithstanding the 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 energy reform, the whole set of activities regarding generation, transmission, distribution and commercialization 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 was also controlled by CFE through the Centro Nacional de Control de Energia, or the CENACE, which operated the national electric grid and controlled 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, CENACE became 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. CENACE will soon emerge as an Independent System Operator, or ISO, which is a figure adopted worldwide in other mature energy markets.

The generation, transmission and distribution of electricity were 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 is used for self-supply purposes.

The regulatory framework of the Mexican power industry is undergoing a transitory period, as the energy reform is still in the process of being fully implemented, given that the secondary legislation derived from such amendments to the Mexican Constitution was published in the Official Federal Gazette, or Diario Oficial de la Federacion, on August 11, 2014, and there are still several regulatory instruments pending issuance. See “Item 4.B—Business Overview—Regulation—Regulation in Mexico—Transitory Regime.”

The changes made by the energy reform will be implemented through a profound modification of the legal framework that has governed the development of the energy industry in the country, which involves the entrance into force of new laws and the amendment of current laws.

The new laws are listed below:

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Oil and Gas Law, or Ley de Hidrocarburos;

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Electric Industry Law, or Ley de la Industria Electrica;

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Geothermal Energy Law, or Ley de Energia Geotermica;

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Petroleos Mexicanos Law, or Ley de Petroleos Mexicanos;

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Federal Electricity Commission Law, or Ley de la Comision Federal de Electricidad;

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Energy Regulatory Bodies Law, or Ley de los Organos Reguladores Coordinados en Materia Energetica;

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National Industrial Safety and Environmental Protection Law of the Oil and Gas Sector, or Ley de la Agencia Nacional de Seguridad Industrial y de Proteccion al Medio Ambiente del Sector Hidrocarburos;

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Mexican Petroleum Fund for Stabilization and Development, or Ley del Fondo Mexicano del Petroleo para la Estabilizacion y el Desarrollo; and

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Oil and Gas Revenue Law, or Ley de Ingresos sobre Hidrocarburos.

Additionally, 12 laws were amended in order to unify their content with the new regulatory framework. The following are the amended laws:

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Foreign Investment Law, or Ley de Inversion Extranjera;

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Mining Law, or Ley Minera;

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Private Public Partnerships Law, or Ley de Asociaciones Publico Privadas;

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National Water Law, or Ley de Aguas Nacionales;

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Federal Law of Government-Owned Entities, or Ley Federal de las Entidades Paraestatales;

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Public Sector Acquisitions, Leases and Services Law, or Ley de Adquisiciones, Arrendamientos y Servicios del Sector Publico;

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Public Works and Related Services Law, or Ley de Obras Publicas y Servicios Relacionados con las mismas;

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Organizational Law of the Federal Government, or Ley Organica de la Administracion Publica Federal;

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Federal Fees Law, or Ley Federal de Derechos;

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Fiscal Coordination Law, or Ley de Coordinacion Fiscal;

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Federal Budget and Treasury Accountability Law, or Ley Federal de Presupuesto y Responsabilidad Hacendaria; and

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General Public Debt Law, or Ley General de Deuda Publica.

Furthermore, on October 31, 2014, the following regulations and regulatory instruments, which will contribute to the implementation of the aforementioned secondary legislation, were published in the Official Federal Gazette:

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Regulations of the Oil and Gas Law, or Reglamento de la Ley de Hidrocarburos;

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Regulations of the activities referred to in Chapter Three of the Oil and Gas Law, or Reglamento de las actividades a que se refiere el Titulo Tercero de la Ley de Hidrocarburos;

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Oil and Gas Revenue Law Regulations, or Reglamento de la Ley de Ingresos sobre Hidrocarburos;

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Electric Industry Law, or Reglamento de la Ley de la Industria Electrica;

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Geothermal Energy Law Regulations, or Reglamento de la Ley de Energia Geotermica;

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Regulations of Petroleos Mexicanos Law, or Reglamento de la Ley de Petroleos Mexicanos;

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Regulations of the Federal Commission of Electricity Law, or Reglamento de la Ley de la Comision Federal de Electricidad;

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Internal Regulations of the Ministry of Energy, or Reglamento Interior de la Secretaria de Energia; and

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Internal Regulations of the National Agency of Industrial Safety and Environmental Protection, or Reglamento Interior de la Agencia Nacional de Seguridad Industrial y de Proteccion al Medio Ambiente del Sector Hidrocarburos.

Additionally, the executive branch also published the following decrees, which amended the existing regulations of different laws and which are relevant for the development of the energy sector:

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Decree amending and supplementing various provisions of the Public Partnerships Law Regulation, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento de la Ley de Asociaciones Publico Privadas;

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Decree amending and supplementing various provisions of the Federal Budget and Treasury Accountability Law, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento de la Ley Federal de Presupuesto y Responsabilidad Hacendaria;

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Decree amending and supplementing various provisions of the Internal Regulation for the Ministry of Finance and Public Credit, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento Interior de la Secretaria de Hacienda y Credito Publico;

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Decree amending and supplementing various provisions of the Regulations of the Mining Law, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento de la Ley Minera;

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Decree amending and supplementing various provisions of the Regulations of the Foreign Investment Law and of the National Registry of Foreign Investment, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento de la Ley de Inversion Extranjera y del Registro Nacional de Inversiones Extranjeras;

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Decree amending and supplementing various provisions of the Internal Regulations of the Ministry of Economics, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento Interior de la Secretaria de Economia;

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Decree amending and supplementing various provisions of the Internal Regulations of the Ministry of Agrarian, Territory and Urban Development, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento Interior de la Secretaria de Desarrollo Agrario, Territorial y Urbano;

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Decree amending and supplementing various provisions of the Regulations of the General Law for Sustainable Forestry Development, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento de la Ley General de Desarrollo Forestal Sustentable;

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Decree amending and supplementing various provisions of the Regulations of the General Law of Ecological Balance and Environmental Protection on Environmental Impact Assessment, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento de la Ley General del Equilibrio Ecologico y la Proteccion al Ambiente en Materia de Evaluacion del Impacto Ambiental;

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Decree amending and supplementing various provisions of the Regulations of the General Law of Ecological Balance and Environmental Protection regarding prevention and Control of Air Pollution, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento de la Ley General del Equilibrio Ecologico y la Proteccion al Ambiente en Materia de Prevencion y Control de la Contaminacion de la Atmosfera;

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Decree amending and supplementing various provisions for the Regulations of the General Law for Prevention and Integral Waste Management, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento de la Ley General para la Prevencion y Gestion Integral de Residuos;

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Decree amending and supplementing various provisions of the Regulations of the General Law of Ecological Balance and Environmental Protection on Environmental Zoning, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento de la Ley General del Equilibrio Ecologico y la Proteccion al Ambiente en Materia de Ordenamiento Ecologico;

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Decree amending and supplementing various provisions of the Regulations of the General Law of Ecological Balance and Environmental Protection regarding Emissions to the Atmosphere and Transfer of Pollutants, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento de la Ley General del Equilibrio Ecologico y la Proteccion al Ambiente en Materia de Registro de Emisiones y Transferencia de Contaminantes;

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Decree amending and supplementing various provisions of the Internal Regulations of the Ministry of Environment and Natural Resources, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento Interior de la Secretaria de Medio Ambiente y Recursos Naturales; and

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Decree amending and supplementing various provisions of the Regulations of the General Law of Ecological Balance and Environmental Protection on Self-Regulation and Environmental Audits, or Decreto por el que reforman, adicionan y derogan diversas disposiciones del Reglamento de la Ley General del Equilibrio Ecologico y la Proteccion al Ambiente en Materia de Autorregulacion y Auditorias Ambientales.

Conventional Electricity Generation in Mexico

The former legal framework for conventional electricity generation in Mexico included 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 was not considered a public utility service and, therefore, could 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, controlled 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 important parts 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 under the new legal framework, privately sold electricity will be transmitted and distributed 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.

As a result of the energy reform, the electricity sector will cease to be a chain of activities vertically integrated in a partially privatized sector, and become an area open to private investment in which, although CFE will maintain control, the possibility of private sector investment will be increased through a more flexible regulatory scheme that permits the execution of contracts to carry out various activities and the creation of new markets in the electricity sector. Among the most significant changes are the following:

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Participation open to the private sector in the generation of electricity through a permit granted by CRE. Private parties may also sell the energy generated and transmitted by CFE through commercial schemes.

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Participation of the private sector, together with CFE, in the activities of transmission and distribution through the execution of the corresponding contracts.

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Participation of the private sector in activities of financing, maintenance, management, operation and expansion of the power infrastructure through service contracts with CFE, with adequate compensation.

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Transformation of the CENACE, currently under the CFE, into a decentralized public body responsible for the operational control of the national electric grid, so that it is an impartial third party (and not the CFE) that operates the wholesale electricity market, guaranteeing open access to the national electric grid, for both transmission and distribution of electric power.

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Creation of the Wholesale Electricity Market, Mercado Electrico Mayorista, or MEM, operated by the CENACE, in which the participants may carry out electric power purchase and sale transactions through contracts between the participants in the MEM. The CENACE will be responsible for

managing the supply and demand of the MEM participants, carrying out transactions and generating prices continuously. The price that will be paid in the MEM transactions will be a competitive price, reflecting the costs of generation and other operating costs of electricity, as well as the volume of electric power demanded and supplied in the MEM.

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Creation of the trader, under the new Electric Industry Law, as the holder of a MEM participant agreement, which purpose is to carry out trading activities (execution of contracts for purchase and sale of electricity within the MEM, among others). The traders may sign contracts with qualified users (through the provider-trader) or execute such contracts with other traders (non-provider trader).

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The permits granted by the CRE under the currently repealed Electricity Law, will continue in force under its terms. The holders of those permits that choose to remain under the provisions of the Electricity Law may, at any time, transfer to the new rules.

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The Geothermal Energy Law, the purpose of which is to regulate the recognition, exploration and exploitation of geothermal resources for the use of underground thermal energy within the limits of Mexican territory, in order to generate electricity or use it otherwise.

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The activities regulated by the Geothermal Energy Law are considered to be in the public interest and their development will have preference over activities of other sectors when there is a conflict.

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The activities pursued under the Geothermal Energy Law will be carried out through different registries, permits, authorizations and concessions granted by the competent authorities applicable for each case. For exploration activities, a permit will be sufficient, while for exploitation activities, a concession will be required.

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Amendment of several articles of the National Water Law, for the purpose of (i) adapting certain definitions of that law to the new definitions introduced by the Geothermal Energy Law; (ii) including geothermal fields under regulated, prohibited or reserved zones; and (iii) establishing the obligation of requesting the relevant permits, authorizations and concessions from the National Water Commission in order to engage in the activities of geothermal fields exploration.

Electric Industry Law

The Electric Industry Law, as part of the package of secondary legislation that will implement the constitutional energy reform, regulates planning activities, the control of the national electric grid, the public services of transmission and distribution of electricity, and all other activities related to the Mexican energy industry, in order to promote the sustainable development of the industry and to ensure its continuous, efficient, and secure operation for the benefit of all users, as well as the fulfillment of the obligations to provide a general and public service of electricity, to develop clean energies, and to reduce contaminating emissions.

Pursuant to the Electric Industry Law, the government will hold the operational control of the national electric grid, through the CENACE, and CENACE, as an ISO, will indicate the elements for the national transmission grid and the related operations which may correspond to the wholesale market.

Regulations of the Electric Industry Law

The Regulations of the Electric Industry Law provide details for the application of the Electric Industry Law and complete the implementation of the restructured electric industry in Mexico.

These regulations expand on certain administrative procedures in the electric industry, such as the development of public bidding procedures by CFE, for private sector contracts for activities related to the national electric grid; the specific requirements for the application for power generation and power supply permits with CRE; the process for infrastructure contributions by the private sector to the State; and the registration of participants in the wholesale spot market with CENACE.

Permits and Authorizations

Pursuant to the Electric Industry Law, all power plants with a capacity greater than or equal to 0.5 MW and all power plants of all capacities represented by a generator (i.e., the holder of one or more generation permits or holder of a wholesale market participant agreement that represents the corresponding power plants

in the wholesale market or, prior authorization granted by CRE, power plants located abroad) will require a generation permit granted by CRE. Authorization granted by CRE will also be required for the import of electricity from a power plant located abroad and interconnected exclusively to the national electric grid. Power plants of any capacity exclusively intended for personal use during emergencies or interruptions in electric supply will not require a permit.

The Electric Industry Law provides for several requirements which generators who represent power plants interconnected to the national electric grid will have to comply with, including, among others, the execution of the corresponding interconnection agreements, issued by CRE. Regarding the production of their power plants, generators may carry out commercialization activities which include, among others, the following: (i) representing exempt generators (i.e., owner or holder of one or more power plants which do not require or have a generation permit) in the MEM; (ii) carrying out sale and purchase transactions of energy, related services included in the MEM, and power or other products which ensure enough resources to meet the electric demand, and all other products, duties or penalties required for the efficient operation of the national electric grid, among others; and (iii) executing, among others, the corresponding electric coverage agreements (i.e., agreement entered into by participants of the MEM which purpose is the sale and purchase of electric energy or related products) with other MEM participants, including other generators, traders (i.e., holder of a MEM participant agreement which purpose is to carry out commercialization activities), and qualified users (i.e., final user who is registered before CRE to acquire electricity supply as a MEM participant or through a qualified provider).

Pursuant to the former legal framework for the Mexican electric industry, permits for self-supply, cogeneration, independent production, small production, import, and export of electricity were granted by CRE for indefinite periods of time, except for independent power producer permits, which were granted for 30-year renewable terms. In addition to the legal and technical requirements established by law to obtain such permits, CFE’s approval was required as part of CRE’s permit approval process. Pursuant to the transitory regime, such permits will be in force for the duration of the corresponding interconnection agreements executed under their scope.

CRE may also issue a supply permit for private parties, which will allow companies to participate in the MEM by carrying out transactions with final users, which are called “qualified users.” In this sense, private parties may supply power directly to consumers through bilateral long-term agreements, which will be partially regulated by the CRE.

Consequently, the Mexican power industry had been divided into two main areas: (i) the public service of electricity under CFE’s control, and (ii) 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).

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 come to be a relevant source of power as a result of certain 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 consequence of the corresponding reforms the issuance of a new class of permit available to those interested in generating electricity is provided for pursuant to the Electric Industry Law. This permit will expand the ways in which entities are allowed to participate as energy producers under the Electric Industry Law and is within the scope of the CRE’s regulatory control.

The permits provided for in the Electric Industry Law will be, as aforementioned, granted and issued by CRE, upon prior submission of the corresponding application, payment of the corresponding duties, all relevant legal and technical information, and project description. Such permits will be terminated or revoked pursuant to the different scenarios indicated in the Electric Industry Law and its regulations, and as determined by CRE.

The regulations lists the documentation to be submitted to apply for a permit with CRE, as well as the corresponding timeline for the application procedure and the essential elements that CRE must include in the permit title.

Transmission and Distribution of Electricity in Mexico

Pursuant to the Electric Industry Law, regarding conventional energy generation, dispatchers and distributors will be responsible for the national transmission grid and the general distribution grids and will operate their grids pursuant to the instruction provided by CENACE. Whereas in the past there were no regulatory limitations that would interfere with a private generator engaging in transmission activities, and, regarding distribution activities, these could only be performed by CFE, with the new regulatory framework derived from the constitutional reform and the legal provisions therein, the public service of electricity and its transmission are considered as strategic areas and will continue to be government-controlled, notwithstanding the possibility of the Mexican government, acting through CFE, to be able to enter into agreements with the private sector, or, acting through the Ministry of Energy, to form partnerships or enter into agreements with the private sector to carry out the financing, installation, maintenance, administration, operation or expansion of the infrastructure required to provide electricity transmission and distribution services, in terms of the provisions of the Electric Industry Law.

Such agreements will be awarded to private companies through bidding rounds, conducted by CENACE, which will determine the needs of the national electric grid, and carry out the corresponding tender processes. In addition, all dispatchers and distributors will have the obligation to execute the corresponding connection and interconnection agreements, based on the model contracts issued by CRE, regarding the interconnection of power plants or the connection of load centers, and the MEM regulations will indicate the criteria for CENACE to define the specifications for the required infrastructure necessary for the interconnection of power plants and the connection of load centers, as well as the mechanisms to determine preference matters for applications or requests and the procedure for their evaluation.

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 on a first-come, first-served basis. 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.

The Electric Industry Law incorporates new requirements to carry out the sale and purchase of electricity. Aside from being classified as a generator or qualified user, along with the need to comply with the rules issued by CRE for the execution of the corresponding agreements, there are new requirements for the interconnection to the transmission grid owned by CFE. The Electric Industry Law introduces and provides for the concepts of connection and interconnection, the first referring to the load points of users and the latter referring to generators’ power plants. Regarding interconnection, the most significant change is the need to execute new model agreements in order to adapt them to the new modalities and activities under the scope of regulation of the Electric Industry Law.

Furthermore, the transitory provisions contained in the Electric Industry Law provide that those interconnection agreements which were executed under the scope of regulation of the Electricity Law will remain in force, notwithstanding the possibility that executing the new contract models that will be issued by CRE may prove beneficial in order to adapt to the new changing aspects of the industry; as with previous agreements, companies will only be limited to the authorized activities under such contracts (e.g. wheeling will only be available for the amount of energy and for the specific purpose established therein). This suggests that new models of interconnection agreements may be more flexible to cover the implementation of the various activities allowed.

The regulations provide that CRE must implement a regulatory regime providing for the conditions for the procurement of the public services of transmission and distribution of electric power based on the principles of proportionality and equality, aiming to prevent transporters, distributors and suppliers from exercising excessive market power that could negatively affect final users. Such regulatory regime will consider the degree of openness in the market, the concentration of participants and any other condition of the competition in every division of the industry. The regulations also anticipate the possible cases of curtailment of the services of transmission and distribution of electric power and provide for standard procedures in different situations.

Commercialization of Electricity

Under the Electric Industry Law, the trader will be the holder of a MEM participant agreement, and will carry out commercial activities, among which are executing electric coverage agreements for the sale and purchase of electricity within the MEM. Under the Electric Industry Law, electric coverage agreements are those agreements executed between MEM participants through which those Participants engage in the sale of electric energy or related products. Traders may enter into such agreements with qualified users (through the figure of the provider-trader) or with other traders (who are not providers).

Excluding qualified users, basic providers will provide the basic supply to all people who so request it and whose load centers are located in their operation areas. Qualified providers will provide the qualified supply to qualified users in terms of free competition. Prior commencement of the Qualified or basic supply services, the final user must execute a supply agreement with the appropriate provider, and such agreements will require registration before the Federal Attorney’s Office of Consumer, or Procuraduria Federal del Consumidor, or PROFECOCRE, will issue the general terms and conditions for the electrical supply services, which will determine the rights and obligations of the service provider and the final user, correspondingly.

Qualified users are those final users who are duly registered as such before CRE in order to acquire power as MEM participants or by a qualified provider. In terms of the Electric Industry Law, users holding load points with a demand greater than or equal to 3 MW may be included in the qualified users registry (but such amount will decrease in one MW per year following the first year until reaching 1 MW). In this case, having the property in which the electric power is intended to be supplied registered as Qualified under the corresponding rules to be issued will suffice. Within the MEM, qualified users may purchase energy through electric coverage agreements executed with CENACE or directly with traders.

Supply

Supply activities carried out in the new electric industry may be either in the basic or qualified modalities. Power supply agreements will be executed by and between providers and final users, under the corresponding supply permits issued by CRE. Basic supply refers to that which is provided by a provider under a regulated tariff to any applicant who is not a qualified user. Qualified Supply refers to that which is provided in terms of free competition to qualified users.

For basic supply, private generators may participate in the auctions conducted by CENACE, in order for CFE to acquire the energy in the most convenient economic terms and conditions, and thus CFE will be able to supply power to users who so request it before CENACE, who will carry out the referred auction and determine whom the electricity will be purchased from. CRE will also determine the requirements that providers must comply with in order to acquire energy and execute contracts for electric coverage with users.

As for qualified supply, qualified providers will carry out transactions directly through long-term supply agreements with qualified users. Under these agreements, the parties will be free to agree upon the terms and conditions (including economic conditions) thereof, abiding by certain general guidelines that will be issued by CRE.

Open Access

Both the Electric Industry Law and in the regulations thereunder establish that CFE will be obligated to grant non-discriminatory open access to all users of the national electric grid. This will enhance the existence of an open electricity market, where various competitors in almost all segments of the supply chain requiring the use of the national electric grid will coexist and develop their activities. Open access is a crucial component of the electric industry since CFE, as owner of the grid, will compete directly with other private sector participants in several activities of the industry, which could lead to a monopoly by CFE. In order to avoid such situation, the CENACE, as an independent system operator, will ensure competitive conditions for all users who want to use CFE’s infrastructure.

The regulations provide that CRE will issue the general guidelines regarding open access conditions, the procedure for users to request such open access and the procedure to which the CENACE will be subject to grant this open access, among others.

Tariffs

Transmission, distribution, basic supply and last resort supply, as well as the operation of CENACE, will be subject to regulatory accounting guidelines established by CRE. CRE will issue general administrative provisions regarding the methodology to determine the calculation and adjustment of the regulated tariffs for transmission, distribution, basic provider operation and CENACE operation services, as well as all related services which are not included in the MEM.

Dispatchers, distributors, basic providers and the CENACE will be required to publish their tariffs, as indicated by CRE, through general administrative provisions.

Wholesale Spot Market, Mercado Electrico Mayorista

The Electric Industry Law provides for the creation of a MEM, operated by CENACE, in which Participants can carry out a number of different transactions provided for in said law, among which are the sale of electricity and related products.

MEM participants may be (i) generators, (ii) provider-traders, (iii) non-provider traders, or (iv) qualified users, prior to execution of the corresponding agreement with CENACE. Transactions carried out within the MEM will be formalized through “electric coverage agreements” executed by and between such MEM participants. Generators, as MEM participants may, sell their generated energy and both traders and qualified users may purchase such energy through CENACE, which will be the independent operator of the electric system.

CENACE will be responsible for managing the supply and demand of MEM participants, conducting transactions and continuously generating prices. The price to be paid in MEM transactions will be a “competition price” in terms of the Electric Industry Law, and will reflect elements such as electricity generation costs and other operating costs, as well as the amount of electricity demanded by and supplied within the MEM. Such competition price will serve as a reference for long-term supply agreements between providers and qualified users, partially replacing the current CFE-published tariffs.

Even though the Electric Industry Law provides the general guidelines to which the operation of the MEM will be subject, the Ministry of Energy will issue the Rules of the Market, which are administrative provisions of general application that will specifically detail different aspects of the operation of the MEM. The regulations list certain topics which will be described in depth in the Rules of the Market, such as the methodology that will be used to forecast the level of demand in the spot market, information on market participants, and the methodology to determine the price of the electricity that will be sold and purchased within the spot market.

Public Consultation

The Electric Industry Law and the regulations thereunder set out the obligation to carry out a prior consultation process in the event a project is to be developed in certain lands where communities or indigenous people are found. This obligation, which is established in international treaties, as well as in Article 2 of the Political Constitution of the United Mexican States, is now established in the new legal framework to provide certainty regarding community and social issues in all projects within the electric industry.

The aforementioned general obligation is provided for in the Electric Industry Law and the regulations thereunder detail the specific procedure to be followed, including the filing of a social and cultural impact assessment before the Ministry of Energy and the different stages that the prior consultation entail, among others.

Transitory Regime

Given that the Electric Industry Law sets various deadlines for the full implementation of its provisions (such as the issuance of the Market Rules, the entry into operation of the MEM or the Terms and Conditions for the Supply of Electricity), a transitory regime has been established, intending to provide clarity and certainty to all participants of the industry who either have ongoing projects or plan to start projects in the near future.

Permits

Permits granted by CRE, in accordance with the Electricity Law, will continue to be governed under the terms set out therein and other applicable provisions. Holders of such permits who decide to remain under the regulation of Electricity Law may, at any time, migrate to the new regime if it suits their interests.

Interconnection agreements

In order to be able to execute an interconnection agreement in terms of the Electricity Law (in the event not previously executed), those interested in doing so must comply with the following conditions: (i) having obtained or having applied for a permit in any of the modalities provided by the Electricity Law, prior to the entry into force of the Electric Industry Law (August 11, 2014); (ii) having notified CRE about its intention to continue with the development of the relevant project; and (iii) having provided proof evidencing that the appropriate financing for the project has already been obtained, that they have already contracted the supply of the main equipment required for the project, and that at least 30% of the total investment for the project has been paid before December 31, 2015. Additionally, it is possible to execute an interconnection agreement in terms of the Electricity Law if a company participated in an open season process, through which CRE granted transmission capacity to several participating companies.

The Electric Industry Law also provides certainty regarding interconnection agreements which have been executed with CFE prior to the enactment of the Electric Industry Law, as those agreements which were executed under the scope of regulation of the Electricity Law will remain in force for their entire duration (although they will not be subject to renewal or extension upon their termination). With the enactment of the Electric Industry Law, it is now possible to modify executed interconnection agreements in relation to the load points, surplus sales, support services, cost of stamp wheeling and other conditions contained therein which may apply.

Permit holders who choose to remain under the scope of regulation of the Electricity Law and decide to keep their interconnection agreements will be governed by the terms and conditions set forth therein and, consequently, will not be subject to the rules of the MEM.

Former Regulatory Framework

The following laws and regulations include constitutional, legal and administrative provisions applying to the development of cogeneration projects in Mexico, according to the former regulatory framework:

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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).

Current Regulatory Framework

The following laws and regulations include constitutional, legal and regulatory provisions applying to the development of cogeneration projects in Mexico, according to the recently enacted regulatory framework:

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Political Constitution of the Mexican United States.

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Electric Industry Law.

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Regulation of the Electric Industry Law.

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Law of the Federal Commission of Energy.

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Law of the Coordinated Regulatory Agencies in Energy Matters.

Notwithstanding the above-listed regulatory framework, it is noteworthy that this list remains subject to modifications, as the pending regulatory instruments are to be issued in coming months, and, pursuant to the transitory regime provided for in the new framework, certain former legal provisions will continue to be in force, as applicable, for specific projects which were started before the enactment and implementation of the new legal framework.

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.

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 Peruvian 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 a transmission infrastructure 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 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 (5% per kW-month) 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 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 is 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

The concessionaires must maintain certain quality, safety and maintenance standards of the facilities. The failure to meet the quality standards established by applicable industry regulations, such as the quality for 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.

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.

If the concessionaire requests it, 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 1st 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.

Every year, before the beginning of the new tariff period, OSINERGMIN will recalculate and determine the tariff base in U.S. dollars for the period which starts from May 1 of such year to April 30 of the following year. This determination is approved in April of each year through a resolution published in the Official Gazette, “El Peruano.”

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:

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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.

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Investment grants and direct subsidies. These help defray the costs of installing renewable energy generation plants.

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Tax exemptions or relief. These include ITCs, cash grants in lieu of tax credits and accelerated depreciation, among others.

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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.

Solar Regulatory Framework Applicable to Solar Power Plants Currently in Operation

The applicable legal framework for solar power plants already in operation is set out in four primary legal instruments:

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Royal Decree-law 9/2013, of July 12, containing emergency measures to guarantee the financial stability of the electricity system, referred to as Royal Decree-law 9/2013;

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Law 24/2013, of December 26, the Electricity Sector Act, referred to as the Electricity Act;

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Royal Decree 413/2014, of June 6, regulating electricity production from renewable energy sources, combined heat and power and waste, referred to as Royal Decree 413/2014; and

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Ministerial Order IET/1045/2014 of June 16, published on June 20, 2014, approving the remuneration parameters for standard facilities, applicable to certain electricity production facilities based on renewable energy, cogeneration and waste, referred to as 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:

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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.

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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.

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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:

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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.

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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.

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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 Royal Decree 413/2014 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.

Solaben 2 and Solaben 3 are on the registers of the autonomous region Extremadura and the Ministry of Industry, Energy and Tourism.

Solacor 1, Solacor 2, PS10 and PS20 are on the register of the autonomous region of Andalucia and the Ministry of Industry, Energy and Tourism.

To receive their facility-specific reimbursement, renewable energy facilities are required under the Electricity Act and Royal Decree 413/2014 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 Royal Decree 413/2014 states that power plants based on renewable sources recognized under the previous economic regime, as in the case of Solaben 2 and Solaben 3, Solacor 1 and Solacor 2, PS10 and PS20 will be automatically included in the Specific Payment System Register.

Change of Compensation System Applicable to Solar Power Plants

Royal Decree-law 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-law 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-law 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-law 9/2013 entered into force).

Prior to the adoption of Royal Decree-law 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 nine settlements that follow the approval of the new implementing regulations.

New System

According to Royal Decree-law 413/2014, producers now receive: (i) the pool price for the power they produce and (ii) a payment based on the standard investment cost for each type of plant (without any relation whatsoever to the amount of power they generate). This payment based on investment (in €/MW of installed capacity) is 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 imposed by Royal Decree-law 413/2014 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).

According to Royal Decree 413/2014, 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:

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The “standard per-MW investment value” is added to the “standard per-MW operating cost” (both updated from July 2013 with a 7.398% 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-law 9/2013 came into force.

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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-law 9/2013, also updated applying the 7.398% rate of return is subtracted.

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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.

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Payments for investment to be made after Royal Decree-law 9/2013 came into force and during every year of a plant’s remaining statutory useful life are calculated by (a) adding the net investment value (calculated as explained above) to the “expected operating costs until the end of the asset’s statutory useful life;” and (b) deducting the “expected revenue on the market up to that same point in time” (in both cases, the amount would be discounted to July 2013 by applying the 7.398% rate of return). The annual amount to be received would be calculated so that it would be the same amount every year until the end of the statutory useful life.

Accordingly, under Royal Decree 413/2014, the returns received by the owners of plants in excess of 7.398%, from start-up until Royal Decree-law 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 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.

Revenue Order recognizes 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) linear collectors and (vi) solar-biomass hybrids.

To determine the payment system applicable to each plant, the following factors are considered:

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Net investment value. This consists of a standard amount per MW for each type of plant, calculated by the method set out in Royal Decree 413/2014, which is the amount invested in the plant and not depreciated as of July 14, 2013.

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Useful life of the plant. For solar thermal plants this is 25 years.

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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.

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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.

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Maximum number of operating hours. A maximum number of hours is set for which each plant type can receive the operating remuneration.

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Operating threshold. Plants must operate for more than a set number of hours per year to receive the return on investment and operating remuneration.

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Minimum operating hours. Plants that cross the operating threshold but operate for fewer hours than the annual minimum hours receive a lower remuneration.

The payment criteria established in respect of Solaben 2, Solaben 3, Solacor 1, Solacor 2, PS 10 and PS 20 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		410,307		33,698		2,167		1,300		758
Solaben 3		25 years		410,307		33,698		2,167		1,300		758
Solacor 1		25 years		410,391		39,694		2,040		1,224		714
Solacor 2		25 years		410,391		39,694		2,040		1,224		714
PS 10		25 years		554,217		60,431		1,870		1,122		655
PS 20		25 years		410,683		54,654		1,870		1,122		655

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-law 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.

Annex III of the Revenue Order specifies that the 10-year average yield for the 10-year bond is 4.398%, which, increased by 300 bps, results in 7.398% per annum.

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.

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:

•

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

•

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 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 temporarily fund the tariff deficit in proportion to the costs that they represent for the electricity system in a given year and can recover these contributions in the following five years, plus interest at a market rate.

According to the Electricity Act, tariff deficit cannot exceed 2% of the estimated system revenues for each year. Furthermore, the accumulated debt due to previous’ years deficit cannot exceed 5% of the estimated system revenues for that period. If these thresholds are exceeded, the Spanish government is forced to review the access fees so that the system revenues increase accordingly.

Access Fee

Royal Decree-law 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-law 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-law 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, as amended, 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, 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.

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 investments during such period and have amounts pending to be deducted for this concept may apply such amounts with certain limitations.

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 2/3 and Solacor 1/2 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 National Interconnected System, Sistema Interligado Nacional, or 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 self-producer agents.

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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 20 years, and by Decree No. 2,003 of 1996, governing the independent producers’ and self-producers’ system.

Law No. 9,427 of 1996, as amended, inter alia, created ANEEL, the regulatory agency responsible for supervising the generation, 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 the rendering of public services of this nature and to grant certain authorizations. Law No. 9,478 of 1997, as amended, created the National Committee on Energy Policy, 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.

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:

•

the trading, import and export of power;

•

the division, into separate agreements, of the purchase and sale of energy, and the free access to the electric transmission and distribution systems;

•

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

•

the free negotiation of energy, within the scope of the Wholesale Market of Electricity, Mercado Atacadista de Energia Eletrica, 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.

This new institutional framework was established by Law No. 10,848 of 2004.

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, Camara de Comercializacao de Energia Eletrica, or CCEE, 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, which took over the responsibilities previously performed by MAE. This law further authorized the creation of the Committee on the Monitoring of the Electricity Sector, Comite de Monitoramento do Setor Eletrico, 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 of 2009, 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, 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. Law No. 12,767 of 2012 expressly sets forth that the possibility of resorting to the judicial or extrajudicial reorganization procedure under Law No. 11,101 of 2005 (Law on Corporate Reorganization and Bankruptcy) shall not apply to the electricity concessionaires which exploit public services while the concession is in force.

In addition, the Provisional Measure No. 579 of 2012, later converted into Law No. 12,783 of 2013, regulated, among others, by Decree No. 7,805 of 2012, sets forth the rules for further extending the concession contracts up to 30 years, for one period only.

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In March 2014, the federal government announced new measures to help distribution concessionaires reduce the immediate 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 amounted to R$12.4 billion and had been made available by the federal government (R$1.2 billion) and by loans (R$11.2), but will be untimely born by the consumers, as the electricity bills are going to increase between 2015 and 2017. The loans were obtained by the federal government from private or public banks and intermediated by the CCEE. In August 2014, a new loan to distribution concessionaires in the amount of R$6.6 billion has been approved by the federal government, following similar rules and for the same purpose. According to the information publicly available, a third loan to the distribution concessionaires in the amount of R$2.5 billion is currently under negotiation.

Another measure already implemented is a new energy auction in which the distributors are 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 first auction after the new regulation took place on April 30, 2014. MP 641 is no longer in force since July 21, 2014, but the rights and obligations created during its term are still valid and enforceable.

In November 2014, ANEEL approved new rules limiting the amount of the Price of Settlement of Differences, or PLD, in the spot market. PLD maximum value was reduced from R$822.83 to R$388.45 per MWh. The purpose of such change was to reduce the impact of high energy prices deriving from drought, delay in the commercial operation of hydroelectric plants and t-lines, and the high cost of thermal power plants. Certain power producers claimed that such new ANEEL rules are illegal because they affect power supply and demand.

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 the federal government by means of 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 concessionaire may use public land or request the granting authority to expropriate necessary private land for the benefit of the concessionaire. In this case, the concessionaire must compensate the affected private landowners. 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 Transmission Agreements and of Agreements for the Rendering of Supplementary Services, Contratos de Prestação de Servicos Ancilares. 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, Contrato de Conexao ao Sistema de Transmissao; (ii) Agreement for Facilities’ Sharing, Contrato de Compartilhamento de Instalacoes; and (iii) Agreement for the Connection to the Transmission Network—Adjustment Term, 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.

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There is also the Financial Guarantee Contract, 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.

Concessionaires’ Obligations

Besides the obligations set under the concession agreements, ANEEL regularly issues and publishes, in the Federal Official Gazette, Resolutions directed at the activities developed by the electricity sector. They are regulatory acts of general interest, with the object of establishing directives, obligations, tasks, conditions, limits, rules, procedures, requirements, or any other rights and duties of the agents and the users of the public service. Some of these rules, applicable to transmission concessionaires, are indicated below:

•

Full Performance Guarantee: The winner of the public auction shall grant a full compliance guarantee on behalf of ANEEL in order to ensure the compliance with the obligations established under the concession. Such guarantees may be replaced by lesser-value guarantees when ANEEL verifies the gradual execution of milestones in the implementation landmarks’ schedule (and, in such cases, the reduction shall be proportional to the implementation);

•

Changes in Controlling Interest: ANEEL must previously approve any change in the concessionaire’s indirect and direct controlling interest;

•

Agreements with Related Parties: ANEEL provides for specific rules on the transactions between agents of the electricity sector and related parties, especially concerning technology transfer, technical assistance, infrastructure sharing and provision of services. According to ANEEL’s Resolution No. 334 of 2008, some agreements shall be previously submitted to the Agency for approval;

•

Financing: ANEEL’s Resolution No. 532 of 2013 establishes limits that shall be observed by the concessionaire to offer to third parties the rights emerging from the concession, assets and future revenues related to the concession as guarantee in financing agreements. Notwithstanding the general rule that the grant of a security interest on concession rights requires ANEEL’s prior approval, such approval will not be required, for example, in the following situations: (a) project finance guarantee packages for new transmission projects; and (b) regulated auctions for new projects that require a guarantee; and

•

Expiration: When the concession expires, all assets, rights and privileges that are materially related to the rendering of the services revert to the Brazilian government. Following the expiration, the concessionaire is entitled to indemnification for its investments in assets that have not been fully amortized or depreciated on the expiration date.

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, 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, 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, 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 12 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.

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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.

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, as amended.

Improvement is defined as any installation, replacement or remodeling of equipment in order to ensure adequate electricity transmission services, pursuant to the relevant concession agreement.

Reinforcement is defined as the implementation of new electricity transmission facilities, or replacement or adjustment of existing facilities in order to increase the electricity transmission capacity, the reliability of the SIN, the useful life or to connect users. Some Reinforcements are subject to prior authorization by ANEEL and 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.

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C.	Organizational Structure

The following summary chart sets forth our ownership structure as of the date of this annual report:

LOGO

(1)	Abengoa Yield directly holds one share in Palmucho and 10 shares in each of Quadra 1 and Quadra 2.

(2)	ACIN directly holds one share in each of ACP and Abengoa Transmision Norte, a Mexican subsidiary of Abengoa.

(3)	We do not have control over ACBH. See “Item 4.B—Business—Our Operations—Exchangeable Preferred Equity Investment in Abengoa Concessoes Brasil Holding.”

(4)	Due to Mexican legal requirements, one share is held by Servicios Auxiliares de Administracion, S.A. de C.V., a Mexican subsidiary of Abengoa.

(5)	One share is held by Abengoa Mexico, S.A. de C.V. (a Mexican subsidiary of Abengoa) and Abener Energia, S.A. (a Spanish subsidiary of Abengoa).

(6)	JGC Corporation, a Japanese engineering company, holds 26% of the shares in each of Solacor 1 and Solacor 2. We hold a 30-year right of usufruct over the remaining shares of Solacor 1 and Solacor 2 and a call option to purchase such shares for one euro during a four-year term.

(7)	Itochu Corporation, a Japanese trading company, holds 30% of the shares in each of Solaben 2 and Solaben 3. We hold a 30-year right of usufruct over the remaining shares of Solaben 2 and Solaben 3 and a call option to purchase such shares for one euro during a four-year term.

(8)	AEC holds 49% and Sadyt holds 16.83% of Skikda.

(9)	AEC holds 49% and Sadyt holds 25.5% of Honaine.

D.	Property, Plant and Equipment

See “Item 4.B—Business Overview.”

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ITEM 4A.

UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 5.

OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following discussion should be read together with, and is qualified in its entirety by reference to, our Annual Consolidated Financial Statements. 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 as a result of various factors, including those set forth under “Item 3.D—Risk Factors” and elsewhere in this annual report.

The following discussion analyzes our historical financial condition and results of operations. For all periods prior to our IPO, the discussion reflects the combined financial statements of our predecessor, which represents the combination of the assets transferred by Abengoa to us immediately prior to the consummation of our IPO. For all periods subsequent to our IPO, the discussion reflects our and our subsidiaries’ consolidated results.

A.	Operating Results

Overview

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On November 18, 2014, we completed the acquisition of Solacor 1/2 through a 30-year usufruct rights contract over the related shares (which includes the option to purchase such shares for one euro during a four-year term); on December 4, 2014, we completed the acquisition of PS10/20; and on December 29, 2014, we completed the acquisition of Cadonal. Together, these three First Dropdown Assets, which we agreed in September 2014 to acquire from Abengoa under the ROFO Agreement, comprise an aggregate of 131 MW of solar power generation and 50 MW of wind power generation. See “Item 4.B—Business Overview—Our Operations—Renewable Energy” for a description of such assets. The total aggregate consideration for the First Dropdown Assets was $312 million (which consideration was determined in part by converting the portion of the purchase price of Solacor 1/2 and PS10/20 denominated in euros into U.S. dollars based on the exchange rate on the date on which the payment was made).

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of our Spanish assets) with low-risk off-takers and collectively have a weighted average remaining contract life of approximately 24 years as of December 31, 2014. We expect that the majority of our cash available for distribution over the next four years will be in U.S. dollars, indexed to the U.S. dollar or in euros. We intend to use currency hedging contracts to maintain a ratio of 90% of our cash available for distribution denominated in U.S. dollars. 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 Further Adjusted EBITDA by geography and business sector for the years ended December 31, 2014, 2013 and 2012 are set forth in the following tables:

Revenue by geography


	Year ended December 31,
Revenue by geography	2014				2013				2012
	$ in millions		% of revenue		$ in millions		% of revenue		$ in millions		% of revenue
North America		195.5		53.9		114.0		54.1		62.3		58.1
South America		83.6		23.0		25.4		12.0		17.0		15.9
Europe		83.6		23.1		71.5		33.9		27.9		26.0


Total revenue		362.7		100.0		210.9		100.0		107.2		100.0

Revenue by business sector


	Year ended December 31,
Revenue by business sector	2014				2013				2012
	$ in millions		% of revenue		$ in millions		% of revenue		$ in millions		% of revenue
Renewable energy		170.7		47.1		82.7		39.2		27.9		26.1
Conventional power		118.8		32.7		102.8		48.7		62.3		58.1
Electric transmission lines		73.2		20.2		25.4		12.1		17.0		15.8


Total revenue		362.7		100.0		210.9		100.0		107.2		100.0

Further Adjusted EBITDA by geography


	Year ended December 31,
Further Adjusted EBITDA by geography	2014				2013				2012
	$ in millions		% of revenue		$ in millions		% of revenue		$ in millions		% of revenue
North America		175.4		89.7		96.7		84.8		61.1		98.1
South America		77.2		92.3		19.0		74.8		10.2		60.0
Europe		55.4		66.3		42.8		59.9		16.6		59.5


Further Adjusted EBITDA⁽¹⁾		308.0		84.9		158.5		75.2		87.9		82.0

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Further Adjusted EBITDA by business sector


	Year ended December 31,
Further Adjusted EBITDA by business sector	2014				2013				2012
	$ in millions		% of revenue		$ in millions		% of revenue		$ in millions		% of revenue
Renewable energy		137.8		80.7		55.8		67.5		16.1		57.6
Conventional power		101.9		85.8		83.3		81.0		61.1		98.0
Electric transmission lines		68.3		93.3		19.4		76.4		10.7		63.6


Further Adjusted EBITDA⁽¹⁾		308.0		84.9		158.5		75.2		87.9		82.0

(1)

Factors Affecting the Comparability of 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 significantly affect our revenue and operating profit, which makes the comparison of periods difficult.

The following table sets forth the principal projects that commenced operations during 2014, 2013 and 2012, including the quarter in which operations began.

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

Operational

4Q 2014

ACT

Conventional power

300 MW

Operational

2Q 2013

South America

ATS

Electric transmission

569 miles

Operational

1Q 2014

Quadra 1

Electric transmission

49 miles

Operational

2Q 2014

Quadra 2

Electric transmission

38 miles

Operational

1Q 2014

Palmatir

Renewable energy

50 MW

Operational

2Q 2014

Europe

Solaben 2

Renewable energy

50 MW

Operational

2Q 2012

Solaben 3

Renewable energy

50 MW

Operational

4Q 2012

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Acquisitions

On November 18, 2014, we completed the acquisition of Solacor 1/2 through a 30-year usufruct rights contract over the related shares (which includes an option to purchase such shares for one euro during a four-year term); on December 4, 2014, we completed the acquisition of PS10/20; on December 29, 2014, we completed the acquisition of Cadonal. Solacor 1/2 has a capacity of 100 MW, PS10/20 has a capacity of 31 MW and Cadonal has a capacity of 50 MW. Solacor 1/2 and PS10/20 are solar power plants located in Spain and Cadonal is an on-shore wind farm located in Uruguay. See “Item 4.B—Business Overview—First Dropdown Assets.” We have consolidated the results of operations of the new assets acquired since the date of each acquisition.

In addition, on February 3, 2015, we completed the acquisition of a 25.5% stake in Honaine and a 34.17% stake in Skikda, two water desalination plants in Algeria with an aggregate capacity of 10.5 M ft3 per day. Also, the completion of the acquisition of the 40% stake in ATN2, an 81-mile transmission line in Peru, a 29.6% stake in Helioenergy 1/2, a 100 MW solar power asset in Spain, and a 20% stake in Shams, a 100 MW solar power asset in the United Arab Emirates, is subject to satisfaction of customary conditions, including approvals from financing institutions and, in certain cases, from partners in joint ventures. In the case of ATN2, the acquisition is also subject to the beginning of the generation of revenues by the project, unless such conditions are waived by Abengoa and us. If the conditions are not met by June 30, 2015, each party may terminate the agreement. See “Item 4.B—Business Overview—Second Dropdown Assets.”

These acquisitions, and any other acquisitions we may make from time to time (including the acquisition of the Second Dropdown Assets in 2015), will affect the comparability of our results.

We do not include pro forma information on the acquisitions because we do not believe that pro forma information is useful to investors as the First Dropdown Assets are already included in the consolidated statement of financial position as of December 31, 2014 and because we do not consider the acquisition of the Second Dropdown Assets to be material.

Factors Affecting Our Results of Operations

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 “Item 4.B—Business Overview—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, 2014, the average remaining life of our PPAs, concessions and contracted revenue agreements was approximately 24 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.

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.

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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 2/3 and Solacor 1/2 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 our IPO (which was consummated in June 2014) due to the NOL carryforwards generated during the construction phase.

Capital expenditures

We finance our contracted assets primarily through project debt issued by a financial institution. Consequently, a significant part of our business is capital-intensive and our assets are highly leveraged. See “Item 5.B—Liquidity and Capital Resources—Capital expenditures.”

Interest rates

We incur significant indebtedness at the corporate level and in our assets. The interest rate risk arises mainly from indebtedness with variable interest rates. In November 2014, we incurred significant indebtedness at the corporate level through the issuance of the 2019 Notes, which have an interest rate of 7.000%. See “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—2019 Notes.” We have also entered into the Credit Facility under which loans accrue interest at a rate per annum equal to: (A) for Eurodollar rate loans, LIBOR plus 2.75% and (B) for base rate loans, the highest of (i) the rate per annum equal to the weighted average of the rates on overnight U.S. Federal funds transactions with members of the U.S. Federal Reserve System arranged by U.S. Federal funds brokers on such day plus 1/2 of 1.00%, (ii) the U.S. prime rate and (iii) LIBOR plus 1.00%, in any case, plus 1.75%. See “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—Credit Facility.” 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, South America and Africa 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. Our solar power plants in Spain, Solaben 2/3, Solacor 1/2 and PS10/20, have their revenues and expenses denominated in euros.

Fluctuations in the value of foreign currencies (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 “Item 11—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.

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The following table sets forth, for the periods indicated, the Noon Buying Rate certified by the Federal Reserve Bank of New York expressed in U.S. dollar per €1.00. The Noon Buying Rate refers to the exchange for euro, expressed in U.S. dollars per euro, in the City of New York for cable transfers payable in foreign currencies as certified by the Federal Reserve Bank of New York for customs purposes. The rates may differ from the actual rates used in the preparation of the Consolidated Financial Statements and other financial information appearing in this annual report. We do not represent that the U.S. dollar amounts referred to below could be or could have been converted into euro at any particular rate indicated or any other rate.

The average rate of the Noon Buying Rate means the average rates for the euro on the last day reported of each month during the relevant period.

The Federal Reserve Bank of New York Noon Buying Rate of the euro on February 13, 2015 was $1.1408 per €1.00.


	U.S. Dollar per €1.00
	High		Low		Average		Period End
Year
2012		1.3463		1.2062		1.2909		1.3186
2013		1.3816		1.2774		1.3303		1.3779
2014		1.3927		1.2101		1.3296		1.2101
Month
August 2014		1.3436		1.3150		1.3315		1.3150
September 2014		1.3136		1.2628		1.2889		1.2628
October 2014		1.2812		1.2517		1.2677		1.2530
November 2014		1.2554		1.2394		1.2472		1.2438
December 2014		1.2504		1.2101		1.2329		1.2101
January 2015		1.2015		1.1279		1.1615		1.1290
February 2015 (through February 13, 2015)		1.1462		1.1300		1.1373		1.1408

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.

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	As of December 31,
Key Performance Indicator	2014			2013			2012

Renewable energy
MW in operation		891			380			100
GWh produced		902			280			75

Conventional power
MW in operation		300			300			—
GWh produced		2,474			1,849			—
Availability (%)		101.9	%		97.0	%		—
Electric transmission lines
Miles in operation		1,018			368			368
Availability		99.1	%		99.6	%		99.2	%

Results of Operations

The table below illustrates our results of operations for the years ended December 31, 2014, 2013 and 2012.


	Year ended December 31,
	2014			2013			2012
	($ in millions)

Operating revenues and costs

Revenue		362.7			210.9			107.2
Other operating income		79.9			379.6			560.4
Raw materials and consumables used		(21.3	)		(8.7	)		(4.3	)
Employee benefit expense		(1.7	)		(2.4	)		(1.8	)
Depreciation, amortization and impairment charges		(125.5	)		(46.9	)		(20.2	)
Other operating expenses		(120.8	)		(420.9	)		(573.6	)


Operating profit/(loss)		173.3			111.6			67.7


Financial income		4.9			1.2			0.7
Financial expense		(210.3	)		(123.8	)		(64.1	)
Net exchange differences		2.1			(0.9	)		0.4
Other financial income/(expense), net		5.9			(1.7	)		(0.2	)


Financial expense, net		(197.4	)		(125.2	)		(63.2	)


Share of profit/(loss) of associates carried under the equity method		(0.8	)		—			(0.4	)


Profit/(loss) before income tax		(24.9	)		(13.6	)		4.1


Income tax		(4.4	)		11.8			(4.0	)


Profit/(loss) for the year		(29.3	)		(1.8	)		0.1


Profit/(loss) attributable to non-controlling interest		(2.3	)		(1.6	)		1.2

Profit/(loss) for the year attributable to the parent company		(31.6	)		(3.4	)		1.3

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Comparison of the Years Ended December 31, 2014 and 2013

Revenues

Revenues increased by 72.0% to $362.7 million in the year ended December 31, 2014, compared with $210.9 million for the year ended December 31, 2013. The increase is largely attributable to the commencement of operations of Solana in the last quarter of 2013 and to the entry into operation of ATS in the first quarter of 2014. The increase was also due to the entry into operation of ACT in the second quarter of 2013, Quadra 1 and 2 in the first and second quarters of 2014 and Palmatir in the second quarter of 2014. The acquisition of Solacor 1/2 on November 18, 2014 and PS10/20 on December 4, 2014 also contributed to the increase in revenues in the year ended December 31, 2014 as compared with the year ended December 31, 2013. Finally, the increase in revenues was also due to the entry into operation of Mojave in December 2014. These resulted in a net electricity production of 3,375 GWh and 1,018 miles of transmission lines in operation for the year ended December 31, 2014, compared with 2,129 GWh produced and 368 miles of transmission lines in operation during the year ended December 31, 2013. The impact of exchange rates was immaterial in the year ended December 31, 2014, as it caused less than a 0.1% change in revenues.

Other operating income

The following table sets forth our other operating income for the years ended December 31, 2014 and 2013:


	Year ended December 31,
Other operating income	2014		2013
	$ in millions

Grants		35.2		10.1
Income from various services		6.1		4.8
Income from subcontracted construction services for our assets and concessions		38.6		364.7


Total		79.9		379.6

Other operating income decreased by 79.0% to $79.9 million for the year ended December 31, 2014, compared with $379.6 million for the year ended December 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 and its corresponding cost decreased by 89.4% to $38.6 million for the year ended December 31, 2014, compared with $364.7 million for the year ended December 31, 2013. These amounts reflect the construction progress of the assets and concessions during the years of 2014 and 2013. The decrease was primarily due to the completion of construction of ATS, ACT, Mojave, Quadra 1, Quadra 2, Palmatir and Solana. We do not expect to have significant other operating income from construction activities in future periods. In addition, the increase in grants is related to the financial support provided by the U.S. Treasury to Solana. An ITC cash grant was received in March 2014 and is being recorded in “Other operating income” progressively over the useful life of the asset.

Raw materials and consumables used

Raw materials and consumables used increased by $12.6 million to $21.3 million for the year ended December 31, 2014, compared with $8.7 million for the year ended December 31, 2013, primarily due to the commencement of operations of Solana in the last quarter of 2013.

Employee benefits expenses

Employee benefit expenses decreased by 29.2% to $1.7 million for the year ended December 31, 2014, compared with $2.4 million for the year ended December 31, 2013. These expenses were primarily attributable to ATN whose employees were transferred to an entity excluded from the perimeter of Abengoa Yield in April 2014. As of the date of this annual report, we had seven employees, all in one of our solar power assets in Spain.

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Depreciation, amortization and impairment charges

Depreciation, amortization and impairment charges increased by 167.6% to $125.5 million for the year ended December 31, 2014, compared with $46.9 million for the year ended December 31, 2013. Depreciation and amortization are recorded from the commencement of operations of the contracted assets. The net change was largely attributable to the increase in depreciation and amortization resulting from the commencement of operations of Solana and ATS and, to a lesser extent, to the commencement of operations of Mojave and Palmatir.

Other operating expenses

The following table sets forth our other operating expenses for the years ended December 31, 2014 and 2013:


	Year ended December 31,
	2014					2013
Other operating expenses	$ in millions		% of revenue			$ in millions		% of revenue
Leases and fees		1.8		0.5	%		1.8		0.9	%
Repairs and maintenance		10.3		2.8	%		12.8		6.1	%
Independent professional services⁽¹⁾		26.2		7.2	%		22.6		10.7	%
Transportation		0.1		—			0.4		0.2	%
Supplies		7.6		2.1	%		3.3		1.6	%
Other external services		10.2		2.8	%		5.5		2.6	%
Levies and duties		14.2		3.9	%		6.6		3.1	%
Other expenses		11.8		3.3	%		3.2		1.5	%
Construction costs		38.6		10.6	%		364.7		172.9	%


Total		120.8		33.3	%		420.9		199.6	%

(1)	Includes approximately $3.8 million in the year ended December 31, 2014 and $3.5 million in the year ended December 31, 2013 of allocated costs and expenses for general and administrative services provided by Abengoa prior to our IPO.

Other operating expenses decreased by 71.3% to $120.8 million for the year ended December 31, 2014, compared with $420.9 million for the year ended December 31, 2013. This was primarily due to the decrease in construction costs by 89.4% to $38.6 million for the year ended December 31, 2014 compared with $364.7 million for the year ended December 31, 2013. This decrease was primarily due to the completion of construction of ATS, ACT, Mojave, Quadra 1, Quadra 2, Palmatir and Solana. On the other hand, the commencement of operation of these assets increased expenses in supplies, other external services, levies and duties, as well as other expenses.

Operating profit/(loss)

As a result of the above factors, operating profit increased by 55.3% to $173.3 million for the year ended December 31, 2014, compared with $111.6 million for the year ended December 31, 2013.

Financial income

Financial income increased to $4.9 million for the year ended December 31, 2014, compared with $1.2 million for the year ended December 31, 2013, due to the interest generated by the cash at hand we held during the year.

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Financial expense

The following table sets forth our financial expense for the years ended December 31, 2014 and 2013:


	Year ended December 31,
Financial expense	2014		2013
	$ in millions

Expenses due to interest:
Loans from credit entities		117.7		78.6
Other debts		61.9		17.2
Interest rates losses derivatives: cash flow hedges		30.7		28.0


Total		210.3		123.8

Financial expense increased by 69.8% to $210.3 million for the year ended December 31, 2014, compared with $123.8 million for the year ended December 31, 2013. This increase was largely attributable to interest expenses from Solana and, to a lower extent, from ATS, which entered into operation during the last quarter of 2013 and first quarter of 2014, respectively. Interest is capitalized for our intangible concessional assets during the construction period and begins to be expensed upon commercial operation. Interest on other debts correspond to interest on ATS and ATN bonds and interest on debt with related parties, which was capitalized in its majority before our IPO. Interest expense also increased due to the interest corresponding to the 2019 Notes and to the Credit Facility. Interest on interest-rate derivatives designated as cash flow hedges of $30.7 million in 2014 was due to transfers from equity to financial expense in accordance with our cash flow hedge accounting policy, and was mainly related to ACT and Solaben 2/3.

Net exchange differences

Net exchange differences increased to an income of $2.1 million for the year ended December 31, 2014, compared with a loss of $0.9 million for the year ended December 31, 2013. Positive exchange differences were primarily due to the depreciation of a euro denominated debt with Cofides in ATS. This debt was repaid in October and, as a result, we do not expect significant exchange rate differences in the future.

Other financial income/(expense), net


	Year ended December 31,
Other financial income/(expenses)	2014			2013
	$ in millions
Dividend ACBH (Brazil)		9.2			—
Other financial income		0.6			0.6
Other financial losses		(3.9	)		(2.2	)
Outsourcing of payables		—			(0.1	)


Total		5.9			(1.7	)

Other financial income, net increased to $5.9 million for the year ended December 31, 2014, compared with a $1.7 million financial expense, net for the year ended December 31, 2013. The increase was mainly due to the dividends received from our preferred equity investment in ACBH since our IPO in a total amount of $9.2 million during the year ended December 31, 2014. Other financial expenses mainly include guarantees and letters of credit, wire transfers and other bank fees and other minor financial expenses.

Financial expense, net

Net financial expense increased by 57.7% to $197.4 million for the year ended December 31, 2014, compared with $125.2 million for the year ended December 31, 2013. This increase was primarily attributable to the aforementioned change in financial expense.

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Profit/(loss) before income tax

As a result of the above factors, we reported a loss amounting to $24.9 million for the year ended December 31, 2014, compared with a loss before income taxes of $13.6 million for the year ended December 31, 2013.

Income tax

Income tax expense amounted to $4.4 million for the year ended December 31, 2014, compared with an income tax benefit of $11.8 million for the year ended December 31, 2013. Our effective tax rate differs from the average nominal tax rate mainly due to permanent differences and treatment of tax credits in some jurisdictions.

Loss/(profit) attributable to non-controlling interest

Profit attributable to non-controlling interest increased by 43.8% to $2.3 million in the year ended December 31, 2014, compared with $1.6 million in the year ended December 31, 2013. Profit attributable to non-controlling interest corresponds to the results from Solaben 2/3 and Solacor 1/2, and the increase was due to a higher profit of Solaben for the year ended December 31, 2014 as compared with the year ended December 31, 2013.

Profit/(loss) attributable to the parent company

As a result of the above factors, loss attributable to the parent company increased to $31.6 million for the year ended December 31, 2014, compared with a loss attributable to the parent company of $3.4 million for the year ended December , 2013.

Total comprehensive income/(loss)

Total comprehensive loss attributable to the parent company amounted to $128.7 million for the year ended December 31, 2014 compared with total comprehensive income of $69.8 million for the year ended December 31, 2013. The loss for the year ended December 31, 2014 was mainly due to the change in fair value of our cash flow hedges recognized directly in equity in accordance with hedge accounting. The loss results mainly from a decrease in the fair value of long-term interest rate swaps due to a decrease in future interest rates during the year 2014. For the year ended December 31, 2013, the change in the fair value of cash flow hedges was a net income, mainly as a result of an increase in the fair value of long-term interest rate swaps, due to an increase in future interest rates during the year 2013.

Comparison of the 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 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 2/3, 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.

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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 2013 and 2012, 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. Treasury 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 2/3, 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 2/3.

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,
	2013					2012
Other operating expenses	$ 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⁽¹⁾		22.6		10.7	%		9.6		9.0	%
Transportation		0.4		0.2	%		0.3		0.3	%
Supplies		3.3		1.6	%		0.7		0.7	%
Other external services		5.5		2.5	%		1.8		1.6	%

118


	Year ended December 31,
	2013					2012
Other operating expenses	$ in millions		% of revenue			$ in millions		% of revenue
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	%

(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 2/3, 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/(loss)

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 2/3.

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

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 2/3, 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.

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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 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

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.

Loss/(profit) attributable to non-controlling interest

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

Profit/(loss) attributable to the parent company

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

As of December 31, 2014, we organized our business into the following three geographies where the contracted assets and concessions are located:

•

North America;

•

South America; and

•

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 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 includes our activities related to the operation of electric transmission lines.

As a result we report our results through the year ended December 31, 2014 in accordance with both criteria.

Beginning on January 1, 2015, we report Water as a new business sector and have expanded our geography reporting from Europe to EMEA as a result of our acquisition of a 25.5% stake in Honaine and a 34.17% stake in Skikda, two water desalination plants in Algeria.

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Comparison of the Year Ended December 31, 2014 and 2013

Revenue and Further Adjusted EBITDA by geography

The following table sets forth our revenue, Further Adjusted EBITDA and volumes for the years ended December 31, 2014 and 2013, by geographic region:


	Year ended December 31,
	2014				2013
Revenue by geography	$ in millions		% of revenue		$ in millions		% of revenue
North America		195.5		53.9		114.0		54.1
South America		83.6		23.0		25.4		12.0
Europe		83.6		23.1		71.5		33.9


Total revenue		362.7		100.0		210.9		100.0


	Year ended December 31,
	2014				2013
Further Adjusted EBITDA by geography	$ in millions		% of revenue		$ in millions		% of revenue
North America		175.4		89.7		96.7		84.8
South America		77.2		92.3		19.0		74.8
Europe		55.4		66.3		42.8		59.9


Further Adjusted EBITDA⁽¹⁾		308.0		84.9		158.5		75.2

(1)


	Volume sold
	Year ended December 31,
Volume by geography	2014		2013
North America (GWh)		3,083		1,938
South America (miles in operation)		1,018		368
South America (GWh)		109		—
Europe (GWh)		185		191

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North America. Revenues increased by 71.5% to $195.5 million for the year ended December 31, 2014, compared with $114.0 million for the year ended December 31, 2013. The increase was primarily due to the commencement of operations of Solana in the last quarter of 2013 and, to a lesser extent, of ACT in the second quarter of 2013 and Mojave during the fourth quarter of 2014. As a result, Further Adjusted EBITDA increased to $175.4 million for the year ended December 31, 2014 compared with $96.7 million for the year ended December 31, 2013. Further Adjusted EBITDA margin has increased as a result of the projects that have entered into operation.

South America. Revenue increased by 229.1% to $83.6 million for the year ended December 31, 2014, compared with $25.4 million for the year ended December 31, 2013. The increase was mostly attributable to the commencement of operations of ATS in the first quarter of 2014 and, to a lower extent, of Palmatir in the second quarter at 2014. Thus, Further Adjusted EBITDA amounted to $77.2 million for the year ended December 31, 2014, which represents an increase of $58.2 million as compared with the year ended December 31, 2013. Further Adjusted EBITDA margin has increased as a result of dividends received from our preferred equity investment in ACBH and of higher margins in the projects that have entered into operation.

Europe. Revenue increased by 16.9% to $83.6 million for the year ended December 31, 2014, compared with $71.5 million for the year ended December 31, 2013. The increase is mainly attributable to the acquisition of Solacor 1/2 and PS10/20 during the fourth quarter of 2014. As a result, Further Adjusted EBITDA increased to $55.4 million for the year ended December 31, 2014, compared with $42.8 million for the year ended December 31, 2013.

Revenue and Further Adjusted EBITDA by business sector

The following table sets forth our revenue, Further Adjusted EBITDA and volumes for the years ended December 31, 2014 and 2013 by business sector:


	Year ended December 31,
	2014				2013
Revenue by business sector	$ in millions		% of revenue		$ in millions		% of revenue
Renewable energy		170.7		47.1		82.7		39.2
Conventional power		118.8		32.7		102.8		48.7
Electric transmission lines		73.2		20.2		25.4		12.1


Total revenue		362.7		100.0		210.9		100.0


	Year ended December 31,
	2014				2013
Further Adjusted EBITDA by business sector	$ in millions		% of revenue		$ in millions		% of revenue
Renewable energy		137.8		80.7		55.8		67.5
Conventional power		101.9		85.8		83.3		81.0
Electric transmission lines		68.3		93.3		19.4		76.4


Further Adjusted EBITDA⁽¹⁾		308.0		84.9		158.5		75.2

(1)

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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 Further 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. Further 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. Further Adjusted EBITDA may not be indicative of our historical operating results, nor is it meant to be predictive of potential future results. See “Presentation of Financial Information—Non-GAAP Financial Measures.”


	Volume sold
	Year ended December 31,
Volume by business sector	2014		2013
Renewable energy (GWh)		902		280
Conventional power (GWh)		2,474		1,849
Electric transmission lines (miles in operation)		1,018		368

Renewable energy. Revenue increased by 106.4% to $170.7 million for the year ended December 31, 2014, compared with $82.7 million for the year ended December 31, 2013. The increase was mainly attributable to the projects that entered into operation during 2014 and in the last quarter of 2013, comprised of Mojave, Palmatir and Solana. Additionally, the acquisition of Solacor 1/2 on November 18, 2014 and PS10/20 on December 4, 2014 also contributed to the increase in production and revenues in the year ended December 31, 2014 as compared with the year ended December 31, 2013. As a consequence, the capacity in terms of installed MW available throughout the year increased by 511 MW, driving total capacity to 891 MW as of December 31, 2014. This resulted in a net electricity production of 902 GWh for the year ended December 31, 2014 compared with 280 GWh produced during the year ended December 31, 2013. Further Adjusted EBITDA amounted to $137.8 million for the year ended December 31, 2014, which represented an increase of $82.0 million with respect to the year ended December 31, 2013, mainly due to the effect of the new projects entering into operation and acquisitions. Further Adjusted EBITDA margin has increased as well as a result of the projects that have entered into operation, with a higher margin than the projects in operation in the year ended December 31, 2013.

Conventional power. Revenue increased by 15.5% to $118.8 million for the year ended December 31, 2014, compared with $102.8 million for the year ended December 31, 2013. The increase was due to the commencement of operations of ACT during the second quarter of 2013. This resulted in net electricity production of 2,474 GWh for the year ended December 31, 2014 compared to 1,849 GWh for the year ended December 31, 2013. As a consequence, Further Adjusted EBITDA increased to $101.9 million for the year ended December 31, 2014, from $83.3 million for the year ended December 31, 2013.

Electric transmission lines. Revenue increased by 188.2% to $73.2 million for the year ended December 31, 2014, compared with $25.4 million for the year ended December 31, 2013. The increase was mostly attributable to the commencement of operations of ATS in the first quarter of 2014. Thus, Further Adjusted EBITDA amounted to $68.3 million for the year ended December 31, 2014, an increase of $48.8 million compared with the year ended December 31, 2013. Further Adjusted EBITDA margin has increased as a result of higher margins in the projects that have entered into operation and dividends received from our preferred equity investment in ACBH.

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Comparison of the Years Ended December 31, 2013 and 2012

Revenue and Further Adjusted EBITDA by geography

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


	Year ended December 31,
	2013				2012
Revenue by geography	$ 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,
	2013				2012
Further Adjusted EBITDA by geography	$ 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		16.6		59.5


Further Adjusted EBITDA⁽¹⁾		158.5		75.2		87.9		82.0

(1)


	Volume sold
	Year ended December 31,
Volume by geography	2013		2012
North America (GWh)		1,938		—
South America (miles in operation)		368		368
Europe (GWh)		191		75

North America. Revenues increased by 82.9% 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, Further 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, Further 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 2/3, which entered into operation during 2012. As a result, Further Adjusted EBITDA increased to $42.8 million for the year ended December 31, 2013, compared with $16.6 million for the same period in 2012.

Revenue and Further Adjusted EBITDA by business sector

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


	Year ended December 31,
	2013				2012
Revenue by business sector	$ 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 lines		25.4		12.1		17.0		15.9


Total revenue		210.9		100.0		107.2		100.0


	Year ended December 31,
	2013				2012
Further Adjusted EBITDA by business sector	$ in millions		% of revenue		$ in millions		% of revenue
Renewable energy		55.8		67.5		16.1		57.6
Conventional power		83.3		81.0		61.1		98.0
Electric transmission lines		19.4		76.4		10.7		63.6


Further Adjusted EBITDA⁽¹⁾		158.5		75.2		87.9		82.0

(1)

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	Volume sold
	Year ended December 31,
Volume by business sector	2013		2012
Renewable energy (GWh)		280		75
Conventional power (GWh)		1,849		—
Electric transmission lines (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 2/3 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 year 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, Further 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.

Conventional power. Revenue increased by 65% 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, Further 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 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 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, Further Adjusted EBITDA amounted to $19.4 million for the year ended December 31, 2013, an increase of $8.7 million compared with the year ended December 31, 2012.

B.	Liquidity and Capital Resources

The liquidity and capital resources discussion which follows contains certain estimates as of the date of this annual report of our 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 annual report. 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,

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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. None of us, or our board of directors, 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 annual report of these estimates should not be deemed an admission or representation by us or our board of directors that such information is viewed by us or our board of directors 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 annual report. None of us, or our board of directors, 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 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 “Item 3.D—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 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. In addition, during the fourth quarter of 2014, we issued the 2019 Notes and entered into the Credit Facility. 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 “Item 3.D—Risk Factors” in this annual report and other factors 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 “Item 4.B—Business Overview—Our Growth Strategy”).

Liquidity position

As of December 31, 2014, our cash and cash equivalents at the project company level were $198.8 million as compared with $357.7 million as of December 31, 2013. In addition, our cash and cash equivalents at the Abengoa Yield plc level were $155.4 million as of December 31, 2014.

On November 17, 2014 we issued the 2019 Notes in an aggregate principal amount of $255 million. The 2019 Notes accrue annual interest of 7.000% payable semi-annually beginning on May 15, 2015 until their maturity date of November 15, 2019. In the event that we do not obtain a public credit rating for the 2019 Notes from each of S&P and Moody’s prior to November 15, 2015, the interest rate per annum accruing on the 2019 Notes will increase by 0.75%, to 7.750%, on and after November 15, 2015 until the date on which we have obtained a public credit rating for the 2019 Notes from each of S&P and Moody’s.

On December 3, 2014, we entered into the Credit Facility in the total amount of up to $125 million. On December 22, 2014, we drewdown $125 million under the Credit Facility. We used a portion of the proceeds of the Credit Facility to finance the acquisition of Cadonal and we expect to use the balance to finance the acquisition of the Second Dropdown Assets and for general corporate purposes. Loans under the Credit Facility accrue interest at a rate per annum equal to: (A) for Eurodollar rate loans, LIBOR plus 2.75% and (B) for base rate loans, the highest of (i) the rate per annum equal to the weighted average of the rates on overnight U.S. Federal funds transactions with members of the U.S. Federal Reserve System arranged by U.S. Federal funds brokers on such day plus 1/2 of 1.00%, (ii) the U.S. prime rate and (iii) LIBOR plus 1.00%, in any case,

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plus 1.75%. Loans under the Credit Facility will mature on the fourth anniversary of the closing date of the Credit Facility. Loans prepaid by us under the Credit Facility may be reborrowed. The Credit Facility is secured by pledges of the shares of the guarantors which we own.

The proceeds of the 2019 Notes were used, together with a portion of the proceeds of the Credit Facility, to finance in part the acquisition of the First Dropdown Assets. See “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—2019 Notes” and “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—Credit Facility.”

In addition, in February 2015, pursuant to the ROFO Agreement, we agreed to acquire the Second Dropdown Assets from Abengoa, which comprise an aggregate of 200 MW of solar power generation, 10.5 M ft3 per day of water desalination and an 81-mile transmission line. The total aggregate consideration for the Second Dropdown Assets will be $142 million and will be financed with a portion of the proceeds of the Credit Facility and available cash. See “Item 4.B—Business Overview—Second Dropdown Assets.”

Sources of liquidity

We expect our ongoing sources of liquidity to include cash on hand, cash generated from our operations, project debt arrangements, corporate debt and the issuance of additional equity securities, as appropriate, given market conditions. Any issuance of equity securities would require waivers in some of our project-level financings if it results in Abengoa becoming a minority shareholder. Our financing agreements consist mainly of the project-level financings for our various assets, the 2019 Notes and the Credit Facility.

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.

Furthermore, on June 13, 2014, we entered into a Financial Support Agreement under which Abengoa has agreed to facilitate a new $50 million revolving credit line and maintain any guarantees and letters of credit that have been provided by it on behalf of or for the benefit of us and our affiliates for a period of five years. As of the date of this annual report, the total amount of the credit line remained undrawn.

We believe that our existing liquidity position and cash flows from operations will be sufficient to meet our requirements and commitments for the next 12 months, 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, 2014 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)

North America

2,121.9

274.8

106.5

130.4

1,609.8

South America

804.5

19.3

29.8

34.9

720.6

Europe

896.7

37.2

81.6

93.3

684.6

Total project debt

3,823.1

331.3

218.2

258.6

3,015.0

Corporate debt

378.4

2.2

—

376.2

—

Total

4,201.5

333.5

218.2

634.8

3,015.0

128

Repayment schedule by business sector

Total

Up to one
year

Between one
and three
years

Between three
and five years

Subsequent
years

($ in millions)

Renewable energy

2,579.2

301.4

148.6

195.8

1,933.3

Conventional power

625.2

17.1

52.7

40.0

515.5

Electric transmission lines

618.7

12.8

16.9

22.8

566.2

Total project debt

3,823.1

331.3

218.2

258.6

3,015.0

Corporate debt

378.4

2.2

—

376.2

—

Total

4,201.5

333.5

218.2

634.8

3,015.0

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

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 interest expense and 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 “Item 8.A—Consolidated Statements and Other Financial Information—Dividend Policy.”

On November 14, 2014, we announced that our board of directors declared the first quarterly dividend corresponding to the third quarter of 2014 amounting to $0.2592 per share, representing $1.04 on an annualized basis. The dividend was paid on December 15, 2014, together with pro-rata dividend corresponding to the days since our IPO on June 12, 2014 until June 30, 2014, amounting to $0.0370 per share, resulting in a total payment of $0.2962 to shareholders of record as of November 28, 2014.

On February 23, 2015, our board of directors declared a quarterly dividend corresponding to the fourth quarter of 2014 amounting to $0.2592 per share, representing $1.04 on an annualized basis. We expect this dividend to be paid on or about March 16, 2015.

Acquisitions

On September 22, 2014, we entered into an agreement with Abengoa, subject to financing and negotiations of definitive documentation and certain other conditions, to acquire the First Dropdown Assets. The total aggregate consideration for the First Dropdown Assets was $312 million (which consideration was determined in part by converting the portion of the purchase price of Solacor 1/2 and PS10/20 denominated in euros into U.S. dollars based on the exchange rate on the date on which the payment was made). The transaction was approved by Abengoa Yield’s board of directors with the approval of independent directors and by Abengoa’s board of directors. The renewable energy assets which we acquired consist of PS10/20 and the 30-year usufruct of the economic and political rights over the shares of Solacor 1/2 (with an option to purchase such shares for one euro during a four-year term), solar power assets located in Spain with a combined capacity of 131 MW, and Cadonal, a 50 MW wind farm located in Uruguay. See “Item 4.B—Business Overview—Our Operations—Renewable Energy” for a description of such assets. The First Dropdown Assets were financed with the proceeds of the 2019 Notes and with a portion of the proceeds of the Credit Facility. See “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—2019 Notes” and “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—Credit Facility.”

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Helioenergy 1/2, with a capacity of 100 MW; and (iv) a 20% stake in the legal entity holding a solar power asset in the United Arab Emirates, Shams, with a capacity of 100 MW. On February 3, 2015, we completed the acquisition of the 25.5% stake in Honaine and the 34.17% stake in Skikda. See “Item 4.B—Business Overview—Our Operations—Water” for a description of such assets. The completion of the acquisition of the 40% stake in ATN2, the 29.6% stake in Helioenergy 1/2 and the 20% stake in Shams is subject to satisfaction of customary conditions, including approvals from financing institutions and, in certain cases, from partners in joint ventures. In the case of ATN2, the acquisition is also subject to the beginning of the generation of revenues by the project, unless such conditions are waived by Abengoa and us. If the conditions are not met by June 30, 2015, each party may terminate the agreement. The total aggregate consideration for the Second Dropdown Assets will be $142 million and will be financed with a portion of the proceeds of the Credit Facility and available cash. See “Item 4.B—Business Overview—Second Dropdown Assets.”

Cash flow

The following table sets forth cash flow data for the years ended December, 2014, 2013 and 2012:


	Year ended December 31,
	2014			2013			2012
	($ in millions)

Gross cash flows from operating activities
Profit/(loss) for the year		(29.3	)		(1.8	)		0.1
Adjustments to reconcile after-tax profit to net cash generated by operating activities		290.6			92.4			22.8

Profit for the year adjusted by non-monetary items		261.3			90.6			22.9

Net interest / taxes paid		(149.7	)		(62.4	)		(41.6	)
Variations in working capital		(68.0	)		9.2			66.6

Total net cash flow provided by operating activities		43.6			37.4			47.9

Net cash flows from investing activities
Investments		(122.8	)		(694.6	)		(1,098.7	)
Acquisitions		(222.4	)		—			—

Total net cash flows used in investing activities		(345.2	)		(694.6	)		(1,098.7	)


Net cash flows provided by financing activities		304.4			914.9			1,107.3


Net increase/(decrease) in cash and cash equivalents		2.9			257.7			56.5

Cash, cash equivalents and bank overdraft at beginning of the year		357.7			97.5			40.2
Translation differences cash or cash equivalents		(6.4	)		2.5			0.8


Cash and cash equivalents at the end of the year		354.2			357.7			97.5

Net cash flows provided by operating activities

For the year ended December 31, 2014, net cash provided by operating activities was $43.6 million, compared with $37.4 for the year ended December 31, 2013. During the year ended December 31, 2014, profit adjusted by non-monetary items was $261.3 million, compared with $90.6 million for the year ended December 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 partially offset by a negative variation in working capital which amounted to $(68.0) million for the year ended December 31, 2014 compared with $9.2 million for the year ended December 31, 2013. The negative variation in working capital in 2014 is related to the end of the construction phase of several projects. As all of our projects have reached COD as of December 31, 2014, we expect this negative movement to decline and we expect to have a non-significant impact from movements in working capital in future periods. In addition, higher interest amounts were paid in the year ended December 31, 2014, amounting to $149.7 million compared with $62.4 million in the year ended December 31, 2013, which is due to interests paid by the projects which have entered into operation.

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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 year adjusted by non-monetary items was $90.6 million compared with $22.9 million in 2012. 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 2/3, as it 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 year adjusted by non-monetary items was offset by larger net interest and taxes paid in 2013 of $62.4 million compared with $41.6 million in 2012.

Net cash used in investing activities

For the year ended December 31, 2014, net cash used in investing activities decreased to $345.2 million, compared with $694.6 million for the year ended December 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. This was partially offset by a net cash outflow caused by the acquisition of the First Dropdown Assets under the ROFO Agreement for the amount of $222.4 million.

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. The net investment in Solaben 2/3 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 provided by financing activities

For the year ended December 31, 2014, net cash flow provided by financing activities was $304.4 million, compared with $914.9 million provided by financing activities for the year ended December 31, 2013. The net cash provided by financing activities during the year ended December 31, 2014 was a net of different movements. Firstly, we recorded proceeds from loans and borrowings of $1,350.7 million, mainly related to (i) the collection of an ITC Cash Grant awarded to Solana by the U.S. Treasury, which was partially used on April 2, 2014 to fully repay the short-term tranche of Solana’s loan with the Federal Financing Bank of $451.3 million, (ii) the bond issue by ATS of $424 million, which was used to repay existing debt associated with the project, (iii) the 2019 Notes in the aggregate principal amount of $255 million (which were used, together with a portion of the proceeds of the Credit Facility, to finance the acquisition of the First Dropdown Assets from Abengoa pursuant to the ROFO Agreement) and (iv) the Credit Facility in the total amount of $125 million (a portion of which was used to finance the acquisition of Cadonal and the remaining portion is intended to be used to finance the acquisition of the Second Dropdown Assets from Abengoa pursuant to the ROFO Agreement and for general corporate purposes). On the other hand, we repaid loans and borrowings for an amount of $1,665.4 million, mostly comprised of the repayments of Solana and ATS referred to above. Additionally, on June 18, 2014 we received $685.3 million in our IPO, of which $655.3 million was used to pay Abengoa in exchange for a transfer of assets, which occurred immediately prior to our IPO.

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 project debt of $1,139.7 million, repayment of project debt 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 project debt of $339.5 million, repayment of project debt of $61.6 million, proceeds from related

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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 2/3.

Financing Arrangements

2019 Notes

On November 17, 2014, we issued the 2019 Notes in an aggregate principal amount of $255 million. Interest accrues on the 2019 Notes from November 17, 2014 until November 15, 2019, the maturity date, at a rate of 7.000% per annum. In the event that we do not obtain a public credit rating for the 2019 Notes from each of S&P and Moody’s prior to November 15, 2015, the interest rate per annum accruing on the 2019 Notes will increase by 0.75%, to 7.750%, on and after November 15, 2015 until the date on which we have obtained a public credit rating for the 2019 Notes from each of S&P and Moody’s.

The 2019 Notes were offered and issued in transactions exempt from registration to certain qualified institutional buyers in the United States, under Rule 144A under the Securities Act, and to institutional investors outside the United States, under Regulation S under the Securities Act.

The proceeds of the 2019 Notes were used, together with a portion of the proceeds of the Credit Facility, to finance the acquisition of the First Dropdown Assets from Abengoa pursuant to the ROFO Agreement. See “Item 4.B—Business Overview—First Dropdown Assets.” The total aggregate consideration for the First Dropdown Assets was $312 million (which consideration was determined in part by converting the portion of the purchase price of Solacor 1/2 and PS10/20 denominated in euros into U.S. dollars based on the exchange rate on the date on which the payment was made).

As of the date of this annual report, $255 million aggregate principal amount of the 2019 Notes remain outstanding. The 2019 Notes are guaranteed on a senior unsecured basis by our subsidiaries Abengoa Solar Holdings USA Inc., Abengoa Solar US Holdings Inc. and Abengoa Concessions Peru, S.A. If we fail to make payments on the 2019 Notes as required under the indenture governing such notes, the guarantors are obligated to make such payments.

The indenture governing the 2019 Notes provides, among other things, that the 2019 Notes and the guarantees are our and the guarantors’, respectively, general unsecured obligations and rank equally (subject to any applicable statutory exemptions) in right of payment with all of our and the guarantors’, respectively, existing and future debt that is not subordinated in right of payment and be effectively subordinated to all of our and the guarantors’, respectively, existing and future secured debt to the extent of the assets securing such debt and to any preferential obligations under applicable law. Interest is payable on the 2019 Notes on May 15 and November 15 of each year beginning on May 15, 2015 until their maturity date of November 15, 2019.

The indenture governing the 2019 Notes contains covenants that limit certain of our and the guarantors’ activities, including those relating to: incur additional indebtedness; pay dividends on, redeem or repurchase our capital stock; prepay subordinated indebtedness; make certain investments; impose certain restrictions on the ability of subsidiaries to pay dividends or other payments; create certain liens; transfer or sell assets; merge or consolidate with other entities; enter into transactions with affiliates; and engage in unrelated businesses. Each of the covenants is subject to a number of important exceptions and qualifications. In addition, certain of the covenants listed above will terminate before the 2019 Notes mature if at least two of the specified rating agencies assign the 2019 Notes an investment grade rating in the future and no events of default under the indenture governing the 2019 Notes exist and are continuing. Any covenants that cease to apply to us as a result of achieving investment grade ratings will not be restored, even if the credit ratings assigned to the 2019 Notes later fall below investment grade.

The indenture governing the 2019 Notes also contains customary events of default (subject in certain cases to customary grace and cure periods). Generally, if an event of default occurs and is not cured within the time periods specified, the trustee or the holders of at least 25% in principal amount of the 2019 Notes then outstanding may declare all of the 2019 Notes to be due and payable immediately.

Credit Facility

On December 3, 2014 we, as the borrower, and our subsidiaries ACIN, ACP, ACTH, ASHUSA and ASUSHI, as guarantors, entered into the Credit Facility of up to $125 million with HSBC Bank plc, as

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administrative agent, HSBC Corporate Trust Company (UK) Limited, as collateral agent and Banco Santander, S.A., Bank of America, N.A., Citigroup Global Markets Limited, HSBC Bank plc and RBC Capital Markets as joint lead arrangers and joint bookrunners.

On December 22, 2014, we drewdown $125 million under the Credit Facility. We used a portion of the proceeds of the Credit Facility to finance the acquisition of Cadonal and we expect to use the balance to finance the acquisition of the Second Dropdown Assets and for general corporate purposes.

Loans under the Credit Facility accrue interest at a rate per annum equal to: (A) for Eurodollar rate loans, LIBOR plus 2.75% and (B) for base rate loans, the highest of (i) the rate per annum equal to the weighted average of the rates on overnight U.S. Federal funds transactions with members of the U.S. Federal Reserve System arranged by U.S. Federal funds brokers on such day plus 1/2 of 1.00%, (ii) the U.S. prime rate and (iii) LIBOR plus 1.00%, in any case, plus 1.75%. Loans under the Credit Facility will mature on the fourth anniversary of the closing date of the Credit Facility. Loans prepaid by us under the Credit Facility may be reborrowed.

Our payment obligations under the Credit Facility are guaranteed by our subsidiaries ACIN, ACP, ACTH, ASHUSA and ASUSHI. The loan is also secured by substantially all of our assets and the assets of the guarantors, subject to customary exceptions.

The Credit Facility contains covenants that limit certain of our and the guarantors’ activities, including those relating to: mergers; consolidations; the ability to incur additional indebtedness; sales, transfers and other dispositions of property and assets; providing new guarantees; investments; granting additional security interests, transactions with affiliates and our ability to pay cash dividends is also subject to certain standard restrictions.

The Credit Facility also contains customary events of default, the ability of the lenders to declare the unpaid principal amount of all outstanding loans, and interest accrued thereon, to be immediately due and payable.

Additionally, we are required to comply with a maintenance leverage ratio of our indebtedness at the holding level to our cash available for distribution of 3.75:1.00 before debt service and an interest coverage ratio of cash available for distribution to debt service payments of 2.00:1.00.

Project Level Financing

We have outstanding project-specific debt that is backed by certain of our assets. These financing arrangements generally include a pledge of shares of the entities holding our assets and customary covenants, including restrictive covenants that limit the ability of the project-level entities to make cash distributions to their parent companies and ultimately to us including if certain financial ratios are not met. For more information about the debt of project-level entities, see “Item 4.B—Business Overview—Our Operations.”

Critical Accounting Policies and Estimates

The preparation of our consolidated 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 consolidated 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 consolidated financial statements.

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

•

Contracted concessional agreements and PPAs;

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•

Impairment of intangible assets;

•

Assessment of control;

•

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 Consolidated 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, 2014, 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 consolidated income statement of the year in which the change occurs. Our significant accounting policies are more fully described in note 2 to our Annual Consolidated Financial Statements, presented elsewhere in this annual report.

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, except for Palmucho, which is recorded in accordance with IAS 17 and PS10/20, which are recorded as tangible assets in accordance with IAS 16. 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.

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.

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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 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 “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.

Property, plant and equipment

Assets recorded as property, plant and equipment (PS10/20) are measured at historical cost, including all expenses directly attributable to the acquisition, less depreciation and impairment losses, with the exception of land, which is presented net of any impairment losses. Once the infrastructure is in operation, the treatment of income and expenses is equal to intangible assets.

Impairment of intangible assets and property, plan and equipment

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.

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.

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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, or 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 Annual Consolidated 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’s construction phase is finished, we gain control over these companies, which are then fully consolidated.

We use the acquisition method to account for business combinations of companies controlled by a third party. 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.

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.

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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.

The fair value of the preferred equity investment in ACBH (Level 3) was calculated by considering expected cash-flows from the preferred equity instrument discounted at a rate appropriate for the sector in which the Company is operating. Valuation was obtained from internal models. This valuation could vary where other models and assumptions made on the principle variables had been used, however the fair value of the asset as well as the results generated by this financial instrument are considered reasonable.

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.

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.

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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.

C.	Research and Development

Not applicable.

D.	Trend Information

Other than as disclosed elsewhere in this annual report, we are not aware of any trends, uncertainties, demands, commitments or events for the year ended December 31, 2014 that are reasonably likely to have a material adverse effect on our revenues, income, profitability, liquidity or capital resources, or that caused the disclosed financial information to be not necessarily indicative of future operating results or financial conditions.

E.	Off Balance Sheet Arrangements

As of December 31, 2014, our only off-balance sheet arrangements consisted of bank bond and surety insurance in an aggregate amount of $17.6 million attributed to transactions of a technical nature. For further discussion, see note 19 to our Annual Consolidated Financial Statements included elsewhere in this annual report.

F.	Tabular Disclosure of Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2014.


	Total		Up to one year		Between one and three years		Between three and five years		Subsequent years
	($ in millions)

Corporate debt		378.5		2.3		—		376.2		—

Loans with credit institutions (project debt)		3,294.3		323.3		209.0		245.0		2,517.0
Notes and bonds (project debt)		528.8		7.9		9.3		13.6		498.0
Purchase commitments		1,813.1		79.5		148.4		152.2		1,433.0
Accrued interest estimate during the useful life of loans		2,233.7		180.8		350.6		308.3		1,394.0

As described in the table above, we have other 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.

Corporate debt refers to the 2019 Notes and the Credit Facility, which are described in detail in note 14 to our Annual Consolidated Financial Statements.

For more detailed information on project debt (loans with credit institutions) refer to note 15 to our Annual Consolidated Financial Statements.

Notes and bonds refer to the carrying value of issuances made during 2014, which are described in detail in note 15 to our Annual Consolidated 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.

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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.

Capital Expenditures

Our capital spending program is currently limited to pending engineering and construction invoices related to the Mojave project, which reached COD on December 1, 2014. As of December 31, 2014, to finance our capital expenditures plan, we have secured all the required commitments with project debt and equity contributed to us as part of the transfer by Abengoa to us of certain assets at the time of our IPO.

G.	Safe Harbor

This annual report contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act and as defined in the Private Securities Litigation Reform Act of 1995. See “Cautionary Statements Regarding Forward-Looking Statements.”

ITEM 6.

DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A.	Directors and Senior Management

Board of Directors of Abengoa Yield plc

The Board of Directors of Abengoa Yield comprises the following 10 members:


Name	Position	Year of birth

Manuel Sanchez Ortega	Director and Chairman of the Board of Directors	1963

Santiago Seage	Chief Executive Officer and Director	1969

William B. Richardson	Director	1947

Christopher Standlee	Director	1953

Maria J. Esteruelas	Director	1972

Eduardo Kausel	Director, independent	1943

Daniel Villalba	Director, independent	1947

Jack Robinson	Director, independent	1942

Enrique Alarcon	Director, independent	1942

Juan del Hoyo	Director, independent	1944

The business address of the members of the Board of Directors of Abengoa Yield is Great West House, GW1, 17th floor, Great West Road, Brentford, United Kingdom, TW8 9DF.

There are no family relationships among any of our executive officers or directors.

There are no potential conflicts of interest between the private interests or other duties of the members of the Board of Directors listed above and their duties to Abengoa Yield.

The following is the biographical information of members of our Board of Directors.

Manuel Sanchez Ortega, Director and Chairman of the Board of Directors

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

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and has a Master’s degree in Business Administration from the Instituto Panamericano de Alta Direccion de Empresas (IPADE) in Mexico. Mr. Sanchez has been a member of the Advisory Board of the Global Business Initiative of the McDonough Business School at Georgetown University in Washington D.C. since March 2013.

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 is and, for a limited period of time after the date of this annual report, will remain an officer of Abengoa.

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 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 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 100 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.

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 50 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.

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Jack Robinson, Director

Mr. Robinson is a portfolio manager and partner at Brown Advisory, affiliates of which are investment advisers registered with the Commission. 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.

Senior Management of Abengoa Yield plc

We have a senior management team with extensive experience in developing, financing, managing and operating contracted assets. During the year 2014, we did not employ any member of this senior management team. Since February 1, 2015, we are in the process of transferring and employing directly our executive management team, including Mr. Seage, Mr. Soler, Mr. Silvan, Mr. Garcia, Mr. Merino and Ms. Hernandez. Once this process is completed, the Executive Services Agreement between Abengoa and us will be terminated. See “Item 7.B—Related Party Transactions—Executive Services Agreement.”

The senior management of Abengoa Yield is made up of the following members:


Name	Position	Year of Birth
Santiago Seage	Chief Executive Officer and Director	1969

Eduard Soler	Executive Vice President and Chief Financial Officer	1979

Manuel Silvan	Vice President Taxes, Risk Management and Compliance	1973

Emiliano Garcia	Vice President North America	1968

Antonio Merino	Vice President South America	1967

David Esteban	Vice President EMEA	1979

Irene M. Hernandez	General Counsel	1980

The business address of the members of the senior management of Abengoa Yield is Great West House, GW1, 17th floor, Great West Road, Brentford, United Kingdom, TW8 9DF.

There are no potential conflicts of interest between the private interests or other duties of the members of the senior management of Abengoa Yield listed above and their duties to Abengoa Yield. There are no family relationships among any of our executive officers or directors.

Below are the biographies of those members of the senior management of Abengoa Yield who do not also serve on our Board of Directors.

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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 is and, for a limited period of time after the date of this annual report, will remain an officer of Abengoa.

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 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.

Emiliano Garcia, Vice President North America

Mr. Garcia 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 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.

David Esteban, Vice President Europe

Mr. Esteban has served as Vice President of our operations in Europe since July 2014. He had previously served at Abengoa’s Corporate Concession department for two years. Before joining Abengoa, David worked for the management consulting firm Arthur D. Little for seven years in the industries of Telecoms & Energy and then moved to a private equity firm specialized in renewable investments in Europe for three years.

Irene M. Hernandez, General Counsel

Ms. Hernandez has served as our General Counsel since June 2014. Prior to that, she served as head of our legal department since the date of our formation. Before that, Ms. Hernandez served as Deputy Secretary General at Abengoa Solar since 2012. Before joining Abengoa, she worked for several law firms. Ms. Hernandez holds a law degree from Complutense Madrid University and a Master’s degree in law from the Madrid Bar Association (Colegio de Abogados de Madrid (ICAM)).

Lead Independent Director

Our corporate governance guidelines 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 our board of directors. Mr. Villalba serves as our lead independent director.

B.	Compensation

Compensation of Board of Directors

Our independent directors will receive compensation as “non-employee directors” as set by our board of directors.

Each independent director receives a total annual compensation of $100,000. As lead independent director and Chair of our Audit Committee, Mr. Villalba receives an additional $35,000 per year. Directors representing Abengoa do not receive any compensation from us. The total compensation received by our independent directors from us during 2014 was $267,375.

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Each member of our board of directors will be indemnified for his actions associated with being a director to the extent permitted by law.

Compensation of Executive Officers

During the year 2014, we did not employ directly any member of our senior management team. Since February 1, 2015, we are in the process of transferring and employing directly our executive management team, including Mr. Seage, Mr. Soler, Mr. Silvan, Mr. Garcia, Mr. Merino and Ms. Hernandez. Once this process is completed, the Executive Services Agreement between Abengoa and us will be terminated. See “Item 7.B—Related Party Transactions—Executive Services Agreement.”

Our officers manage the day-to-day affairs of our business and are employed and compensated by us, including under long-term incentive plans, although some of our executives may continue to participate in long-term incentive plans with Abengoa, provided that since 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.

As we did not directly employ any of the executives responsible for managing our business during the year 2014, we did not have any compensation expenses for our executive officers during such year other than the expenses corresponding to the fees paid by us to Abengoa under the Executive Services Agreement.

C.	Board Practices

For purpose of the following disclosure, Mr. Sanchez, Mr. Seage, Mr. Richardson, Mr. Standlee and Ms. Esteruelas are considered Abengoa representatives.

Our board of directors consists of 10 directors, five of them independent. Under our articles of association, our board of directors may consist of seven to 13 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.

Abengoa representatives do 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 is 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 of directors and have not approved the board of director’s delegation to others.

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Audit Committee

Our Audit Committee is responsible for monitoring and informing the board of directors on the work of external and internal auditors, control systems, key processes and procedures, security and risks. The committee comprises the following six members:


Name		Position
Daniel Villalba⁽¹⁾		Chairman
Santiago Seage		Member
Eduardo Kausel⁽¹⁾		Member
Jack Robinson⁽¹⁾		Member
Enrique Alarcon⁽¹⁾		Member
Juan del Hoyo⁽¹⁾		Member

(1)	Independent member of the Audit Committee.

We expect Mr. Seage to resign from the committee prior to the first anniversary of our IPO, 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.

Our 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 our Audit Committee. Our Audit Committee is also responsible for reviewing and approving our hiring policies regarding former employees of the external auditor. In addition, the Audit Committee preapproves all non-audit services undertaken by the external auditor.

Our 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. Our Audit Committee is accountable to our board of directors and will provide a report to our board of directors after each regularly scheduled Audit Committee meeting outlining the results of the Audit Committee’s activities and proceedings.

Appointments and Remuneration Committee

Our Appointments and Remuneration Committee comprises of the following three members:


Name		Position
Manuel Sanchez Ortega		Chairman
Daniel Villalba⁽¹⁾		Member
Enrique Alarcon⁽¹⁾		Member

(1)	Independent member of the 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 our board of directors and its members, as well as upon general remuneration and incentives policy for our board of directors and senior management. Our Appointments and Remuneration Committee meets as often as necessary in order to perform its functions and at least once every six months. The committee informs and makes proposals to the board of directors.

Benefits upon Termination of Employment

Neither we nor our subsidiaries maintain any director’s service contracts providing for benefits upon termination of service.

D.	Employees

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Mr. Soler, Mr. Silvan, Mr. Garcia, Mr. Merino and Ms. Hernandez. Once this process is completed, the Executive Services Agreement between Abengoa and us will be terminated. See “Item 7.B—Related Party Transactions—Executive Services Agreement.” In addition, we are in the process of employing directly some of the employees who were in Abengoa’s subsidiaries in 2014. As of the date of this annual report, we had 23 employees in our subsidiaries.

E.	Share Ownership

None of our directors or members of our senior management is the owner of more than one percent of our ordinary shares, and no director or member of our senior management has voting rights with respect to our ordinary shares that are different from any other holder of our ordinary shares.

ITEM 7.

MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A.	Major Shareholders

As of the date of this annual report, Abengoa, through its indirectly 100%-owned subsidiary Abengoa Concessions Investments Limited, is our major shareholder and beneficially owns approximately 51.1% of our outstanding shares. As of December 31, 2014, Jennison Associates LLC and Prudential Financial, Inc. beneficially owned approximately 7.25% each of our outstanding shares.

To the best of our knowledge, there were no other beneficial holders of 5% or more of our outstanding shares as of the date of this annual report.

Shareholders in the United States

Because some of our ordinary shares are held by brokers and other nominees, the number of shares held by and the number of beneficial holders with addresses in the United States is not fully ascertainable. As of the date of this annual report, to the best of our knowledge, one of our shareholders of record was located in the United States and held in the aggregate 39,157,500 ordinary shares representing approximately 48.9% of our outstanding shares. However, the United States shareholders of record include Cede & Co., which, as nominee for The Depositary Trust Company, is the record holder of all such 39,157,500 ordinary shares. Accordingly, we believe that the shares held by Cede & Co. include ordinary shares beneficially owned by both United States and non-United States beneficial owners. As a result, these numbers may not accurately represent the number of beneficial owners in the United States.

Control of the Company

As of the date of this annual report, Abengoa, through its indirectly 100%-owned subsidiary Abengoa Concessions Investments Limited, is our major shareholder and beneficially owns approximately 51.1% of our shares. Under the terms of the Governance MOU entered into on December 9, 2014, we and Abengoa agreed to work jointly for a period of seven months to amend our corporate governance regulations to (i) ensure that none of our shareholders, including Abengoa, shall have the right to appoint or recommend either the majority or even half of our directors, even if such shareholder (including Abengoa) owns a majority of our shares, (ii) expand the list of strategic matters that require approval by our board of directors, including significant investments, divestitures and indebtedness and (iii) ensure that Abengoa will not be entitled to exercise more than 40% of the voting rights in relation to us. See “Item 7.B—Related Party Transactions—Governance MOU.”

Arrangements for Change in Control of the Company

Except as described above under “Information on the Company,” we are not aware of any arrangements the operation of which may at a later time result in a change of control.

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B.	Related Party Transactions

Each of our assets typically has two contracts in place with Abengoa entities from the time they reach COD, i.e.: an operation and maintenance agreement and a services agreement that covers local administrative support. We also have engineering, procurement and construction agreements with subsidiaries of Abengoa.

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 and (ii) access through the ROFO Agreement and the Call Option Agreement a pipeline of potential acquisitions that we believe will help us to grow in the future. In addition to the deed described under “Item 10.B—Memorandum and Articles of Association—Brazil Dividend Policy” and the shareholders agreement and related parent support agreement described under “Item 4.B—Business Overview—Our Operations—Exchangeable Preferred Equity Investment in Abengoa Concessoes Brasil Holding,” we have entered into seven 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;

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Executive Services Agreement;

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Governance MOU; and

•

Call Option 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:

•

an operations and maintenance contract, in most cases with an Abengoa subsidiary; and

•

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, including the Abengoa ROFO Assets we expect to acquire, 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.

•

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.

•

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.

•

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.

•

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 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 2/3 Solacor 1/2, PS10/20 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.

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Services Agreement

Each of our project-level companies, including the Abengoa ROFO Assets we expect to acquire, 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.

•

Term. The agreements relating to ATN and ATS expire after a year but include tacit renewal clauses, while Solana, Mojave, Solaben 2/3, Solacor 1/2, PS10/20 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 2/3, Solacor 1/2, which provide for a fee of 2.5% of revenues, and PS10/20, which provide for a fee of 2% of revenues.

Engineering, Procurement and Construction Agreement

Each of our project-level companies, including the Abengoa ROFO Assets we expect to acquire, have entered into an EPC contract with a local Abengoa subsidiary. These contracts typically provide for the construction of the asset and are in place until the asset reaches COD. EPC contracts may contain warranties such as those against defects in design, materials and workmanship after completion of the asset and may also provide a performance guarantee.

Right of First Offer

Pursuant to the ROFO Agreement, which we and Abengoa entered into on June 13, 2014, as amended and restated on December 9, 2014, Abengoa and its affiliates granted 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 any other renewable energy, conventional power, electric transmission and water asset that is expected to generate contracted revenue and that Abengoa has transferred to an investment vehicle that are 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 selected countries in Africa, the Middle East, Asia and Australia, which we refer to as our secondary geographies.

On July 2, 2014 we agreed with Abengoa on a list of four assets that will be considered Abengoa ROFO Assets. The initial list of these four assets consists of Shams, a 110 MW solar plant in Abu Dhabi, United Arab Emirates, ATN2, an 81 mile transmission line in Peru, Honaine, a 7 M ft3 per day desalination plant in Algeria and Skikda, a 3.5 M ft3 per day desalination plant in Algeria. We refer to the contracted assets subject to the ROFO Agreement as the “Abengoa ROFO Assets.” See “Item 4.B—Business Overview—Our Growth Strategy.”

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

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to, an unaffiliated third party, or to an internal restructuring. The right of first offer will not apply to the sale of Linha Verde, a Brazilian transmission line, which sale to a third party is in the process of receiving the necessary approvals for closing, pursuant to a purchase agreement entered into on March 26, 2014.

If Abengoa transfers interests in any Abengoa ROFO Asset to any affiliate or to an investment vehicle, then Abengoa must obtain an accession agreement from such transferee subjecting the transferred Abengoa ROFO Asset to our right of first offer. For purposes of this requirement, “investment vehicle” means any person (A) (i) formed by Abengoa to act as an investment vehicle or (ii) that is an affiliate of Abengoa that Abengoa intends to use as an investment vehicle or becomes an investment vehicle due to an investment by a third party and (B) with the purpose of providing equity to projects related to any renewable energy, conventional power, electric transmission line and water contracted revenue assets that are to be, are being or were previously developed, sponsored, initiated or launched by Abengoa or any of its affiliates, irrespective of the amount of equity invested in such person by Abengoa or any such affiliate.

In addition, we have a “negotiation call” right under which we can require Abengoa to negotiate in good faith for the sale to us of any Abengoa ROFO Asset that has been in operation for 18 months.

The ROFO Agreement has an initial term of five years from the consummation of our IPO. 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 10 days that the information is insufficient, a 60-day negotiation period will start. If an agreement is not reached, Abengoa may, during the following 30 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 30-month period, the asset will cease to be an Abengoa ROFO Asset.

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 is not 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 “Item 7.B—Related Party Transactions—Procedures for Review, Approval and Ratification of Related Party Transactions; Conflicts of Interest,” “Item 3.D—Risk Factors—Risks Related to Our Relationship with Abengoa—We may not be able to consummate future acquisitions from Abengoa” and “Item 3.D—Risk Factors—Our organizational and

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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 our minority shareholders and that may have a material adverse effect on our business, financial condition, results of operations and cash flows.”

Abengoa may enter into agreements with other companies with the objective of jointly financing the construction of new projects consisting of concessional assets which are included in Abengoa’s current or future portfolio. Pursuant to the terms of the ROFO Agreement, we expect that any investing vehicle created by Abengoa and a potential partner with this purpose will sign the ROFO Agreement in the same terms of Abengoa.

Call Option Agreement

On December 9, 2014, we entered into the Call Option Agreement with Abengoa pursuant to which we have the option, exercisable by us or through any of our subsidiaries during a 10-month period starting on January 22, 2015, to purchase from Abengoa up to $100 million in equity or subordinated debt of additional operational contracted assets at a yield of 12%, such yield being based on a set of projections of recurrent cash available for distribution generated by the relevant asset to be agreed between the parties (or decided by external arbitration if an agreement is not reached between us and Abengoa during a period of time). This agreement has a one-year term starting on January 22, 2015, although the relevant acquisitions may be completed afterwards. We will pay Abengoa a fee of 1% of the equity purchase price of any asset that we acquire through the Call Option Agreement, which is the same fee applicable to the acquisition of any Abengoa ROFO Assets made pursuant to the ROFO Agreement.

Trademark License Agreement

We and Abengoa entered into a Trademark License Agreement on June 13, 2014, pursuant to which Abengoa granted 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 do not have a legal right to the “Abengoa” name or the Abengoa logo. Abengoa also granted an exclusive license to use the “Abengoa Yield” name and logo.

On September 10, 2014, Abengoa transferred 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. Abengoa committed 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 is entitled to terminate the Trademark License Agreement upon 90 days’ prior written notice of termination if any of the following occurs:

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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.

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 entered into a Financial Support Agreement on June 13, 2014, for a period of five years, pursuant to which:

(1)

Abengoa provided us with a revolving credit line from its central treasury for a period of five years up to a maximum amount of $50 million. 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. As of the date of this annual report, the total amount of the credit line remains undrawn.

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(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 million.

(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 date of our IPO. 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 which provides 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

We and Abengoa entered into a Support Services Agreement on June 13, 2014, pursuant to which Abengoa agreed 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 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;

•

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;

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•

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 are subject to the supervision of our executive management.

Support Services Fee

Pursuant to the Support Services Agreement, we pay a support services fee of approximately $625,000 per quarter. The support services fee is adjusted for inflation annually since 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.

Term and Termination

The Support Services Agreement does not have a fixed term. However, we are 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 must 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 is 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 is also able to terminate the Support Services Agreement upon the occurrence of certain events relating to our bankruptcy or insolvency.

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Indemnification and Limitations on Liability

Under the Support Services Agreement, Abengoa does not assume any responsibility other than to provide or arrange for the provision of the services called for thereunder in good faith and is not 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.

Executive Services Agreement

We entered into an Executive Services Agreement with Abengoa on June 13, 2014, under which key executives currently employed by Abengoa provide their services to us while they remain employees of and continue to provide services to Abengoa.

During the year 2014, we did not employ any member of our senior management team. Since February 1, 2015, we are in the process of transferring and employing directly our executive management team, including Mr. Seage, Mr. Soler, Mr. Silvan, Mr. Garcia, Mr. Merino and Ms. Hernandez. Once this process is completed, the Executive Services Agreement between Abengoa and us will be terminated. For a discussion of our management team, see “Item 6—Directors, Senior Management and Employees.”

Services Rendered

Under the Executive Services Agreement, Abengoa arranges 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 pay an executive services fee of approximately $500,000 per quarter.

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Termination

We are able to terminate this agreement immediately upon notice on or after June 2015 without cause, or at any time upon 30 days’ notice with cause. Both parties can agree to terminate it earlier once the 10 senior managers, or a majority of them, have been transferred to us.

Abengoa is not able to terminate this agreement unilaterally.

Once all or a substantial part of the senior managers have been transferred to us, we expect to 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 does not assume any responsibility other than to provide or arrange for the provision of the services called for thereunder in good faith and is not 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, is 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 are not 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.

Governance MOU

On December 9, 2014, we entered into the Governance MOU with Abengoa pursuant to which we and Abengoa agreed to work jointly for a period of seven months to amend our corporate governance regulations to (i) ensure that none of our shareholders, including Abengoa, shall have the right to appoint or recommend either the majority or even half of our directors, even if such shareholder (including Abengoa) owns a majority of our shares, (ii) expand the list of strategic matters that require approval by our board of directors, including significant investments, divestitures and indebtedness and (iii) ensure that Abengoa will not be entitled to exercise more than 40% of the voting rights in relation to us.

C.	Interests of Experts and Counsel

Not applicable.

ITEM 8.

FINANCIAL INFORMATION

A.	Consolidated Statements and other Financial Information.

We have included the Annual Consolidated Financial Statements as part of this annual report. See “Item 18—Financial Statements.”

Dividend Policy

Our Cash Dividend Policy

Our quarterly dividend was set at $0.2592 per share for the third quarter of 2014, or $1.04 per share on an annualized basis. On February 23, 2015, our board of directors declared a quarterly dividend corresponding to the fourth quarter of 2014 amounting to $0.2592 per share, representing $1.04 on an annualized basis. We expect this dividend to be paid on or about March 16, 2015.

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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. We declared our first quarterly dividend in November 2014 and paid it on December 15, 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 ramp-up 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.

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 borrowings under our Credit Facility 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.

Risks Regarding Our Cash Dividend Policy

We do not have a significant 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 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 “Item 4.B—Business Overview—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 recently incurred indebtedness under the 2019 Notes and entered into the Credit Facility which contain, among other covenants, certain financial incurrence and maintenance covenants, as applicable. See “Item 5.B—Liquidity and Capital Resources—Financing

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Arrangements.” In addition, 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 “Item 4.B—Business—Our Operations” for a description of such restrictions.

•

We and our board of directors 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 project debt 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 “Item 3.D—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. Our 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.

Our Ability to Grow our Business and Dividend

We intend to grow our business primarily through the improvement of existing assets and the acquisition of contracted power generation assets, electric transmission lines and other infrastructure assets, which, we believe, along with Mojave’s having reached COD and the recent acquisitions of Cadonal, PS10/20 and the 30-year usufruct of the economic and political rights over the shares of Solacor 1/2 (with an option to purchase such shares for one euro during a four-year term), 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.

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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.

B.	Significant Changes

Except as described above, there have been no significant changes since the date of the Annual Consolidated Financial Statements included in this annual report.

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ITEM 9.

THE OFFER AND LISTING.

A.	Offering and Listing Details.

Our ordinary shares trade on the NASDAQ Global Select Market under the symbol “ABY.” The following table sets forth, for the periods indicated, the high and low intraday sales price per ordinary share as reported by the NASDAQ Global Select Market since the date of our IPO.


	Price per Share
(Amounts in U.S. dollars)	High		Low		Average Daily Trading (in number of shares)
Year ending December 31, 2015:
First quarter (through February 19, 2015)		36.36		25.93		743,657

Year ended December 31, 2014:
Fourth quarter		35.76		21.00		697,219
Third quarter		40.98		33.87		442,476
Second quarter (from June 12, 2014)⁽¹⁾		40.61		35.00		1,845,033

Most recent six months:
September 2014		40.47		34.97		546,223
October 2014		35.76		28.64		436,399
November 2014		33.98		21.00		886,493
December 2014		29.22		25.10		806,430
January 2015		36.36		25.93		951,345
February 2015 (through February 19, 2015)		35.27		31.61		424,137

(1)	Our ordinary shares were admitted to trading on the NASDAQ Global Select Market following the consummation of our IPO on June 12, 2014. There was no public market for our ordinary shares before our IPO.

B.	Plan of Distribution

Not applicable.

C.	Markets

Our ordinary shares are traded on the NASDAQ Global Select Market under the symbol “ABY.”

D.	Selling Shareholders

Not applicable.

E.	Dilution

Not applicable.

F.	Expenses of the Issue

Not applicable.

ITEM 10.

ADDITIONAL INFORMATION.

A.	Share Capital

Not applicable.

B.	Memorandum and Articles of Association

The information called for by this item has been reported previously in our Registration Statement on form F-1 (File No. 333-200848), filed with the SEC on January 16, 2015, as amended, under the heading “Description of Share Capital” and is incorporated by reference into this annual report.

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C.	Material Contracts

See “Item 4.B—Business Overview,” “Item 5.B—Liquidity and Capital Resources—Financing Arrangements” and “Item 7.B—Related Party Transactions.”

D.	Exchange Controls

See “Item 5.A—Operating Results—Factors Affecting Our Results of Operations—Regulation.”

E.	Taxation

The following is a discussion of the material U.K. and U.S. federal income tax consequences of acquiring, owning and disposing of shares in Abengoa Yield to the persons addressed therein. Insofar as it expresses legal conclusions with respect to matters of U.K. tax law and U.S. federal income tax law, it is the opinion of Linklaters LLP.

We plan to undertake the actions set forth in the Governance MOU only after analyzing and addressing all implications for us and our shareholders and taking into account, among other things, any adverse tax consequences. This might affect the timing of the implementation of some of those actions or prevent us from implementing some at all. The rest of this disclosure speaks to the present and does not take into account any actions that may be taken under the Governance MOU.

Material U.K. Tax Considerations

The following is a general summary of material U.K. tax considerations relating to the ownership and disposal of Abengoa Yield shares. The comments set out below are based on current United Kingdom tax law as applied in England and Wales and HM Revenue & Customs 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 to you only if you are a “U.S. Holder” (as defined in the section below entitled “Material U.S. Federal Income Tax Considerations” and if:

•

you hold Abengoa Yield shares as an investment for tax purposes, as capital assets and you are the absolute beneficial owner thereof for U.K. tax purposes;

•

you are an individual, you are not resident in the United Kingdom for U.K. tax purposes and do not hold Abengoa Yield shares for the purposes of a trade, profession, or vocation that you carry on in the United Kingdom through a branch or agency, or if you are a corporation, you are not resident in the U.K. for U.K. tax purposes and do not hold the securities for the purpose of a trade carried on in the United Kingdom through a permanent establishment in the United Kingdom; and

•

you are not domiciled in the U.K. for U.K. inheritance tax purposes.

This summary does not address all possible tax consequences relating to an investment in the shares. Certain categories of shareholders, including those falling outside the category described above, 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 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.

UK 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 to a U.S. Holder.

U.S. Holders 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.

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UK Taxation of Capital Gains

An individual holder who is a U.S. Holder will not be liable to U.K. capital gains tax on capital gains realised on the disposal of his or her Abengoa Yield 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.

A corporate holder of shares that is a U.S. Holder will not be liable for U.K. corporation tax on chargeable gains realized on the disposal of its Abengoa Yield shares unless it carries on a trade in the United Kingdom through a permanent establishment to which the shares are attributable.

An individual holder of shares who is temporarily a non-U.K. resident for U.K. tax purposes will, in certain circumstances, become liable to U.K. tax on capital gains in respect of gains realised while he or she was not resident in the U.K.

UK Inheritance Tax

Abengoa Yield shares which are registered on the main Abengoa Yield share register are assets situated in the United Kingdom for the purposes of U.K. inheritance tax. A gift of such assets by, or the death of, an individual holder of such assets may (subject to certain exemptions and reliefs) give rise to a liability to U.K. inheritance tax, even if the holder is neither domiciled in the U.K. nor deemed to be domiciled there (under certain rules relating to long residence or previous domicile). Generally, U.K. inheritance tax is not chargeable on gifts to individuals if the transfer is made more than seven complete years prior to death of the donor. For inheritance tax purposes, a transfer of assets at less than full market value may be treated as a gift and particular rules apply to gifts where the donor reserves or retains some benefit. Special rules also apply to close companies and to trustees of settlements who hold shares in Abengoa Yield bringing them within the charge to inheritance tax.

However, Abengoa Yield shares held by an individual whose domicile is determined to be the United States for the purposes of the United States-United Kingdom Double Taxation Convention relating to estate and gift taxes (the “U.S.-U.K. Estate Tax Treaty”) and who is not for such purposes a national of the U.K. will not, provided any U.S. federal estate or gift tax chargeable has been paid, be subject to U.K. inheritance tax on the individual’s death or on a lifetime transfer of the Abengoa Yield shares except in certain cases where the Abengoa Yield shares (i) are comprised in a settlement (unless, at the time of the settlement, the settlor was domiciled in the United States and was not a national of the U.K.), (ii) are part of the business property of a U.K. permanent establishment or an enterprise, or (iii) pertain to a U.K. fixed base of an individual used for the performance of independent personal services. In such cases, the U.S.-U.K. Estate Tax Treaty generally provides a credit against U.S. federal tax liability for the amount of any tax paid in the U.K. in a case where the Abengoa Yield shares are subject both to U.K. inheritance tax and to U.S. federal estate or gift 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, Abengoa Yield 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

An agreement to transfer Abengoa Yield 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 Abengoa Yield 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.

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.

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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 or depositary receipt system.

Where Abengoa Yield 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 any other transfer into a clearance service or depositary receipt system, or in respect of a transfer within any clearance service or depositary receipt system, 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.

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). This 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) 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 5% of the 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 U.S. citizens or lawful permanent residents of the United States living abroad, 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, partners in entities classified as partnerships for U.S. federal income

160

tax purposes, persons holding shares through an individual retirement account or other tax-deferred account, 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 a partnership for U.S. federal income tax purposes holds shares, the U.S. federal income tax treatment of a partner in such an 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 advisors 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, has not been during the prior taxable year, 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 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 dividend income.” Distributions received by a U.S. Holder on shares will be qualified dividend income if: (i) shares are readily tradable on an established securities market in the United States (such as NASDAQ Global Select Market, where our shares are listed) 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 was a PFIC for its 2014 taxable year and does not expect to be a PFIC for its current taxable year or 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 owned 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 was a PFIC for its 2014 taxable year and does not expect to be a PFIC for its current taxable year or in

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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, certain rents 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. The law is unclear as to what constitutes “active business gains” and there are also other uncertainties regarding the criteria that commodities must meet. Accordingly, there can be no assurance that Abengoa Yield is not, was not for its 2014 taxable year, or will not become a PFIC or that changes in the management or ownership structure of Abengoa Yield or its assets, including as a result of any acquisitions pursuant to the ROFO Agreement and the Call Option Agreement, will not impact the determination of Abengoa Yield’s PFIC status.

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 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.

U.S. Holders should consult their own tax advisors regarding the PFIC rules.

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.

F.	Dividends and Paying Agents

Not applicable.

G.	Statement by Experts

Not applicable.

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H.	Documents on Display

We previously filed with the SEC our registration statement on Form F 1.

We have filed this annual report on Form 20 F with the SEC under the Securities Exchange Act of 1934, as amended. Statements made in this annual report as to the contents of any document referred to are not necessarily complete. With respect to each such document filed as an exhibit to this annual report, reference is made to the exhibit for a more complete description of the matter involved, and each such statement shall be deemed qualified in its entirety by such reference.

We are subject to the informational requirements of the Exchange Act and file reports and other information with the SEC. Reports and other information which we filed with the SEC, including this annual report on Form 20 F, may be inspected and copied at the public reference room of the SEC at 450 Fifth Street N.W. Washington D.C. 20549.

You can also obtain copies of this annual report on Form 20 F by mail from the Public Reference Section of the Securities and Exchange Commission, 450 Fifth Street, N.W., Washington D.C. 20549, at prescribed rates. Additionally, copies of this material may be obtained from the SEC’s Internet site at http://www.sec.gov. The Commission’s telephone number is 1 800 SEC 0330.

I.	Subsidiaries Information

Not applicable.

ITEM 11.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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 from our subsidiaries 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 were no forward sale contracts signed as of December 31, 2014 and 2013.

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 as of December 31, 2014, 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:

•

project debt in U.S. dollars: between 75% and 100% of the notional amount, maturities until 2043 and average guaranteed interest rates of between 2.75% and 6.32%.

•

project debt in euro: between 80% and 100% of the notional amount, maturities until 2030 and average guaranteed interest rates of between 3.13% and 4.75%.

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In connection with our interest rate derivative positions, the most significant impact on our consolidated 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, 2014, with the rest of the variables remaining constant, the effect in the consolidated income statement would have been a loss of $271,000 (a loss of $195,000 in 2013 and a profit of $296,000 in 2012) and an increase in hedging reserves of $24.2 million ($16.3 million in 2013 and $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 PPAs 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, 2014, 2013 and 2012:

Balance as of December 31,

2014

2013

2012

$ in millions

Maturity

Up to 3 months

78.5

26.6

11.2

Between 3 and 6 months

—

Total

78.5

26.6

11.2

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 project 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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ITEM 12.

DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES.

A.	Debt Securities

Not applicable.

B.	Warrants and Rights

Not applicable.

C.	Other Securities

Not applicable.

D.	American Depositary Shares

Not applicable.

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PART II.

ITEM 13.

DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES.

None of these events occurred in any of the years ended December 31, 2014, 2013 and 2012.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS.

Not applicable.

ITEM 15.

CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

Our chief executive officer and chief financial officer have performed an evaluation of the effectiveness of our disclosure controls and procedures within the meaning of Rule 13a-15(e) of the Exchange Act as of the end of the year covered by this annual report. Based on such evaluation, they have concluded that, as of the end of the year covered by this annual report, our disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time period specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure.

This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the Company’s registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

ITEM 16.

[RESERVED]

ITEM 16A.

AUDIT COMMITTEE FINANCIAL EXPERT.

See “Item 6.C—Board Practices—Audit Committee.” Our board of directors has determined that Mr. Daniel Villalba qualifies as an “audit committee financial expert” under applicable SEC rules.

ITEM 16B.

CODE OF ETHICS.

Our Board of Directors has adopted a code of conduct for our employees, officers and directors to govern their relations with current and potential customers, fellow employees, competitors, government and self-regulatory agencies, the media, and anyone else with whom Abengoa Yield has contact. Our code of conduct is publicly available on our website at www.abengoayield.com.

ITEM 16C.

PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The following table provides information on the aggregate fees billed by our principal accountants, Deloitte, S.L., or by other firms to Abengoa Yield, classified by type of service rendered in 2014, since our inception:


	Deloitte		Other Auditors		Total
	($ in thousands)
Audit Fees		1,228		—		1,228
Audit-Related Fees		53		—		53
Tax Fees		63		400		463
All Other Fees		176		191		367

Total		1,520		591		2,111

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Audit Fees are the aggregate fees billed for professional services in connection with the audit of our Annual Consolidated Financial Statements, quarterly review of our interim financial statements and statutory audits of our subsidiaries’ financial statements under the rules of England and Wales and the countries in which our subsidiaries are organized. Also included are services that can only be provided by our auditor, such as audits of non-recurring transactions, consents, comfort letters, attestation services and any audit services required for SEC or other regulatory filings.

Audit-Related Fees are fees charged for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements, and are not restricted to those that can only be provided by the auditor signing the audit report. This category comprises fees billed advisory services associated with our financial reporting process and assistance with training of personnel in financial related subjects.

The Audit Committee approved all of the services provided by Deloitte, S.L. and by other member firms of Deloitte.

Tax Fees are fees billed for tax compliance, tax review and tax advice on actual or contemplated transactions.

All Other Fees comprises fees billed in relation to financial advisory services, internal control advisory, issuance of comfort letters in connection with capital markets transactions and other services which cannot be comprised under other categories.

Audit Committee’s Policy on Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor

Subject to the approval of the independent auditor by our shareholders, the Audit Committee has the sole authority to appoint, retain or replace the independent auditor. The Audit Committee is also directly responsible for the compensation and oversight of the work of the independent auditor. These policies generally provide that we will not engage our independent auditors to render audit or non-audit services unless the service is specifically approved in advance by the Audit Committee. The Audit Committee’s pre-approval policy, which covers audit and non-audit services provided to us or to any of our subsidiaries, is as follows:

•

The Audit Committee shall review and approve in advance the annual plan and scope of work of the independent external auditor, including staffing of the audit, and shall (i) review with the independent external auditor any audit-related concerns and management’s response and (ii) confirm that any examination is performed in accordance with the relevant accounting standards;

•

The Audit Committee shall pre-approve all audit services and all permitted non-audit services (including the fees and terms thereof) to be performed for us by the independent auditors, to the extent required by law. The Audit Committee may delegate to one or more Committee members the authority to grant pre-approvals for audit and permitted non-audit services to be performed for us by the independent auditor, provided that decisions of such members to grant pre-approvals shall be presented to the full Audit Committee at its next regularly scheduled meeting;

•

The list of audit services and all permitted non-audit services (including the fees and terms thereof) to be performed for us by the independent auditors pre-approved by the Audit Committee, considering that these services clearly allowed from the point of independence is the following:

•

Audit services, including audit of financial statements, limited reviews, comfort letters, other verification works requested by regulator or supervisors;

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•

Audit-related services, including due diligence services, verification of corporate social responsibility report, accounting or internal control advisory and preparation courses on these topics;

•

Tax services;

•

Other specific services, such as evaluation of the design, implementation and operation of a financial information system or control over financial reporting; and

•

Courses or seminars.

Only for information purpose, all audit and non-audit services will be reported to the Audit Committee on a quarterly basis;

Any other service shall be pre-approved by the Audit Committee. However, when for reasons of urgency, it is necessary to start the provision of services prior to the next meeting of the Audit Committee, the Chairman of the Committee is authorized to provide such approval which shall be shall be communicated to the Audit Committee subsequently.

In accordance with the above pre-approval policy, all audit and permitted non-audit services performed for us by our principal accountants, or any of its affiliates, were approved by the Audit Committee of our board of directors, who concluded that the provision of such services by the independent accountants was compatible with the maintenance of that firm’s independence in the conduct of its auditing functions: an auditor may not function in the role of management; an auditor may not audit his or her own work; and an auditor may not serve in an advocacy role for his or her client.

The Audit Committee approved 100% of the services provided by Deloitte, S.L., including audit services, audit-related services, and all Other Fees for the year 2014.

ITEM 16D.

EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES.

Under the NASDAQ listing standards mandated by Rule 10A3(b) of the Exchange Act (which require, among other things, that each member of the Audit Committee of a listed company be independent), we are not required to have a fully-independent audit committee until one year from the effective date of our initial public offering in the United States. We expect that by the first anniversary of our initial public offering in the United States, all members of our Audit Committee members will be independent as required by NASDAQ listing standards and SEC requirements.

ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS.

Not applicable.

ITEM 16F.

CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT.

Not applicable.

ITEM 16G.

CORPORATE GOVERNANCE.

For purposes of the NASDAQ rules, we are 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. Abengoa controls more than 50% of the combined voting power of

168

our shares and has 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. Accordingly, we are 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 are not 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, 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 currently comply with the requirements of the Sarbanes-Oxley Act and the NASDAQ rules.

In addition, on December 9, 2014, we entered into the Governance MOU with Abengoa pursuant to which we and Abengoa agreed to work jointly for a period of seven months to amend our corporate governance regulations to (i) ensure that none of our shareholders, including Abengoa, shall have the right to appoint or recommend either the majority or even half of our directors, even if such shareholder (including Abengoa) owns a majority of our shares, (ii) expand the list of strategic matters that require approval by our board of directors, including significant investments, divestitures and indebtedness and (iii) ensure that Abengoa will not be entitled to exercise more than 40% of the voting rights in relation to us. See “Item 7.B—Related Party Transactions.”

ITEM 16H.

MINE SAFETY DISCLOSURE.

Not applicable.

PART III.

ITEM 17.

FINANCIAL STATEMENTS.

We have elected to provide financial statements pursuant to Item 18.

ITEM 18.

FINANCIAL STATEMENTS.

Our Annual Consolidated Financial Statements are included at the end of this annual report.

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ITEM 19.

EXHIBITS.

The following exhibits are filed as part of this annual report:


Exhibit No.		Description

1.1		Articles of Association of Abengoa Yield plc.

4.1		Amended and Restated Right of First Offer Agreement by and between Abengoa Yield plc and Abengoa, S.A., dated December 9, 2014 (incorporated by reference to Exhibit 10.1 to Abengoa Yield plc’s Registration Statement on Form F-1 filed with the SEC on December 11, 2014 – SEC File No. 333-200848).

4.2		Executive Services Agreement by and between Abengoa Yield plc and Abengoa Concessions, S.L. (incorporated by reference to Exhibit 10.2 to Abengoa Yield plc’s draft registration statement on Form F-1 submitted to the SEC on February 28, 2014 – SEC File No. 377-00503).

4.3		Support Services Agreement by and between Abengoa Yield plc and Abengoa Concessions, S.L. (incorporated by reference to Exhibit 10.3 to Abengoa Yield plc’s draft registration statement on Form F-1 submitted to the SEC on February 28, 2014 – SEC File No. 377-00503).

4.4		Financial Support Agreement by and between Abengoa Yield plc and Abengoa, S.A. (incorporated by reference to Exhibit 10.4 to Abengoa Yield plc’s draft registration statement on Form F-1 submitted to the SEC on February 28, 2014 – SEC File No. 377-00503).

4.5		Trademark License Agreement by and between Abengoa Yield plc and Abengoa, S.A. (incorporated by reference to Exhibit 10.5 to Abengoa Yield plc’s draft registration statement on Form F-1 submitted to the SEC on February 28, 2014 – SEC File No. 377-00503).

4.6		Deed between Abengoa Yield plc and Abengoa Concessions Investments Limited (incorporated by reference to Exhibit 10.6 to Abengoa Yield plc’s Form F-1/A filed with the SEC on April 28, 2014 – SEC File No. 333-194970).

4.7		Shareholders Agreement by and among Abengoa Construcao Brasil Ltd., Sociedad Inversora Lineas de Brasil S.L., Abengoa Concessions, S.L. and Abengoa Concessao Brasil Holding, S.A. (incorporated by reference to Exhibit 10.6 to Abengoa Yield plc’s Form F-1/A filed with the SEC on April 28, 2014 – SEC File No. 333-194970).

4.8		Operation and Maintenance Agreement between Abengoa Solar Espana, S.A. and Solaben Electricidad Dos, S.A., dated December 10, 2012 (incorporated by reference to Exhibit 10.8 to Abengoa Yield plc’s draft registration statement on Form F-1 submitted to the SEC on February 28, 2014 – SEC File No. 377-00503).

4.9		Operation and Maintenance Agreement between Abengoa Solar Espana, S.A. and Solaben Electricidad Tres, S.A., dated December 10, 2012 (incorporated by reference to Exhibit 10.9 to Abengoa Yield plc’s draft registration statement on Form F-1 submitted to the SEC on February 28, 2014 – SEC File No. 377-00503).

4.10		Indenture dated November 17, 2014, by and among Abengoa Yield plc, as issuer, Abengoa Concessions Peru, S.A., Abengoa Solar US Holdings Inc. and Abengoa Solar Holdings USA Inc., as guarantors, The Bank of New York Mellon, as trustee, registrar, paying agent and transfer agent, and The Bank of New York Mellon (Luxembourg) S.A., as Luxembourg paying agent and Luxembourg transfer agent, relating to the issuance and sale by Abengoa Yield plc of $255,000,000 aggregate principal amount of 7.000% Senior Notes due 2019 (incorporated by reference to Exhibit 10.10 to Abengoa Yield plc’s Registration Statement on Form F-1 filed with the SEC on December 11, 2014 – SEC File No. 333-200848).

170


Exhibit No.		Description

4.11		Form of Global Notes relating to the issuance and sale by Abengoa Yield plc of $255,000,000 aggregate principal amount of 7.000% Senior Notes due 2019 (incorporated by reference to Exhibit 10.11 to Abengoa Yield plc’s Registration Statement on Form F-1 filed with the SEC on December 11, 2014 – SEC File No. 333-200848).

4.12		Call Option Agreement by and between Abengoa Yield plc and Abengoa, S.A., dated December 9, 2014 (incorporated by reference to Exhibit 10.12 to Abengoa Yield plc’s Registration Statement on Form F-1 filed with the SEC on December 11, 2014 – SEC File No. 333-200848).

4.13		Underwriting Agreement dated January 15, 2015, by and among Abengoa Yield plc, Abengoa Concessions Investments Limited, Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated related to the offer and sale by Abengoa Concessions Investment Limited of up to 10,580,000 ordinary shares of Abengoa Yield plc (incorporated by reference to Exhibit 1.1 to Abengoa Yield plc’s Registration Statement on Form F-1/A filed with the SEC on January 12, 2015 – SEC File No. 333-200848).

8.1		Subsidiaries of Abengoa Yield plc.

12.1		Certification of Santiago Seage, Chief Executive Officer of Abengoa Yield plc, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

12.2		Certification of Eduard Soler, Chief Financial Officer of Abengoa Yield plc, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

13.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

171

SIGNATURE

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

Date: February 23, 2015


ABENGOA YIELD PLC

By:		/s/ Santiago Seage
Name:		Santiago Seage
Title:		Chief Executive Officer


ABENGOA YIELD PLC

By:		/s/ Eduard Soler
Name:		Eduard Soler
Title:		Chief Financial Officer

172

ABENGOA YIELD PLC

INDEX TO FINANCIAL STATEMENTS

Annual Consolidated Financial Statements as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012


Report of Independent Registered Public Accounting Firm			F-2
Consolidated statements of financial position as of December 31, 2014 and 2013			F-3
Consolidated income statements for the years ended December 31, 2014, 2013 and 2012			F-5
Consolidated financial statements of comprehensive income for the years ended December 31, 2014, 2013 and 2012			F-7
Consolidated statements of changes in equity for the years ended December 31, 2014, 2013 and 2012			F-8
Consolidated cash flow statements for the years ended December 31, 2014, 2013 and 2012			F-10
Notes to the annual consolidated financial statements			F-11
Appendix I: Entities included in the Company as subsidiaries as of December 31, 2014			F-50
Appendix II: Investments recorded under the equity method as of December 31, 2014			F-52
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, 2014 and 2013			F-53
Appendix IV (Schedule I) Condensed Financial Statements of Abengoa Yield plc			F-59

F-1

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 and Shareholders of

Abengoa Yield plc:

We have audited the accompanying consolidated statements of financial position of Abengoa Yield plc and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated income statements, the consolidated statements of comprehensive income (loss), the consolidated statements of changes in equity and the consolidated cash flow statements for each of the three years in the period ended December 31, 2014. These consolidated financial statements are the responsibility of Company’s management. Our responsibility is to express an opinion on these consolidated 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 Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits 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 statements presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Abengoa Yield plc and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with International Financial Reporting Standards, as issued by the International Accounting Standards Board (“IFRS-IASB”).

As discussed in Note 2, the combined financial statements of the Company as of December 31, 2013 were prepared as a combination of the historical accounts of the companies that composed the Company and 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.

/s/ Deloitte, S.L.

Seville, Spain

February 23, 2015

F-2

Consolidated statements of financial position as of December 31, 2014 and 2013

Amounts in thousands of U.S. dollars


	Note (1)	As of December 31, 2014		As of December 31, 2013

Assets
Non-current assets
Contracted concessional assets	6		6,725,178		4,418,120
Investments carried under the equity method	7		5,711		387,324
Other receivable accounts	8		368,964		15,230
Derivative assets	8&9		4,597		13,622
Financial investments	8		373,561		28,852
Deferred tax assets	18		124,210		52,784

Total non-current assets			7,228,660		4,887,080


Current assets
Inventories			22,068		5,244
Trade receivables	11		78,521		26,649
Credits and other receivables	11		51,175		70,948
Clients and other receivables	8&11		129,696		97,597
Financial investments	8		229,417		266,363
Cash and cash equivalents	8&12		354,154		357,664

Total current assets			735,335		726,868



Total assets			7,963,995		5,613,948

(1)	Notes 1 to 23 are an integral part of the consolidated financial statements

F-3

Consolidated statements of financial position as of December 31, 2014 and 2013

Amounts in thousands of U.S. dollars


	Note (1)	As of December 31, 2014			As of December 31, 2013
Equity and liabilities
Equity attributable to the parent company
Share capital	13		8,000			—
Parent company reserves	13		1,790,135			—
Hedging reserves			(15,539	)		(36,600	)
Accumulated currency translation differences			(28,963	)		9,009
Retained earnings	13		(2,031	)		—
Other equity			—			1,245,510
Non-controlling interest	13		88,029			69,279

Total equity			1,839,631			1,287,198


Non-current liabilities
Long-term corporate debt	14		376,160			—
Borrowings			2,970,984			2,736,552
Notes and bonds			520,893			105,786
Long-term project debt	15		3,491,877			2,842,338
Grants and other liabilities	16		1,367,601			650,903
Related parties	10		77,961			492,534
Derivative liabilities	9		168,931			44,221
Deferred tax liabilities	18		60,818			21,839

Total non-current liabilities			5,543,348			4,051,835


Current liabilities
Short-term corporate debt	14		2,255			—
Borrowings			323,250			49,540
Notes and bonds			7,939			2,772
Short-term project debt	15		331,189			52,312
Trade payables and other current liabilities	17		231,132			204,013
Income and other tax payables			16,440			18,590

Total current liabilities			581,016			274,915



Total equity and liabilities			7,963,995			5,613,948

(1)	Notes 1 to 23 are an integral part of the consolidated financial statements

F-4

Consolidated income statements for the years ended December 31, 2014, 2013 and 2012

Amounts in thousands of U.S. dollars


	Note (1)	For the twelve-month period ended December 31,
	Note (1)	2014			2013			2012
Revenue	4		362,693			210,907			107,183
Other operating income	20		79,913			379,644			560,372
Raw materials and consumables used			(21,321	)		(8,671	)		(4,289	)
Employee benefit expenses			(1,664	)		(2,446	)		(1,789	)
Depreciation, amortization, and impairment charges	6		(125,480	)		(46,943	)		(20,234	)
Other operating expenses	20		(120,798	)		(420,905	)		(573,510	)

Operating profit/(loss)			173,343			111,586			67,733


Financial income	21		4,911			1,153			718
Financial expense	21		(210,252	)		(123,784	)		(64,104	)
Net exchange differences			2,054			(895	)		392
Other financial income/(expense), net	21		5,861			(1,693	)		(173	)

Financial expense, net			(197,426	)		(125,219	)		(63,167	)


Share of profit/(loss) of associates carried under the equity method			(769	)		13			(404	)

Profit/(loss) before income tax			(24,852	)		(13,620	)		4,162


Income tax	4&18		(4,413	)		11,762			(4,021	)

Profit/(loss) for the year			(29,265	)		(1,858	)		141


Loss/(profit) attributable to non-controlling interests			(2,347	)		(1,559	)		1,195

Profit/(loss) for the year attributable to the parent company			(31,612	)		(3,417	)		1,336


Less: Predecessor Loss prior to Initial Public Offering on June 12, 2014	22		(28,233	)

Net profit/(loss) attributable to Abengoa Yield plc subsequent to Initial Public Offering	22		(3,379	)

Weighted average number of ordinary shares outstanding (thousands)	22		80,000

*Basis earnings per share attributable to Abengoa Yield plc (U.S. dollar per share) ()**	22		(0.04	)

(*)	Earnings per share has been calculated for the period subsequent to the initial public offering, considering Net profit/(loss) attributable to equity holders of Abengoa Yield Plc. generated after the initial public offering divided by the number of shares outstanding.

(1)	Notes 1 to 23 are an integral part of the consolidated financial statements

F-5

The consolidated income statements include the following income (expense) items arising from transactions with related parties:


	For the twelve-month ended December 31,
	2014			2013			2012
Sales		25,673			11,925			5,089
Construction costs		(38,565	)		(364,715	)		(558,620	)
Services rendered		2,343			2,804			3,527
Services received		(41,961	)		(24,403	)		(8,742	)
Purchases		—			(2,669	)		(177	)
Financial income		4,415			468			575
Financial expenses		(9,544	)		(11,209	)		(4,525	)

F-6

Consolidated financial statements of comprehensive income for the years ended December 31, 2014, 2013 and 2012

Amounts in thousands of U.S. dollars


	Note (1)	For the twelve-month period ended December 31,
	Note (1)	2014			2013			2012
Profit/(loss) for the year			(29,265	)		(1,858	)		141
Items that may be subject to transfer to income statement
Change in fair value of cash flow hedges			(117,423	)		75,907			(41,320	)
Currency translation differences			(51,226	)		8,941			3,521
Tax effect			33,473			(22,494	)		12,396

Net income/(expenses) recognized directly in equity			(135,176	)		62,354			(25,403	)


Cash flow hedges			29,859			27,513			5,916
Tax effect			(8,958	)		(8,254	)		(1,775	)

Transfers to income statement			20,901			19,259			4,141



Other comprehensive income/(loss)			(114,275	)		81,613			(21,262	)



Total comprehensive income/(loss) for the year			(143,540	)		79,755			(21,121	)


Total comprehensive income/(loss) attributable to non-controlling interest			(14,813	)		(9,947	)		3,399

Total comprehensive income/(loss) attributable to the parent company			(128,727	)		69,808			(17,722	)

(1)	Notes 1 to 23 are an integral part of the consolidated financial statements

F-7

Consolidated statements of changes in equity for the years ended December 31, 2014, 2013 and 2012

Amounts in thousands of U.S. dollars


	Hedging reserves			Accumulated currency translation differences		Other equity			Total equity attributable to the parent 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 period 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	)

Equity Contributions		—			—		562,920			562,920			14,090			577,010

Balance as of December 31, 2012 ^(a)		(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 for the period 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

Equity Contributions		—			—		66,919			66,919			715			67,634

Balance as of December 30, 2013 (a)		(36,600	)		9,009		1,245,510			1,217,919			69,279			1,287,198

F-8


	Share Capital		Parent company reserves			Hedging reserves			Retained earnings/ Other equity^(c)			Accumulated currency translation differences			Total equity attributable to the parent company			Non- controlling interest			Total equity
Balance as of January 1, 2014		—		—			(36,600	)		1,245,510			9,009			1,217,919			69,279			1,287,198
Profit/(loss) for the year after taxes		—		—			—			(28,233	)		—			(28,233	)		410			(27,823	)
Change in fair value of cash flow hedges		—		—			(59,277	)		—			—			(59,277	)		(4,253	)		(63,530	)
Currency translation differences		—		—			—			—			(10,660	)		(10,660	)		(4,347	)		(15,007	)
Tax effect		—		—			17,325			—			—			17,325			1,276			18,600

Other comprehensive income		—		—			(41,952	)		—			(10,660	)		(52,612	)		(7,324	)		(59,937	)

Total comprehensive income		—		—			(41,952	)		(28,233	)		(10,660	)		(80,845	)		(6,914	)		(87,760	)


Initial Public Offering and Asset Transfer		8,000		1,813,831			78,552			(1,195,862	)		1,651			706,172			—			706,172

Balance as of June 30, 2014 ^(b)		8,000		1,813,831			—			21,415			—			1,843,246			62,365			1,905,611

Profit/(loss) for six-month period after taxes		—		—			—			(3,379	)		—			(3,379	)		1,937			(1,442	)
Change in fair value of cash flow hedges		—		—			(20,236	)		—			—			(20,236	)		(3,685	)		(23,921	)
Currency translation differences		—		—			—			—			(28,963	)		(28,963	)		(7,256	)		(36,219	)
Tax effect		—		—			4,697			—			—			4,697			1,105			5,802

Other comprehensive income ^(d)		—		—			(15,539	)		—			(28,963	)		(44,502	)		(9,836	)		(54,338	)

Total comprehensive income		—		—			(15,539	)		(3,379	)		(28,963	)		(47,881	)		(7,899	)		(55,780	)

First asset acquisition under the Rofo^(e)		—		—			—			(20,067	)		—			(20,067	)		33,563			13,496

Dividend distribution		—		(23,696	)		—			—			—			(23,696	)		—			(23,696	)

Balance as of December 31, 2014 ^(b)		8,000		1,790,135			(15,539	)		(2,031	)		(28,963	)		1,751,602			88,029			1,839,631

(a)	The combined statement of changes in equity for the twelve-month period ended December 31, 2013 represents the changes in the combined equity of the assets that were transferred to Abengoa Yield plc in the Asset Transfer.

(b)	The consolidated statement of changes in equity for the six-month period ended June 30, 2014 and for the twelve-month period ended December 31, 2014 represents the changes in the consolidated equity of Abengoa Yield plc and its subsidiaries since January 1, 2014.

(c)

Loss for the six-month period after taxes amounting to ($3,379) thousands, includes the result of the Company after the Initial Public Offering up to the end of December 31^,2014. Loss attributable to the parent company for the twelve-month period ended December 31, 2014 amounting to ($31,612) thousand is included within Retained Earnings.

(d)	These amounts account for the impact in Other comprehensive income of the consolidated statements for the six-month period ended December 31, 2014.

(e)	See Note 5 for further details.

(1)	Notes 1 to 23 are an integral part of the consolidated financial statements

F-9

Consolidated cash flow statements for the years ended December 31, 2014, 2013 and 2012

Amounts in thousands of U.S. dollars


		For the year ended
	Note (1)	2014			2013			2012
I. Profit/(loss) for the year		$	(29,265	)	$	(1,858	)	$	141
Non-monetary adjustments
Depreciation, amortization and impairment charges	6		125,480			46,943			20,234
Finance (income)/expenses			206,294			95,117			57,440
Fair value gains on derivative financial instruments			2,386			8,272			1,007
Shares of (profits)/losses from associates			769			(13	)		404
Income tax	18		4,413			(11,762	)		4,021
Changes in consolidation and other non-monetary items			(48,793	)		(46,168	)		(60,269	)

II. Profit for the year adjusted by non monetary items		$	261,284		$	90,531		$	22,978


Variations in working capital
Inventories			379			(5,244	)		—
Clients and other receivables			(5,981	)		10,622			23,775
Trade payables and other current liabilities			(117,199	)		(45,110	)		16,322
Financial investments and other current assets/liabilities			54,810			48,945			26,527

III. Variations in working capital		$	(67,991	)	$	9,213		$	66,624


Income tax paid			(428	)		(73	)		(255	)
Interest received			256			640			718
Interest paid			(149,513	)		(62,923	)		(42,083	)

A. Net cash provided by operating activities		$	43,608		$	37,388		$	47,982


Investments in entities under the equity method	4		(44,524	)		(240,639	)		(554,276	)
Investment in contracted concessional assets	4		(56,960	)		(401,678	)		(518,495	)
Other non-current assets/liabilities			(21,339	)		(52,250	)		(25,929	)
Acquisitions of subsidiaries			(222,345	)		—			—

B. Net cash used in investing activities		$	(345,168	)	$	(694,567	)	$	(1,098,700	)


Proceeds from Project & Corporate debt	14&15		1,350,689			1,139,671			339,550
Repayment of Project & Corporate debt	14&15		(1,665,433	)		(667,784	)		(61,620	)
Dividends paid to company´s shareholders			(23,696	)		—			—
Proceeds from related parties and other			(39,035	)		442,986			829,322
Proceeds IPO			681,916			—			—

C. Net cash provided by financing activities		$	304,441		$	914,873		$	1,107,252

Net increase/(decrease) in cash and cash equivalents		$	2,881		$	257,694		$	56,534


Cash, cash equivalents and bank overdrafts at beginning of the year	12		357,664			97,499			40,171
Translation differences cash or cash equivalent			(6,391	)		2,471			794

Cash and cash equivalents at end of the year	12	$	354,154		$	357,664		$	97,499

(1)	Notes 1 to 23 are an integral part of the consolidated financial statements

F-10

Contents


Note 1.- Nature of the business			F-12

Note 2.- Significant accounting policies			F-13

Note 3.- Financial risk management			F-24

Note 4.- Financial information by segment			F-25

Note 5.- Changes in the scope of the combined financial statements			F-30

Note 6.- Contracted concession assets			F-32

Note 7.- Investments carried under the equity method			F-33

Note 8.- Financial Instruments by category			F-34

Note 9.- Derivative financial instruments			F-35

Note 10.- Related parties			F-36

Note 11.- Clients and other receivable			F-38

Note 12.- Cash and cash equivalents			F-39

Note 13.- Equity			F-39

Note 14.- Corporate debt			F-40

Note 15.- Project debt			F-40

Note 16.- Grants and other liabilities			F-42

Note 17.-Trade payables and other current liabilities			F-43

Note 18.- Income tax			F-43

Note 19.- Third-party guarantees and commitments			F-46

Note 20.- Other operating income and expenses			F-46

Note 21.- Financial income and expenses			F-47

Note 22.- Earnings per share			F-48

Note 23.- Other information			F-49

Appendices⁽¹⁾			F-50

(1)	The Appendices are an integral part of the notes to the consolidated financial statements.

F-11

Note 1.- Nature of the business

Abengoa Yield plc (‘Abengoa Yield’ or the Company) 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 total return company formed to serve as the primary vehicle through which Abengoa owns, manages, and acquires 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, Brazil 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. Abengoa has developed a unique and integrated business model that applies accumulated engineering expertise to promoting sustainable development solutions.

On June 18, 2014 Abengoa Yield closed its initial public offering issuing 24,850,000 ordinary shares. The shares were offered at a price of $29 per share, resulting in gross proceeds to the Company of $720,650 thousand. The underwriters further purchased 3,727,500 additional shares from the selling shareholder, a subsidiary wholly owned by Abengoa, at the public offering price less fees and commissions to cover over-allotments (“greenshoe”) driving the total proceeds of the offering to $828,748 thousand.

Prior to the consummation of this offering, Abengoa contributed, through a series of transactions, which we refer to collectively as the “Asset Transfer,” ten concessional assets described below, certain holding companies and a preferred equity investment in Abengoa Concessoes Brasil Holding (“ACBH”), which is a subsidiary of Abengoa engaged in the development, construction, investment and management of contracted concessions in Brazil, comprised mostly of transmission lines. As consideration for the Asset Transfer, Abengoa received a 64.28% interest in Abengoa Yield and $655.3 million in cash, corresponding to the net proceeds of the initial public offering less $30 million retained by Abengoa Yield for liquidity purposes.

Abengoa Yield’s shares began trading on the NASDAQ Global Select Market under the symbol “ABY” on June 13, 2014.

On September 22, 2014, the Company entered into an agreement with Abengoa to perform the first acquisition of assets under the Rofo agreement (“First Dropdown Assets”). On November 18, 2014, the Company completed the acquisition of Solacor 1/2 through a 30-year usufruct rights contract over the related shares (which includes the option to purchase such shares for one euro during a four-year term); on December 4, 2014, the Company completed the acquisition of PS10/20; and on December 29, 2014, the Company completed the acquisition of Cadonal. The total aggregate consideration for this first assets acquisition under Rofo agreementwas $312 million. Solacor 1/2 are Solar assets located in Spain with a capacity of 100 MW, PS 10/20 are Solar assets located in Spain with a capacity of 31 MW and Cadonal is a 50 MW wind farm located in Uruguay.

The portfolio of assets which are now owned by Abengoa Yield consists of ten renewable energy assets, a cogeneration facility, and several electric transmission lines, all of which are fully operational as of today. All the 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 24 years as of December 31, 2014. The 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 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 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.

The following table provides an overview of our current assets (excluding our exchangeable preferred equity investment in ACBH):

Our Assets

Type

Ownership

Location

Currency⁽³⁾

Capacity
(Gross)

Counterparty
Credit Ratings⁽⁴⁾

COD

Contract
Years Left

Solana

Renewable
(Solar)

100

Class B

Arizona (USA)

USD

280 MW

A-/A3/BBB+

4Q 2013

Mojave

Renewable
(Solar)

100

California (USA)

USD

280 MW

BBB/A3/BBB+

4Q 2014

ACT

Conventional
Power

100

Mexico

USD

300 MW

BBB+/A3/BBB+

2Q 2013

ATN

Transmission
line

100

Peru

USD

362 miles

BBB+/A3/BBB+

1Q 2011

ATS

Transmission
line

100

Peru

USD

569 miles

BBB+/A3/BBB+

1Q 2014

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Our Assets

Type

Ownership

Location

Currency⁽³⁾

Capacity
(Gross)

Counterparty
Credit Ratings⁽⁴⁾

COD

Contract
Years Left

Quadra 1

Transmission
line

100

Chile

USD

43 miles

N/A

2Q 2014

Quadra 2

Transmission
line

100

Chile

USD

38 miles

N/A

1Q 2014

Palmucho

Transmission
line

100

Chile

USD

6 miles

BBB+/Baa2/BBB+

4Q 2007

Palmatir

Renewable
(Wind)

100

Uruguay

USD

50 MW

BBB-/Baa2/BBB-⁽⁵⁾

2Q 2014

Cadonal

Renewable
(Wind)

100

Uruguay

USD

50 MW

BBB-/Baa2/BBB-⁽⁵⁾

4Q 2014

Solaben 2 & 3

Renewable
(Solar)

%⁽²⁾

Spain

Euro

2x50 MW

BBB/Baa2/BBB+

2Q 2012 &
4Q 2012

Solacor 1 & 2

Renewable
(Solar)

%⁽⁶⁾

Spain

Euro

100 MW

BBB/Baa2/BBB+

2Q 2012 &
4Q 2012

PS10/PS20⁽⁷⁾

Renewable
(Solar)

100

Spain

Euro

31 MW

BBB/Baa2/BBB+

1Q 2007 &
2Q 2009

(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, a Japanese trading company, holds 30% of the shares in each of Solaben 2 and Solaben 3. We hold a 30-year right of usufruct over the remaining shares of Solaben 2 and Solaben 3 and a call option to purchase such shares for one euro during a four-year term.

(3)	Certain contracts denominated in U.S. dollars are payable in local currency.

(4)	Reflects the counterparty’s 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.

(5)	Refers to the credit rating of Uruguay, as UTE (Administración Nacional de Usinas y Transmisoras Eléctricas) is unrated.

(6)	JGC Corporation, a Japanese engineering company, holds 26% of the shares in each of Solacor 1 and Solacor 2. We hold a 30-year right of usufruct over the remaining shares of Solacor 1 and Solacor 2 and a call option to purchase such shares for one euro during a four-year term.

(7)	PS10 and PS20 are separate special purpose vehicles with separate agreements, but they are treated as a single platform.

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 electric transmission lines.

All the project companies included in these consolidated 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, PS10 and PS20) are included within the scope of International Financial Reporting Interpretations Committee 12 (“IFRIC 12”), and given that some of them are included in the consolidated financial statements during their construction phase, the Company has recorded income and cost attributable to the construction in the consolidated income statement. Construction revenue is recorded within “Other operating income” according to the percentage of completion method as established by International Accounting Standards 11 (“IAS 11”). Construction cost, which is fully contracted with related parties, is recorded within “Other operating expense”.

These consolidated financial statements were approved by the Board of Directors on February 23, 2015.

Note 2.- Significant accounting policies

2.1 Basis of preparation

These consolidated financial statements are presented in accordance with the IFRS as issued by the IASB.

For all periods prior to the initial public offering, the combined financial statements represent the combination of the assets that Abengoa Yield acquired and were prepared using Abengoa’s historical basis in the assets and liabilities. For the purposes of the

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combined financial statements, the term “Abengoa Yield” represents the accounting predecessor, or the combination of the acquired businesses. For all periods subsequent to the initial public offering, the accompanying consolidated financial statements represent the consolidated results of the Company and its subsidiaries. The Company has elected to account for the Asset Transfer to Abengoa Yield plc using the predecessor values, given that it is a transaction 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 has been reflected as an adjustment to equity. In addition, the Company has elected to incorporate the results of the transferred entities prior to the initial public offering as if the entities had always been consolidated and the transferred entities after the initial public offering from the acquisition date.

In the fourth quarter of 2014, the Company closed the acquisition of the First Dropdown assets. Given that Abengoa Yield is a subsidiary controlled by Abengoa, the assets acquired constitute an acquisition under common control by Abengoa and accordingly, were recorded using Abengoa’s historical basis in the assets and liabilities of the Predecessor.

In the periods prior to the IPO, the combined financial statements for periods prior to the initial public offering include all revenues, expenses, assets, and liabilities attributed to the Predecessor. In addition, prior to the initial public offering, 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 condensed income statement includes a reasonable estimate of actual costs incurred to operate the business.

The consolidated financial statements are presented in U.S. dollars, which is the Company’s functional and presentation currency. Amounts included in these consolidated 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, 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 under the IFRS approved by the International Accounting Standards Board, hereinafter IFRS-IASB, and is to be applied retroactively.

•

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 under IFRS-IASB.

•

IAS 39 (Amendment) ‘Novation of Derivatives and Continuation of Hedge Accounting’. The IAS 39 amendment is for periods beginning on or after January 1, 2014 under IFRS-IASB.

•

IFRIC 21 (Interpretation) ‘Levies’. The IFRIC 21 is mandatory for periods beginning on or after January 1, 2014 under IFRS-IASB.

The amendments and interpretations effective from January 1, 2014 have not had any significant impact on these consolidated financial statements.

b)	Standards, interpretations and amendments published by the IASB that will be effective for periods beginning on or after January 1, 2015:

•

Annual Improvements to IFRSs 2010-2012 and 2011-2013 cycles. These improvements are mandatory for periods beginning on or after July 1, 2014 under IFRS-IASB.

•

Annual Improvements to IFRSs 2012-2014 cycle. These improvements are mandatory for periods beginning on or after January 1, 2016 under IFRS-IASB.

•

IFRS 9 ’Financial Instruments’. This Standard will be effective from January 1, 2018 under IFRS-IASB.

•

IFRS 14 ‘Regulatory Deferral Accounts’. This Standard will be effective from January 1, 2016 under IFRS-IASB.

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•

IFRS 15 ‘Revenues from contracts with Customers’. IFRS 15 is applicable for periods beginning on or after 1 January 2017 under IFRS-IASB. Earlier application is permitted. IFRS 15 has not yet been adopted by the EU.

•

IAS 16 (Amendment) ‘Property, Plant and Equipment’ and IAS 38 ‘Intangible Assets’, regarding acceptable methods of amortization and depreciation. This amendment is mandatory for periods beginning on or after January 1, 2016 under IFRS-IASB, earlier application is permitted.

•

IAS 27 (Amendment) ‘Separate financial statements’ regarding the reinstatement of the equity method as an accounting option n separate financial statements. This amendment is mandatory for periods beginning on or after January 1, 2016 under IFRS-IASB.

•

IFRS 10 (Amendment) ‘Consolidated financial statements’ and IAS 28 ‘Investments in associates and joint ventures’ regarding the exemption from consolidation for investment entities. These amendments are mandatory for periods beginning on or after January 1, 2016 under IFRS-IASB.

•

IFRS 11 (Amendment) ‘Joint Arrangements’ regarding acquisition of an interest in a joint operation. This amendment is mandatory for periods beginning on or after January 1, 2016 under IFRS-IASB, earlier application is permitted.

The Company is currently in the process of evaluating the impact on the consolidated financial statements derived from the application of the new standards and amendments that will be effective for periods beginning after December 31, 2014.

2.2. Principles to include and record companies in the consolidated financial statements

For the period subsequent to the initial public offering, subsidiaries are those entities over which Abengoa Yield has control. For the periods prior to the initial public offering, companies included in these consolidated financial statements are accounted for as subsidiaries as long as Abengoa Yield has had control over them and are accounted for as investments under the equity method as long as Abengoa Yield has had significant influence over them, in the periods presented. The group of entities included in these financial statements is referred to as the “Company”.

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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 solar plants in the United States, the Company has concluded that all the relevant decisions during the construction phase are subject to the approval of the Administration. 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´s construction phase is finished, the Company gains control over these companies which are then fully consolidated.

The Company uses the acquisition method to account for business combinations of companies controlled by a third party. 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.

Acquisitions of businesses to Abengoa are not considered business combinations, as Abengoa Yield is a subsidiary controlled by Abengoa. The assets acquired constitute an acquisition under common control by Abengoa and accordingly, were recorded using Abengoa’s historical basis in the assets and liabilities of the Predecessor.

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

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 financial statements using the equity method of accounting. Under the equity method, an investment in an associate is initially recognized in the 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.

Controlled entities and associates included in these financial statements as of December 31, 2014 and 2013, 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 project debt, related to service concession arrangements recorded in accordance with IFRIC 12, except for Palmucho, which is recorded in accordance with IAS 17 and PS10/PS20, which are recorded as tangible assets in accordance with IAS 16. 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 wind farms. 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.

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.

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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.

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.

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.

Property, plant and equipment

Property, plant and equipment includes property, plant and equipment of companies or project companies. Property, plant and equipment is measured at historical cost, including all expenses directly attributable to the acquisition, less depreciation and impairment losses, with the exception of land, which is presented net of any impairment losses.

Once the infrastructure is in operation, the treatment of income and expenses is the same as the one described above for intangible asset.

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.

2.5 Asset impairment

Abengoa Yield reviews its contracted concessional assets to identify any indicators of impairment at least 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.

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

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 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.

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.

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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.

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 consolidated 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.

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 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.

Level 2 valuation

All derivatives are classified as level 2. Abengoa Yield derivatives correspond mainly to the interest rate swaps designated as cash flow hedges.

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.

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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.

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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.

Level 3 valuation

Level 3 includes the preferred equity investment in ACBH.

Fair value of this instrument was calculated by taking as the main reference the value of the investment, which is obtained by considering expected cash-flows from the preferred equity instrument discounted at a rate appropriate for the sector in which the Company is operating. Valuation was obtained from internal models. This valuation could vary where other models and assumptions made on the principle variables had been used, however the fair value of the asset as well as the results generated by this financial instrument are considered reasonable.

Detailed information on fair values is included in Note 8.

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 consolidated statement of financial position and are recognized in “Other operating income” in the consolidated 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 consolidated income statement over the duration of the borrowing using the effective interest rate method.

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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 consolidated statement of financial position, and subsequently recorded in “Other operating income” in the consolidated 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 consolidated 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 consolidated statement of financial position in the countries in which the subsidiaries and associates operate and generate taxable income.

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 consolidated 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 consolidated 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.

F-22

2.17. 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 consolidated financial statements. These balances have been presented separately in Equity.

Non-controlling interest represents interest from other partners in entities included in these consolidated financial statements which are not fully owned by Abengoa Yield as of the dates presented.

Parent company reserves together with the Share capital represent the Parent’s net investment in the entities included in these consolidated financial statements.

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 consolidated 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 consolidated statements of financial position unless they have been acquired in a business combination.

Some companies included in the 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 concessional 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 consolidated 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, 2014, are expected.

F-23

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 loss exposure.

•

Interest rate risk

Interest rate risk arises when the Company’s activities are exposed to changes in 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:

Project debt in U.S. dollars: between 75% and 100% of the notional amount, maturities until 2043 average guaranteed interest rates of between 2.75% and 6.32%.

Project debt in euro: between 80% and 100% of the notional amount, maturities until 2030 and average guaranteed interest rates of between 3.13% and 4.75%.

In connection with our interest rate derivative positions, the most significant impacts on our consolidated 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, 2014, with the rest of the variables remaining constant, the effect in the consolidated income statement would have been a loss of $ 271 thousand (a profit of $195 thousand in 2013) and an increase in hedging reserves of $24.177 thousand ($16,328 thousand in 2013). 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, 2014 and 2013, is provided in Note 9.

•

Currency risk

The main cash flows in the entities included in these consolidated 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, a natural hedge exists for the main operations of the Company.

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.

F-24

Project finance borrowing permits the Company to finance the project through project 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.

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, as of December 31, 2014 the Company had the following business sectors:

Renewable energy: Our renewable energy assets include two Solar 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 reached COD on December 1, 2014. Additionally, we own two wind farms in Uruguay, Palmatir and Cadonal, with a gross capacity of 50 MW each. Palmatir and Cadonal respectively reached COD in May and December 2014. Finally, Solacor 1 and 2 with a gross capacity of 100 MW, PS10 and PS20 with a gross capacity of 31 MW and Solaben 2 and 3 with a gross capacity of 100 MW are Solar plants located in Spain. These projects have been in operation respectively since mid-2012 for Solaben 2 and Solacor 1 and 4Q 2012 for Solaben 3, and Solacor 2, 1Q 2007 for PS10 and 2Q 2009 for PS20, and receive regulated revenues under the framework for renewable projects in Spain.

Conventional power: Our conventional power asset consists 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. In addition, 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 electric transmission lines.

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 Further Adjusted EBITDA as measure of the performance of each segment. Further Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest from continued operations, income tax, share of profit/(loss) of associates carried under the equity method, finance expense net, depreciation, amortization and impairment charges of entities included in these consolidated financial statements, and dividends received from our preferred equity investment in ACBH. In order to assess performance of the business, the CODM receives reports of each reportable segment using revenues and Further Adjusted EBITDA. Net interest expense evolution is assessed on a consolidated basis. Financial expense and amortization are not taken into consideration by the CODM for the allocation of resources. Further Adjusted EBITDA includes the dividends received from ACBH, our Brazil preferred equity investment.

In the year ended December 31, 2014, Abengoa Yield had three customers with revenues representing more than 10% of the total revenues, i.e., one in the renewable energy, one in the conventional power and one in the electric transmission lines business sectors.

The following tables show Revenues and Further Adjusted EBITDA by operating segments and business sectors for the years 2014, 2013 and 2012:


	Revenue						Further Adjusted EBITDA
	For the twelve-month period ended December 31,						For the twelve-month period ended December 31,
Geography	2014		2013		2012		2014		2013		2012
North America	$	195,508	$	113,998	$	62,268	$	175,398	$	96,712	$	61,106
South America		83,592		25,392		16,986		77,188		18,979		10,191
Europe		83,593		71,517		27,929		55,437		42,838		16,670

Total	$	362,693	$	210,907	$	107,183	$	308,023	$	158,529	$	87,967

F-25


	Revenue						Further Adjusted EBITDA
	For the twelve-month period ended December 31,						For the twelve-month period ended December 31,
Business sectors	2014		2013		2012		2014		2013		2012
Renewable energy	$	170,673	$	82,714	$	27,929	$	137,820	$	55,797	$	16,121
Conventional power		118,765		102,801		62,268		101,896		83,277		61,106
Electric transmission lines		73,255		25,392		16,986		68,307		19,455		10,740

Total	$	362,693	$	210,907	$	107,183	$	308,023	$	158,529	$	87,967

The reconciliation of segment Further Adjusted EBITDA with the profit/(loss) attributable to the parent company is as follows:


	For the twelve-month period ended December 31,
	2014			2013			2012
Total segment Further Adjusted EBITDA	$	308,023		$	158,529		$	87,967
Depreciation, amortization, and impairment charges		(125,480	)		(46,943	)		(20,234	)
Financial expense, net		(197,426	)		(125,219	)		(63,167	)
Dividend from exchangeable preferred equity investment in ACBH		(9,200	)		—			—
Share in profits/(losses) associates		(769	)		13			(404	)
Income tax		(4,413	)		11,762			(4,021	)
Profit attributable to non-controlling interests		(2,347	)		(1,559	)		1,195

Profit/(Loss) attributable to the parent company	$	(31,612	)	$	(3,417	)	$	1,336

b) The assets and liabilities by operating segments (and business sector) at the end of 2014 and 2013 are as follows:

Assets and liabilities by geography as of December 31, 2014:


	North America		South America		Europe		Balance as of December 31, 2014
Assets allocated
Contracted concessional assets		4,185,638		1,159,652		1,379,888		6,725,178
Investments carried under the equity method		—		—		5,711		5,711
Current financial investments		175,339		54,012		66		229,417
Cash and cash equivalents (project companies)		49,030		37,623		112,133		198,786

Subtotal allocated		4,410,007		1,251,287		1,497,798		7,159,092

Unallocated assets
Other non-current assets								497,771
Other current assets (including cash and cash equivalents at holding company level)								307,132

Subtotal unallocated								804,903

Total assets								7,963,995

F-26

North
America

South America

Europe

Balance as of
December 31,
2014

Liabilities allocated

Long-term and short-term project debt

2,121,916

804,460

896,690

3,823,066

Subtotal allocated

2,121,916

804,460

896,690

3,823,066

Unallocated liabilities

Long-term and short-term corporate debt

378,415

Other non-current liabilities

1,675,311

Other current liabilities

247,572

Subtotal unallocated

2,301,298

Total liabilities

6,124,364

Equity unallocated

1,839,631

Total liabilities and equity unallocated

4,140,929

Total liabilities and equity

7,963,995

Assets and liabilities by geography as of December 31, 2013:


	North America		South America		Europe		Balance as of December 31, 2013
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 (project companies)		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


	North America		South America		Europe		Balance as of December 31, 2013
Liabilities allocated
Long-term and short-term project debt	$	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

F-27

Assets and liabilities by business sectors as of December 31, 2014:


	Renewable energy		Conventional power		Electric transmission lines		Balance as of December 31, 2014
Assets allocated
Contracted concessional assets		5,178,459		646,842		899,877		6,725,178
Investments carried under the equity method		5,711		—		—		5,711
Current financial investments		64,449		110,959		54,009		229,417
Cash and cash equivalents (project companies)		156,867		17,612		24,307		198,786

Subtotal allocated		5,405,486		775,413		978,193		7,159,092

Unallocated assets
Other non-current assets								497,771
Other current assets (including cash and cash equivalents at holding company level)								307,132

Subtotal unallocated								804,903

Total assets								7,963,995

Renewable
energy

Conventional
power

Electric
transmission
lines

Balance as of
December 31,
2014

Liabilities allocated

Long-term and short-term project debt

2,579,221

625,135

618,710

3,823,066

Subtotal allocated

2,579,221

625,135

618,710

3,823,066

Unallocated liabilities

Long-term and short-term corporate debt

378,415

Other non-current liabilities

1,675,311

Other current liabilities

247,572

Subtotal unallocated

2,301,298

Total liabilities

6,124,364

Equity unallocated

1,839,631

Total liabilities and equity unallocated

4,140,929

Total liabilities and equity

7,963,995

Assets and liabilities by business sectors as of December 31, 2013:


	Renewable energy		Conventional power		Electric transmission lines		Balance as of December 31, 2013
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

F-28


	Renewable energy		Conventional power		Electric transmission lines		Balance as of December 31, 2013
Liabilities allocated
Long-term and short-term project debt	$	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

The investment in contracted concessional assets and in entities under the equity method by operating segments and business sectors for the years 2014 and 2013 are as follows:


	Capex
	For the twelve-month period ended December 31,
Geography	2014		2013		2012
North America		51,492		347,397		628,011
South America		49,992		294,658		293,909
Europe		—		262		150,851

Total		101,484		642,317		1,072,771


	Capex
	For the twelve-month period ended December 31,
Business sectors	2014		2013		2012
Renewable energy		59,206		323,251		753,878
Conventional power		—		106,757		73,735
Electric transmission lines		42,278		212,309		245,158

Total		101,484		642,317		1,072,771

The amount of depreciation and amortization expense recognized for the years ended December 31, 2014, 2013 and 2012 are as follows:


	For the twelve-month period ended December 31,
Depreciation and amortization by geography	2014			2013			2012
North America		(70,777	)		(16,182	)		—
South America		(31,990	)		(10,853	)		(10,871	)
Europe		(22,713	)		(19,908	)		(9,363	)

Total		(125,480	)		(46,943	)		(20,234	)


	For the twelve-month period ended December 31,
Depreciation and amortization by business sectors	2014			2013			2012
Renewable energy		(98,107	)		(36,090	)		(9,363	)
Electric transmission lines		(27,373	)		(10,853	)		(10,871	)

Total		(125,480	)		(46,943	)		(20,234	)

F-29

Note 5.- Changes in the scope of the consolidated financial statements

For the year ended December 31, 2014.

Mojave Solar LLC

On December 1, 2014, Mojave Solar, LLC, the Company that holds the assets in Mojave, 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 Mojave plant all the relevant decisions were subject to the control and approval of the Administration. 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´s construction phase was finished, 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.

First asset acquisition under the Rofo agreement

On September 22, 2014, we entered into an agreement with Abengoa, subject to financing and negotiations of definitive documentation and certain other conditions, to acquire the First Dropdown Assets. On November 18, 2014, we completed the acquisition of Solacor 1/2 through a 30-year usufruct rights contract over the related shares (which includes the option to purchase such shares for one euro during a four-year term); on December 4, 2014, we completed the acquisition of PS10/20; and on December 29, 2014, we completed the acquisition of Cadonal. The total aggregate consideration for the First Dropdown Assets was $312 million. Solacor 1/2 are Solar assets located in Spain with a capacity of 100 MW, PS 10/20 are Solar assets located in Spain with a capacity of 31 MW and Cadonal is a 50 MW wind farm located in Uruguay.

Given that Abengoa Yield is a subsidiary controlled by Abengoa, the assets acquired constitute an acquisition under common control by Abengoa and accordingly, were recorded using Abengoa’s historical basis in the assets and liabilities of the Predecessor. The difference between the cash proceeds and historical value of the net assets was recorded in equity. Results of operations of the assets acquired have been recorded in Abengoa Yield’s consolidated income statement since the date of the acquisition.

Impact of changes in the scope in the consolidated financial statements

The amount of assets and liabilities integrated at the effective acquisition date for the aggregated change in scope is shown in the following table:


	Total			First asset acquisition under Rofo agreement			Mojave
Concession assets (Note 6)		2,583,946			1,010,030			1,573,916
Amortization (Note 6)		(108,191	)		(108,191	)		—
Deferred tax asset (Note 18)		20,230			20,230			—
Other non-current assets		21,837			1,555			20,282
Current assets		144,734			138,692			6,042
Project debt long term (Note 15)		(1,401,107	)		(592,115	)		(808,992	)
Deferred tax liabilities (Note 18)		(2,526	)		(2,526	)		—
Project debt short term (Note 15)		(39,445	)		(28,284	)		(11,161	)
Other current and non-current liabilities		(468,349	)		(113,630	)		(354,719	)
Book value of previously held interest for Mojave (Note 7)		(425,368	)		—			(425,368	)
First asset acquisition under Rofo - purchase price		(312,265	)		(312,265	)		—
Non-controlling interests		(33,563	)		(33,563	)		—

Net result of the asset acquisition		(20,067	)		(20,067	)		—

F-30

The results of operations of Mojave Solar LLC and the first asset acquisition under Rofo have been included in the consolidated financial statement from the acquisition date (revenue of $9 million and loss of $6 million).

Had the first asset acquisition under Rofo been consolidated from January 1, 2014, the consolidated statement of comprehensive income would have included additional revenue of $97 million and additional profit of $13 million. Mojave Solar LLC impact would have been nil.

For the year ended December 31, 2013.

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 the Administration. 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´s construction phase was finished, 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 of October 13, 2013
Current assets		10,494
Contracted concessional assets (Note 6)		2,027,642
Other current and non-current assets		18,931
Project debt (Note 15)		(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.

Had Arizona Solar One, LLC been consolidated from January 1, 2013, the consolidated statement of comprehensive income would not have included any additional revenue or profit.

F-31

Note 6.- Contracted concessional assets

The following table shows the movements of contracted concessional assets included in the heading ‘Contracted Concessional assets for 2014:


Cost

Total as of January 1, 2014	4,492,286
Additions	50,799
Translation differences	(86,095	)

Change in the scope of the combined financial statements (Note 5)	2,583,946

Reclassification and other movements	(15,360	)

Total as of December 31, 2014	7,025,576


Accumulated amortization

Total as of January 1, 2014	(74,166	)
Additions	(125,480	)

Change in the scope of the combined financial statements (Note 5)	(108,191	)

Translation differences	7,439

Total accum. Amort. As of December 31, 2014	(300,398	)

Net balance at December 31, 2014	6,725,178

During 2014 contracted concessional assets increased mainly due to the first asset acquisition under Rofo ($1,010 million) and the full consolidation of Mojave Solar LLC ($1,574 million), 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 have entered into operation in 2014, mainly electric transmission lines in Peru, Palmatir and Quadra 2. No losses from impairment of ‘Contracted concessional assets in projects’ were recorded during 2014.

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.

Contracted concessional assets include fixed assets financed through project debt, related to service concession arrangements recorded in accordance with IFRIC 12, except for Palmucho, which is recorded in accordance with IAS 17, and PS10&20, which are recorded as property plant and equipment in accordance with IAS 16. As of December 31, 2014, contracted concessional financial assets amount to $750,546 thousand ($722,989 thousand as of December 31, 2013).

F-32

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		401,676
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

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 and 2012.

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.

For further details of projects to the application of IFRIC 12, please see Appendix III.

Note 7.- Investments carried under the equity method

The table below shows the breakdown and the movement of the investments held in associates for 2014 and 2013:


Investments in associates	2014			2013
Initial balance		387,324			734,083
Capital contributions		44,524			240,640
Change in the scope of the combined financial statements (Note 5)		(425,368	)		(587,412	)
Share of (loss)/profit		(769	)		13

Final balance		5,711			387,324

The decrease in 2014 is due to the entity Mojave Solar, LLC, which is fully consolidated since the plant entered into operation in December 2014 (see Note 5).

The increase in 2013 was due to the equity contribution to Arizona Solar One and Mojave Solar. 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).

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The tables below show a breakdown of assets, revenues and profit and loss as well as other information of interest for the years 2014 and 2013 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
Evacuacion Valdecaballeros, S.L.		28.56	$	24,513	$	2,137	$	310	$	1,108	$	536	$	(868	)	$	(651	)	$	5,711

As of December 31, 2014			$	24,513	$	2,137	$	310	$	1,108	$	536	$	(868	)	$	(651	)	$	5,711


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
Evacuacion 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	$	(986	)	$	(651	)	$	387,324

None of the associated companies referred to above is a listed company.

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 as of December 31, 2014 and 2013 are as follows:


Category	Notes	Loans and receivables / payables		Available for sale financial assets		Hedging derivatives		Balance as of 12.31.14
Derivative assets	9		—		—		4,597		4,597
Preferred equity in ACBH			—		263,000		—		263,000
Other financial accounts receivables			335,381		—				335,381
Clients and other receivables	11		129,696		—		—		129,696
Cash and cash equivalents	12		354,154		—		—		354,154

Total financial assets			819,231		263,000		4,597		1,086,828

Corporate debt	14		378,415		—		—		378,415
Project debt	15		3,823,066		—		—		3,823,066
Related parties	10		77,961		—		—		77,961
Trade and other current liabilities	17		231,132		—		—		231,132
Derivative liabilities	9		—		—		168,931		168,931

Total financial liabilities			4,510,574		—		168,931		4,679,505

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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		—		281,594
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

Project debt	15		2,894,650		—		2,894,650
Related parties	10		492,534		—		492,534
Trade and other current liabilities	17		204,013		—		204,013
Derivative liabilities	9		—		44,221		44,221

Total financial liabilities			3,591,197		44,221		3,635,418

As of December 31, 2014 and 2013, all the financial instruments measured at fair value have been classified as Level 2, except for the preferred equity investment in ACBH, classified as Level 3.

The preferred equity investment in ACBH is an available for sale financial asset that gives the following rights:

•

During the five-year period commencing on July 1, 2014, Abengoa Yield has the right to receive, in four quarterly installments, a preferred dividend of $18,400 thousand per year;

•

Following the initial five-year period, Abengoa Yield has the option to (i) remain as preferred equity holder receiving the first $18,400 thousand in dividends per year that ACBH is able to distribute or (ii) exchange the preferred equity for ordinary shares of specific project companies owned by ACBH.

Given that Abengoa Yield has a right to receive a quarterly dividend during the upcoming five years, the Company has recorded an account receivable for a total amount of $70,784 as of December 30, 2014, corresponding to the present value of the receivable, with a credit to Deferred income, in “Grants and other liabilities”. Income is recorded progressively during the next five years from July 2014, as dividend is collected. This account receivable is included in “Other financial accounts receivables”.

The valuation method used to calculate the fair value of the preferred equity investment in ACBH was discounting the $18.4 million annual dividend, using a discount rate of 7%. If the discount rate used were 1 per cent higher or lower while all the other variables were held constant, the carrying amount of this instrument would decrease by US$ 33 million or increase by US$ 44 million respectively.

Other financial accounts receivables 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, 2014 and 2013 are as follows:

Balance as of 12.31.14

Balance as of 12.31.13

Assets

Liabilities

Assets

Liabilities

Interest rate derivatives - cash flow hedge

4,597

168,931

13,622

44,221

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. All derivatives are classified as Level 2 (see Note 8).

As stated in note 3 to these consolidated 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 contracting floating to fixed interest rate swaps.

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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:

•

Project debt in Euros: we hedge between 80% and 100% of the notional amount, maturities until 2030 and average guaranteed interest rates of between 3.13 % and 4.75%.

•

Project debt in U.S. dollars: we hedge between 75% and 100% of the notional amount, including maturities until 2043 and average guaranteed interest rates of between 2.75% and 6.32%.

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, 2014 and 2013.


Notionals	Balance as of 12.31.14				Balance as of 12.31.13
	Cap		Swap		Cap		Swap
Up to 1 year		18,505		28,122		9,178		25,303
Between 1 and 2 years		19,833		39,923		9,581		29,840
Between 2 and 3 years		21,333		41,135		10,378		36,839
Subsequent years		245,797		751,350		231,694		682,384

Total	$	305,468	$	860,530	$	260,831	$	774,366

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, 2014 and 2013. 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 consolidated statement of financial position:


Fair value	Balance as of 12.31.14					Balance as of 12.31.13
	Cap		Swap			Cap		Swap
Up to 1 year		170		(5,388	)		290		(4,537	)
Between 1 and 2 years		185		(7,110	)		310		(4,236	)
Between 2 and 3 years		202		(7,320	)		334		(3,940	)
Subsequent years		4,041		(149,113	)		12,688		(31,508	)

Total	$	4,597		(168,931	)	$	13,622		(44,221	)

During the year 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 caps and swaps resulting from the decrease in future interest rates, and due to the first asset acquisition under the Rofo agreement, ( $1,436 thousand in assets and ($52,608) thousand in liabilities).

The net amount of the fair value of interest rate derivatives designated as cash flow hedges transferred to the consolidated income statement is a loss of $27,473 thousand (loss of $28,027 thousand in 2013 and a loss of $4,939 thousand in 2012). Additionally, the net amount of the time value component of the cash flow derivatives fair value recognized in the consolidated income statement for the year 2014 and the combined income statement for the years 2013 and 2012 has been a loss of $2,386 thousand, a gain of $513 thousand and a loss of $1,007 thousand respectively (See Note 21).

The after-tax losses accumulated in equity in connection with derivatives designated as cash flow hedges at the years ended December 31, 2014 and 2013, amount to $15,538 thousand and $36,600 thousand respectively.

Note 10.- Related parties

During the normal course of business, the Company has conducted operations with related parties consisting mainly of Abengoa´s subsidiaries, mainly through loan contracts and advisory services. The transactions were completed at market rates.

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During the period prior to the initial public offering, certain consolidated entities entered into one-year contractual arrangements with Abengoa from which the Company received certain administrative services. Such services included general services related to supporting functions such as financing, human resources management, and administration. The fee incurred by the operating companies was based on anticipated annual sales.

In addition, other operating expenses included an allocation of certain general and administrative services provided by Abengoa. Allocated costs included general and administrative costs deemed allocable to the Company. Measurement of allocated costs was based principally on time devoted to the Company by employees of Abengoa. The Company believed that including the allocated costs, the combined statements of operations included a reasonable estimate of actual costs incurred to operate the business.

At the date of the initial offering, the Company entered into a series of agreements to receive management, general and administrative services from Abengoa (the Support Services Agreement and Executive Service Agreement), and corresponding fees have been properly accounted for as other operating expenses from this date onwards.

All the project entities included in these consolidated financial statements, except for ACT, receive operation and maintenance services from related parties. Furthermore, some of these entities received engineering, procurement, construction services from related parties for those concessions which were still under construction during the year 2014.

Details of balances with related parties as of December 31, 2014 and 2013 are as follows:


	Balance as of December 31, 2014		Balance as of December 31, 2013

Trade receivables (current)		—		—
Credit receivables (current)		29,876		—

Total current receivables with related parties		29,876		—


Credit receivables (non-current)		327,400		—

Total non-current receivables with related parties		327,400		—


Trade payables (current)		104,556		25,077

Total current payables with related parties		104,556		25,077


Trade payables (non- current)		21,685		5,107
Credit payables (non-current)		56,276		487,427

Total non-current payables with related parties		77,961		492,534

Receivables with related parties primarily correspond to the preferred equity investment in ACBH amounting to $263,000 thousand and its corresponding dividend (see Note 8), for $64,400 as non-current and $18,400 as current.

The decrease in Credit payables (non-current) is mainly due to the capitalization of debt with related parties which occurred prior to the Asset Transfer. The increase in the line Trade payables (current) is due to the construction cost of Mojave Solar, LLC.

The transactions carried out by entities included in these consolidated financial statements with Abengoa and with subsidiaries of Abengoa not included in the consolidated group during the twelve-month periods ended December 31, 2014, 2013 and 2012 have been as follows:


	For the twelve-month ended December 31,
	2014			2013			2012
Sales		25,673			11,925			5,089
Construction costs		(38,565	)		(364,715	)		(558,620	)
Services rendered		2,343			2,804			3,527
Services received		(41,961	)		(24,403	)		(8,742	)

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	For the twelve-month ended December 31,
	2014			2013			2012
Purchases		—			(2,669	)		(177	)
Financial income		4,415			468			575
Financial expenses		(9,544	)		(11,209	)		(4,525	)

Services received include operation and maintenance services received by some plants, the fee incurred by some plants under the services agreement with Abengoa, and general and administrative services as explained above. Sales relate to sale of energy by Spanish Solar plants, which are sometimes made through an Abengoa´s company acting as an agent for the plant. Financial expenses primarily relate to interest expenses on debt with related parties that were capitalized prior to the IPO.

Construction costs include construction work subcontracted to Abengoa for the construction of the assets, which is recorded in these consolidated financial statements due to the fact that contracted concessional assets are included in the consolidated financial statements during the construction phase, according to IFRIC 12.

In addition, the Company has entered into a Financial Support Agreement under which Abengoa has agreed to facilitate a new $50,000 thousand revolving credit line and maintain any guarantees and letters of credit that have been provided by it on behalf of or for the benefit of Abengoa Yield and its affiliates for a period of five years. As of December 31, 2014, the total amount of the credit line remains undrawn.

Note 11.- Clients and other receivable

Clients and other receivable as of December 31, 2014 and 2013, consist of the following:


	Balance as of December 31, 2014		Balance as of December 31, 2013
Trade receivables		78,521		26,649
Tax receivables		36,080		61,888
Other accounts receivable		15,095		9,060

Total		129,696		97,597

As of December 31, 2014 and 2013, 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, 2014 and 2013, are as follows:


	Balance as of December 31, 2014		Balance as of December 31, 2013
Euro		45,435		5,409
Peruvian Sol		6,500		—
Chilean Peso		1,214		—

Total		53,149		5,409

The following table shows the maturity of Trade receivables as of December 31, 2014 and 2013:


	Balance as of December 31, 2014		Balance as of December 31, 2013
Up to 3 months		78,521		26,649

Total		78,521		26,649

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Note 12.- Cash and cash equivalents

The following table shows the detail of Cash and cash equivalents as of December 31, 2014 and 2013:


	Balance as of 12.31.14		Balance as of 12.31.13
Cash at bank and on hand		350,854		351,042
Bank deposits		3,300		6,622

Total		354,154		357,664

The following breakdown shows the main currencies in which cash and cash equivalent balances are denominated:


Currency	Balance as of 12.31.14		Balance as of 12.31.13
U.S. dollar		226,226		289,172
Euro		113,948		64,685
Peruvian sol		7,840		291
Chilean Peso		6,099		276
Others		41		3,240

Total		354,154		357,664

Note 13.- Equity

As of June 30, 2014, the share capital amounted to $8,000,000 represented by 80,000,000 ordinary shares completely subscribed and disbursed with a nominal value of $0.10 each, all in the same class and series. Each share grants one voting right.

On June 18, 2014 Abengoa Yield closed its initial public offering issuing 24,850,000 ordinary shares. The shares were offered at a price of $29 per share and as a result the Company raised $720,650 thousand of gross proceeds. The Company recorded $2,485 thousand as Share Capital and $682,810 thousand as Additional Paid in Capital, included in the Parent company reserves of the consolidated statement of financial position as of December 31, 2014, corresponding to the total net proceeds of the offering. The underwriters further purchased 3,727,500 additional shares from the selling shareholder, a subsidiary wholly owned by Abengoa, at the public offering price less fees and commissions to cover over-allotments (“greenshoe”) driving the total proceeds of the offering to $828,748 thousand. On January 22, 2015, Abengoa closed an underwritten public offering and sale in the United States of 10,580,000 of our ordinary shares for total proceeds of $327,980,000 (or $31 per share). Abengoa continues to beneficially own a majority of our outstanding shares but, as a result of such offering, reduced its stake in us from approximately 64.3% to 51.1% of our shares.

Abengoa Yield’s shares began trading on the NASDAQ Global Select Market under the symbol “ABY” on June 13, 2014.

As of December 31, 2014, Abengoa had a 64.28% interest in Abengoa Yield.

On February 23, 2015, our Board of Directors declared a quarterly dividend corresponding to the fourth quarter of 2014 amounting to $0.2592 per share, representing $1.04 on an annualized basis. We expect the dividend to be paid on or around March 16, 2015.

Parent company reserves as of December 31, 2014 are made up of share premium account and distributable reserves.

Retained earnings include results attributable to the parent company from January 1^st, 2014 and impact of the Asset Transfer and the first assets acquisition under the Rofo agreement in equity recorded in accordance with the Predecessor accounting principle.

F-39

Non-controlling interests fully relate to interests held by JGC Corporation in Solacor 1 and Solacor 2 and by Itochu Corporation in Solaben 2 and Solaben 3.

In addition, as of December 31, 2014, there was no treasury stock and there have been no transactions with treasury stock during the period then ended.

Note 14.- Corporate debt

The breakdown of the corporate debt as of December 31, 2014 and 2013 is as follows:


Non-current	Balance as of 12.31.14		Balance as of 12.31.13
Credit Facilities with financial entities		123,400		—
Notes and Bonds		252,760		—

Total Non-current		376,160		—


Current	Balance as of 12.31.14		Balance as of 12.31.13
Credit Facilities with financial entities		103		—
Notes and Bonds		2,152		—

Total Current		2,255		—

The repayment schedule for the Corporate debt, at the end of 2014 is as follows:


	Between January and December 2015		2016		2017		2018		2019		Subsequent years		Total
Credit Facilities with financial entities		103		—		—		123,400		—		—		123,503
Notes and Bonds		2,152		—		—		—		252,760		—		254,912

On November 17, 2014 we issued 7.000% Senior Notes due 2019 in an aggregate principal amount of $255 million (the “2019 Notes”). The 2019 Notes accrue annual interest of 7.000% payable semi-annually beginning on May 15, 2015 until their maturity date of November 15, 2019. In the event that we do not obtain a public credit rating for the 2019 Notes from both S&P and Moody’s prior to November 15, 2015, the interest rate per annum accruing on the 2019 Notes will increase by 0.75%, to 7.750%, on and after November 15, 2015 until the date on which we have obtained a public credit rating for the 2019 Notes from both S&P and Moody’s.

On December 3, 2014, we entered into a credit facility of up to $125 million with Banco Santander, S.A., Bank of America, N.A., Citigroup Global Markets Limited, HSBC Bank plc and RBC Capital Markets, as joint lead arrangers and joint bookrunners (the “Credit Facility”). On December 22, 2014, we drew down $125 million under the Credit Facility. Loans under the Credit Facility accrue interest at a rate per annum equal to: (A) for Eurodollar rate loans, LIBOR plus 2.75% and (B) for base rate loans, the highest of (i) the rate per annum equal to the weighted average of the rates on overnight U.S. Federal funds transactions with members of the U.S. Federal Reserve System arranged by U.S. Federal funds brokers on such day plus 1/2 of 1.00%, (ii) the U.S. prime rate and (iii) LIBOR plus 1.00%, in any case, plus 1.75%. Loans under the Credit Facility will mature on the fourth anniversary of the closing date of the Credit Facility. Loans prepaid by us under the Credit Facility may be reborrowed. The Credit Facility is secured by pledges of the shares of the guarantors which we own.

Note 15.- Project debt

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 project debt. This note shows the project debt linked to the contracted concessional assets included in note 6 of these consolidated financial statements.

F-40

Project debt 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 debt, project debt has certain key advantages, including a greater leverage period permitted and a clearly defined risk profile.

The movements for 2014 and 2013 of project debt have been as follows:


	Project debt - long term			Project debt - short term			Total

Balance as of December 31, 2013		2,842,338			52,312			2,894,650
Increases		501,335			89,390			590,725
Decreases (reimbursement)		(896,848	)		(139,086	)		(1,035,934	)
Currency translation differences		(65,036	)		(1,891	)		(66,927	)
Reclassifications		(291,019	)		291,019			—

Changes in the scope of the consolidated financial statements		1,401,107			39,445			1,440,552

Balance as of December 31, 2014		3,491,877			331,189			3,823,066

During 2014, the increase in Project debt was mainly due to the ATS bond issuance of $ 432 million on April 8, 2014, at a fixed coupon and with semi-annual amortization until April 2043, to refinance its then existing project finance debt. In addition, Project debt increased due to the full consolidation of Mojave Solar, LLC, increase of $820 million resulting from the business combination of the plant in December 2014 and to the First asset acquisition under the Rofo agreement which represented an increase of $620 million. (see Note 5).

The decrease was mainly due to the repayment of the short term tranche of the loan with the Federal Financing Bank by Arizona Solar One debt amounting to $451.3 millions and to the repayment of the former project finance debt of ATS $333 million, both in April 2014.

Reclassifications from long term to short term primarily relates to the Short term tranche of the loan with the Federal Financing Bank due by Mojave in December 2015.


	Project debt - long term			Project debt - short term			Total

Balance as of December 31, 2012		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 consolidated financial statements		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 Project debt 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, Project debt increased due to the full consolidation of Arizona Solar One resulting from the business combination of the plant in October 2013 (see Note 5).

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A decrease also occurred mainly due to the cancellation of previous debt by ACT, with the new financing obtained as indicated above ($501 million).

The repayment schedule for Project debt, at the end of 2014 is as follows and is consistent with the projected cash flows of the related projects.


2015		2016		2017		2018		2019		Subsequent years		Total
	331,189		106,702		111,600		121,872		136,699		3,015,004		3,823,066

Amount of project debt due within a year is mainly made up of the FFB short term tranche to be repaid by Mojave Solar, LLC in December 2015 ($ 248 million). We expect to repay this amount with the proceed of the ITC (Investment Tax Credit) grant we expect to collect in relation to the Mojave project.

Project debt projects entered in 2014 and 2013 (in millions of U.S. dollars) are as follows:

Project

Year

Country

Amount
committed

Amount
drawn

Abengoa Transmision Sur, S.A. (ATS)

2014

Peru

432

Total year 2014

432

Abengoa Transmision Norte, S.A. (ATN)

2013

Peru

110

Abengoa Cogeneracion Tabasco, S. de R.L. de C.V. (ACT)

2013

Mexico

660

Total year 2013

770

Current and non-current loans with credit entities include amounts in foreign currencies for a total of $901,951 thousand ($452,997 thousand in 2013).

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 12.31.14		Balance as of 12.31.13

Euro		896,690		446,436

Total		896,690		446,436

All of the Company’s financing agreements have a carrying amount close to its fair value.

Note 16.- Grants and other liabilities


	Balances as of December 31, 2014		Balances as of December 31, 2013
Grants		1,043,837		416,264
Long-term trade payables		259,364		234,639
Deferred Income		64,400		—

Grant and other non-current liabilities		1,367,601		650,903

As of December 31, 2014, the amount recorded in Grants corresponds mainly to loans with interest rates below market rates for Solana and Mojave for a total amount of $ 549 million ($308.1 million as of December 31, 2013). Loans with the Federal Financing

F-42

Bank guaranteed by the Department of Energy for these projects 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, is initially recorded as “Grants” in the consolidated statement of financial position, and subsequently recorded in “Other operating income” starting at the entry into operation of the plants.

The remaining balance of the “Grants” account corresponds to the ITC Grant awarded by the U.S. Department of the Treasury for the Solana project received in 2014 for a total amount of $513.7 million, which was mainly used to fully repay the Solana short-term tranche of the loan with the Federal Financing Bank. The amount recorded in Grants as a liability is progressively recorded as other income over the useful life of the asset.

Long-term trade payables mainly relates to the investment from Liberty Interactive Corporation (‘Liberty’) made on October 2, 2013 for an amount of $300 million. The investment was made in class A shares of Arizona Solar Holding, the holding of Solana Solar 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 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, 2014 and 2013, the non-current portion of the liability is recorded in Grants and other liabilities for an amount of $239 million and its current portion is recorded in other current liabilities for the remaining amount (see Note 17). 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 solar plant is a responsibility of Abengoa and the plant is fully consolidated in these consolidated financial statements.

Deferred income corresponds to the long-term portion of the deferred income from the dividend receivable from the preferred equity investment in ACBH (see Note 8).

As of December 31, 2014, the fair value of this financial liability is close to its carrying amount.

Note 17.- Trade payables and other current liabilities

Trade payable and other current liabilities as of December 31, 2014 and 2013 are as follows:


Item	Balance as of December 31, 2014		Balance as of December 31, 2013
Trade accounts payable		54,074		119,893
Down payments from clients		5,274		4,711
Deferred Income		18,400		—
Suppliers of concessional assets current		81,052		10,819
Liberty (see Note 16)		63,652		65,211
Other accounts payable		8,680		3,379

Total		231,132		204,013

Suppliers of concessional assets primarily relates to Mojave, which COD took place the on December 4, 2014. Trade accounts payable mainly relates to the operating and maintenance of the plants.

Deferred income corresponds to the short-term portion of the deferred income related to the dividend receivable from the preferred equity investment in ACBH (see Note 8).

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 18.- 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.

F-43

The consolidated 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 consolidated entities individually, the accounting profit is adjusted for temporary and permanent differences, recording the corresponding deferred tax assets and liabilities. At each consolidated income statement date, a current tax asset or liability is recorded, representing income taxes 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, 2014 and 2013, the analysis of deferred tax assets and deferred tax liabilities is as follows:


Concept	Balance as of 12.31.14		Balance as of 12.31.13
Tax credits for tax loss carryforwards		55,887		24,999
Tax credits for deductions pending application		145		—
Temporary differences derivatives financial instruments		59,307		23,353
Other temporary differences		8,871		4,432

Total deferred tax assets		124,210		52,784


Concept	Balance as of 12.31.14		Balance as of 12.31.13
Temporary differences tax amortization		52,342		19,048
Temporary differences derivatives financial instruments		—		195
Other temporary differences		8,476		2,596

Total deferred tax liabilities		60,818		21,839

Most of the tax credits for net operating loss carryforwards correspond to Peru ($16 million), ACT ($16 million), Solana ($14 million) and Chile ($6 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, 2014 and 2013 were as follows:


Deferred tax assets	Amount
As of January 1, 2013		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

Increase/decrease through the consolidated income statement		20,295
Increase/decrease through other consolidated comprehensive income (equity)		29,409
Other movements		1,492
Change in the scope of the consolidated financial statements (Note 5)		20,230

As of December 31, 2014		124,210

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Deferred tax liabilities	Amount
As of January 1, 2013		15,358
Increase/decrease through the combined income statement		5,007
Increase/decrease through other combined comprehensive income (equity)		1,581
Other movements		(107	)

As of December 31, 2013		21,839

Increase/decrease through the consolidated income statement		23,633
Increase/decrease through other consolidated comprehensive income (equity)		13,005
Other movements		(185	)
Change in the scope of the consolidated financial statements (Note 5)		2,526

As of December 31, 2014		60,818

Details regarding income tax for the years ended December 31, 2014 and 2013 are as follows:


Item	For the twelve- month period ended December 31, 2014			For the twelve- month period ended December 31, 2013
Current tax		(1,075	)		(705	)
Deferred tax		(3,338	)		12,467

Total income tax benefit/(expense)		(4,413	)		11,762

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 consolidated income statements for the years ended December 31, 2014 and 2013, are as follows:


Concept	For the twelve-month period ended December 31, 2014			For the twelve-month period ended December 31, 2013
Consolidated profit before taxes		(24,852	)		(13,620	)
Regulatory tax rate		30	%		30	%

Corporate income tax at regulatory tax rate		7,456			4,086

Income tax of associates, net		(231	)		4
Differences in foreign tax rates		(76	)		340
Permanent differences		(4,587	)		16,062
Incentives, deductions, and tax losses carryforwards		(249	)		339
Change in Spanish corporate income tax		1,608			—
Other non-taxable income/(expense)		(8,334	)		(9,069	)

Corporate income tax		(4,413	)		11,762

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.

On November 28, 2014, certain laws were published in the official state gazette (BOE) to reform the Spanish tax system which include changing the general tax rate to 28% in 2015 and to 25% in 2016 (from 30% in 2014), among other measures. The impact of the change in the new income tax rate has resulted in a $1.6 million reduction in the deferred income tax expense recorded in the profit and loss statement in 2014.

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Note 19.- Third-party guarantees and commitments

Third-party guarantees

At the close of 2014 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 $17,573 thousand attributed to operations of technical nature ($7,118 thousand as of December 31, 2013).

Contractual obligations

The following table shows the breakdown of the third-party commitments and contractual obligations as of December 31, 2014 and 2013:


2014	Total		2015		2016 and 2017		2018 and 2019		Subsequent

Corporate debt		378,415		2,255		—		376,160		—
Loans with credit institutions (project debt)		3,294,234		323,250		209,039		244,986		2,516,959
Notes and bonds (project debt)		528,832		7,939		9,263		13,585		498,045
Purchase commitments		1,813,080		79,509		148,357		152,256		1,432,958
Accrued interest estimate during the useful life of loans		2,233,750		180,756		350,553		308,430		1,394,011

2013	Total		2014		2015 and 2016		2017 and 2018		Subsequent

Loans with credit institutions (project debt)		2,786,092		49,539		247,654		426,275		2,062,624
Notes and bonds (project debt)		108,558		2,772		5,877		6,434		93,475
Purchase commitments		1,132,131		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

Note 20.- Other operating income and expenses

The table below shows the detail of Other Operating Income and Expenses for the years ended December 31, 2014, 2013 and 2012:


Other Operating income	For the year ended 12.31.14		For the year ended 12.31.13		For the year ended 12.31.12

Grants		35,261		10,118		—
Income from various services		6,087		4,811		1,752
Income from subcontracted construction services for our assets and concessions		38,565		364,715		558,620

Total		79,913		379,644		560,372

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Other Operating expenses	For the year ended 12.31.14			For the year ended 12.31.13			For the year ended 12.31.12
Leases and fees		(1,827	)		(1,850	)		(405	)
Repairs and maintenance		(10,262	)		(12,753	)		(876	)
Independent professional services		(26,204	)		(22,579	)		(9,632	)
Transportation		(114	)		(437	)		(191	)
Supplies		(7,589	)		(3,322	)		(651	)
Other external services		(10,164	)		(5,479	)		(1,763	)
Levies and duties		(14,226	)		(6,605	)		(437	)
Other expenses		(11,847	)		(3,165	)		(935	)
Construction costs		(38,565	)		(364,715	)		(558,620	)

Total		(120,798	)		(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 consolidated 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 consolidated 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 during the year 2013 with the construction of ATS and Palmatir, which entered into operation in 2014. Income from construction decreased in 2014 considering only few plants were still under construction.

The increase in grants is related to the ITC cash grant, which was received in March 2014 and to the implicit grant recorded for accounting purposes in relation to the FFB Loans in Solana and Mojave projects with interest rates below market rates (See Note 16).

Until the date of out initial public offering, other operating expenses include an allocation of certain general and administrative services provided by Abengoa for the period prior to the offering. The Company believes that by including the allocated costs, the consolidated income statement for this period includes a reasonable estimate of actual costs incurred to operate the business. These general and administrative services amount to $3.8 million in 2014 and $3.5 million in 2013.

Independent professional services are mainly related to the Operating and Maintenance costs of the plants.

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 2014 when compared with the previous year. This decrease has been partially offset by the increase in costs related to the entry in operation of Solana, ATS, Palmatir and Mojave, as well as to the consolidation of Solacor 1/2 and PS 10/20 since their acquisition in November and December 2014, respectively.

Note 21.- Financial income and expenses

Financial income and expenses

The following table sets forth our financial income and expenses for the years ended December 31, 2014, 2013 and 2012:

For the twelve-month period ended December 31,

Financial income

2014

2013

2012

Interest income from loans and credits

4,075

640

718

Interest rates benefits derivatives: cash flow hedges

836

513

—

Total

4,911

1,153

718

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	For the twelve-month period ended December 31,
Financial expenses	2014			2013			2012
Expenses due to interest:
Loans from credit entities		(117,743	)		(78,644	)		(53,633	)
Other debts		(61,814	)		(17,113	)		(4,525	)
Interest rates losses derivatives: cash flow hedges		(30,695	)		(28,027	)		(5,946	)

Total		(210,252	)		(123,784	)		(64,104	)

Financial expenses have increased for the year 2014 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 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 correspond mainly to transfers from equity to financial expense when the hedged item is impacting the consolidated income statement.

Other net financial income and expenses

The following table sets out ‘Other net financial income and expenses’ in years ended December 31, 2014, 2013 and 2012:


	For the twelve months ended December 31,
Other financial income / (expenses)	2014			2013			2012
Dividend from preferred equity investment in ACBH (Note 8)		9,200			—			—
Other financial income		549			618			1,170
Other financial losses		(3,880	)		(2,172	)		(1,256	)
Outsourcing of payables		(8	)		(139	)		(87	)

Total		5,861			(1,693	)		(173	)

Other financial losses mainly include guarantees and letters of credit, wire transfers and other bank fees and other minor financial expenses.

Note 22.- Earnings per share

Basic earnings per share has been calculated for the period subsequent to the initial public offering by dividing the profit/(loss) attributable to equity holders of the company generated after the initial public offering by the number of shares outstanding. Diluted earnings per share equals basic earnings per share for the period presented.


Item	Period from July 1, 2014, to December 31, 2014

Profit/(loss) from continuing operations attributable to Abengoa Yield Plc.		(3,379	)

Profit/(loss) from discontinuing operations attributable to Abengoa Yield Plc.		—

Average number of ordinary shares outstanding (thousands) - basic and diluted		80,000

Earnings per share from continuing operations (US dollar per share) - basic and diluted		(0.04	)
Earnings per share from discontinuing operations (US dollar per share) - basic and diluted		—
Earnings per share from profit for the period (US dollar per share) - basic and diluted		(0.04	)

Earnings per share calculated for the year 2014 considering loss for the full year attributable to the parent company of $31,612 thousand and weighted average number of ordinary shares outstanding of 44,614 thousand amounts to a loss of $0.71.

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Note 23.- Other information

23.1 Restricted Net assets

Certain of our consolidated 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 just reached COD, no dividends may be distributed during first months of operation. At December 31, 2014, the accumulated amount of the restrictions for the whole restricted term of these affiliates was $636 million. The company expects in the future to extract cash from the entities and to pay dividends to their shareholders. Excluding Mojave and Cadonal, the accumulated amount of restrictions amounts to $247 million.

The Company performed a test on the restricted net assets of consolidated 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 consolidated net assets of the Company as of December 31, 2014. Therefore the separate financial statements of Abengoa Yield, Plc. should be presented (see Appendix IV (Schedule I) for details).

23.2 Subsequent events

In February 2015, pursuant to the ROFO Agreement, the Company agreed to acquire a second set of assets from Abengoa (the “Second Dropdown”), which comprise an aggregate of 200 MW of solar power generation, 10.5 million cubic feet per day of water desalination and an 81-mile transmission line. The Second Dropdown Assets consist of (i) two water desalination plants in Algeria, Honaine and Skikda, with an aggregate capacity of 10.5 million cubic feet per day; (ii) an 81-mile transmission line in Peru, ATN2; (iii) a solar power asset in Spain, Helioenergy 1/2, with a capacity of 100 MW; and (iv) a solar power asset in the United Arab Emirates, Shams, with a capacity of 100 MW. On February 3, 2015, we completed the acquisition of a 25.5% stake in Honaine and a 34% stake in Skikda. Simultaneously, we entered into a two-year call and put option agreement with Abengoa by which we have put option rights to require Abengoa to purchase back these assets at the same price paid by us and Abengoa has call option rights to require us to sell back these assets if certain indemnities and guarantees provided by Abengoa related to past circumstances reach a certain threshold. The completion of the acquisition of the 40% stake in ATN2, the 30% stake in Helioenergy 1/2 and the 20% stake in Shams is subject to satisfaction of customary conditions, including approvals from financing institutions and, in certain cases, from partners in joint ventures.

F-49

Appendices

Appendix I

Entities included in the Company as subsidiaries as of December 31, 2014

Company name

Project name

Registered

address

% of nominal
share

Business

Abengoa Cogeneración Tabasco, S. de R.L. de C.V.

ACT

Santa Barbara. (MX)

100.00

(2)

Abengoa Concessions Infrastructure, S.L.

ACIN

Sevilla (ES)

100.00

(3)

Abengoa Concessions Perú, S.A.

ACP

Lima (PE)

100.00

(1)

Abengoa Solar Holdings USA Inc.

ABSA

Arizona (US)

100.00

(3)

Abengoa Solar US Holdings Inc.

ABSU

Arizona (US)

100.00

(3)

Abengoa Transmisión Norte S.A. (ATN)

ATN

Lima (PE)

100.00

(1)

Abengoa Transmisión Sur, S.A. (ATS)

ATS

Lima (PE)

100.00

(1)

ACT Holdings, S.A. de C.V.

ACT Holding

México D.F. (MX)

100.00

(2)

Arizona Solar One, LLC

ASO

Colorado (US)

100.00

(3)

ASO Holdings Company, LLC

ASOH

Colorado (US)

100.00

(3)

Cadonal, S.A.

Cadonal

Montevideo (UY)

100.00

(3)

Carpio Solar Inversiones, S.A.

Carpio

Sevilla (ES)

100.00

(3)

Holding de Energía Eólica S.A.

Montevideo (UY)

100.00

(3)

Logrosán Solar Inversiones, S.A.

Logrosan

Sevilla (ES)

100.00

(3)

Mojave Solar Holdings, LLC.

MSH

Colorado (US)

100.00

(3)

Mojave Solar LLC

Mojave

Arizona (US)

100.00

(3)

Palmatir S.A.

Palmatir

Montevideo (UY)

100.00

(3)

Palmucho, S.A.

Palmucho

Santiago de Chile (Chile)

100.00

(1)

Sanlucar Solar, S.A.

PS-10

Sevilla (ES)

100.00

(3)

Solaben Electricidad Dos

Solaben 2

Caceres(ES)

70.00

(3)

Solaben Electricidad Tres

Solaben 3

Caceres(ES)

70.00

(3)

Solacor Electricidad Uno, S.A.

Solacor 1

Sevilla (ES)

74.00

(3)

Solacor Electricidad Dos, S.A.

Solacor 2

Sevilla (ES)

74.00

(3)

Solar de Receptores de Andalucía, S.A.

SRA

Sevilla (ES)

100.00

(3)

Solar Processes, S.A

PS-20

Sevilla (ES)

100.00

(3)

Transmisora Mejillones, S.A.

Quadra 1

Santiago de Chile (CL)

100.00

(1)

Transmisora Baquedano, S.A.

Quadra 2

Santiago de Chile (CL)

100.00

(1)

(1)	Business sector: Electric transmission lines

(2)	Business sector: Conventional power

(3)	Business sector: Renewable energy

*	100% of Class A shares held by Liberty Media (US tax equity investor, non related).

The Appendices are an integral part of the notes to the financial statements.

F-50

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

Arizona (US)

100.0

(3)

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)

Arizona Solar One, LLC

ASO

Colorado (US)

100.0

(3)

Mojave Solar Holding, LLC

MSH

Colorado (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 consolidated financial statements.

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Appendices

Appendix II

Investments recorded under the equity method as of December 31, 2014

Company name

Project name

Registered
address

% of nominal
share

Business

Evacuacion Valdecaballeros, S.L.

Valdecaballeros

Caceres (ES)

28.6

(3)

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

Colorado (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 consolidated financial statements.

F-52


Appendices		Appendix III-1

Projects subject to the application of IFRIC 12 interpretation based on the concession of

services as of December 31, 2014 and 2013

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 and Mojave reached COD on December 1, 2014.

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.

Palmatir reached COD in 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 Servicios 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.

Cadonal

Cadonal is an on-shore wind farm facility in Uruguay with nominal installed capacity of 50 MW. Cadonal has 25 wind turbines and each turbine has a nominal capacity of 2 MW each. UTE (Administracion Nacional de Usinas y Trasmisiones Electricas), Uruguay´s state-owned electricity company, has agreed to purchase all energy produced by Cadonal pursuant to a 20-year PPA.

Cadonal reached COD in December 2014. The wind farm is located in Flores, 105 miles north of the city of Montevideo.

Cadonal signed a PPA with UTE on December 28, 2012 for 100% of the electricity produced, approved by URSEA (Unidad Reguladora de Servicios de Energia y Agua). UTE will pay a fixed tariff under the PPA per MWh under the PPA, which is denominated in U.S. dollars and will be adjusted every January considering both US and Uruguay´s inflation indexes and the exchange rate between Uruguayan pesos and U.S. dollars.

F-53

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.

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.

Solacor 1 & Solacor 2

The Solacor 1 and Solacor 2 are two 100 MW Concentrating Solar Power facilities and are part of Abengoa’s El Carpio Solar Complex, located in the municipality of El Carpio, Spain. The Carpio Solar Complex consists in a conventional parabolic trough Concentrating Solar Power system to generate electricity. Abengoa commenced construction of Solacor 1 and Solacor 2 in September 2010. The COD was reached in two phases, the first one, Solacor 1, was reached in January 2012 and the second one, Solacor 2, was reached in March 2012. JGC Corporation holds 26% of Solacor 1 & Solacor 2, a Japanese engineering company.

Renewable energy plants in Spain, like Solacor 1 and Solacor 2, 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. Solacor 1 and Solacor 2 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.

F-54

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 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.

F-55

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.

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 consolidated financial statements.

F-56

Appendices

Appendix III-2

Projects subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 2014

Project name

Country

Status⁽¹⁾

% of
Nominal
Share⁽²⁾

Period of
Concession⁽⁵⁾⁽⁶⁾

Offtaker⁽⁸⁾

Financial/
Intangible⁽³⁾

Assets/
Investment

Accumulated
Amortization

Construction
Revenue⁽⁴⁾

Operating
Profit/
(Loss)⁽⁹⁾

Arrangement
Terms (price)

Description of the
Arrangement

Renewable energy:

Solana

USA

(O)

100.0

30 Years

APS

(I)

2,046,486

(82,820

)

—

8,832

Fixed price per MWh with annual increases of 1.84% per year

30-year PPA with APS regulated by ACC

Mojave

USA

(O)

100.0

25 Years

PG&E

(I)

1,580,042

(4,914

)

—

(4,266

)

Fixed price per MWh without any indexation mechanism

25-year PPA with PG&E regulated by CPUC and CAEC

Palmatir

Uruguay

(O)

100.0

20 Years

UTE, Uruguay
Administration

(I)

146,274

(4,617

)

4,299

4,415

Fixed price per MWh in USD with annual increases based on inflation

20-year PPA with UTE, Uruguay state-owned utility

Cadonal

Uruguay

(O)

100.0

20 Years

UTE, Uruguay
Administration

(I)

118,119

—

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)

331,232

(21,454

)

—

15,386

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)

330,934

(24,570

)

—

15,059

Regulated revenue
base⁽⁷⁾

Regulated revenue established by different laws and rulings in Spain

Solacor 1

Spain

(O)

74.0

25 Years

Kingdom of
Spain

(I)

327,811

(28,627

)

—

1,132

Regulated revenue
base⁽⁷⁾

Regulated revenue established by different laws and rulings in Spain

Solacor 2

Spain

(O)

74.0

25 Years

Kingdom of
Spain

(I)

339,612

(28,714

)

—

1,139

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)

646,823

—

103,650

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)

320,135

(38,264

)

—

443

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

(O)

100.0

30 Years

Republic of
Peru

(I)

529,983

(15,701

)

17,447

23,005

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

(O)

100.0

21 Years

Sierra Gorda

(F)

41,922

—

416

4,251

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

(O)

100.0

21 Years

Sierra Gorda

(F)

55,017

—

16,402

5,383

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, 2014.

(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. Itochu Corporation holds 30% of the economic rights to each of Solaben 2 and Solaben 3. JGC Corporation holds 26% of the economic rights to each Solacor 1 and Solacor 2.

(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)	In each case the offtaker is the grantor.

(9)	Figures reflect the contribution to the consolidated financial statements of Abengoa Yield Plc. as of December 31, 2014, being only one month (December) for Solacor 1 and Solacor 2.

The Appendices are an integral part of the notes to the consolidated financial statements.

F-57

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 project 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 consolidated financial statements.

F-58

Appendices

Appendix IV (Schedule I)

Condensed Financial Statements of Abengoa Yield plc

Condensed statements of financial position of Abengoa Yield Plc.

– Amounts in thousands of usd –


	As of December 31, 2014		As of December 31, 2013
Assets
Investment in affiliates		1,392,481		—
Loans to affiliates		694,302		—
Cash and cash equivalents		155,367		—
Other assets		26,944		—

Total assets		2,269,094		—

Liabilities and Equity
Borrowings		123,502		—
Notes and bonds		254,912		—
Intercompany liabilities		172		—
Other Liabilities		83,958		—

Total Liabilities		462,544		—

Common Stock		8,000		—
Additional paid-in capital		1,313,903		—
Distributable reserves		476,233		—
Accumulated gains (losses)-net		8,414		—
Total shareholders’s equity		1,806,550		—

Total liabilities and equities		2,269,094		—

F-59

Condensed income statements of Abengoa Yield, Plc.

– Amounts in thousands of usd –


	For the year ended December 31, 2014			15 day period ended December 31, 2013
Income from

Services		24,006			—

Other financial income		7			—


Total income		24,013			—

Expenses

Other operating expenses		(3,668	)		—

Interest		(2,319	)		—

Other financial expenses		(9,821	)		—


Total expenses		(15,808	)		—


Income before income taxes		8,205			—

Income tax benefits (expense)		209			—


Profit for the year		8,414			—

F-60

Condensed cash flow statements of Abengoa Yield, Plc.

– Amounts in thousands of usd –


	For the year ended December 31, 2014			15 day period ended December 31, 2013
Cash Flow from operating activities		6,900			—
Cash Flow—investing activities
Decrease (increase) in investment and advance to affiliates		(196,849	)		—

Net decrease (increase) in other assets		(34,053	)		—

Cash used for investing activities		(230,902	)		—
Cash Flow—financing activities
Net increases in borrowings and other liabilities		376,747			—

Dividend paid to shareowner		(23,696	)		—

Other		26,318			—

Cash from financing activities		379,369			—

Increase (decrease) in cash and cash equivalents during the year		155,367			—

Cash and cash equivalent at the beginning of the year		—			—

Cash and cash equivalent at the end of the year		155,367			—

F-61

Notes to the Condensed Financial Statements

Schedule I has been provided pursuant to the requirements of Rule 12- 04(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 Abengoa Yield plc, 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. Other comprehensive income statement is not applicable for the periods presented.

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.

Basis of Presentation.

The presentation of Abengoa Yield plc stands alone condensed financial statement has been prepared using the same accounting policies as set out in the accompanying consolidated financial statements except that, the Company records its investment in subsidiaries under the cost method of accounting and that financial income from credits to companies in the group are recorded under Income from services, given that the company is a holding and this type of service is part of its primary activity. Such investments are presented on the statements of financial position as “Investment in and loans to affiliates” at cost less any identified impairment loss.

As of December 31, 2014 and 2013 there were no material contingencies, significant provisions of long-term obligations, mandatory dividend or redemption requirements of redeemable stocks or guarantees of the Company, except for those which have been separately disclosed in the Consolidated Financial Statements, if any.

c)	For years ended December 31, 2014 and 2013, cash dividends of $9,200 thousand and nil were declared to the Company by its consolidated subsidiaries or associates, respectively.

Reconciliation of the stand alone to consolidated financial statements of Abengoa Yield Plc.


Profit/(Loss) Reconciliation	For the year ended december 31, 2014			15 day period ended december 31, 2013
Stand alone—IFRS profit/(loss) for the period		8,414			—
Additional profit/(loss) if subsidiaries had been accounted for using the equity method of accounting as opposed to cost method		(40,026	)		—
Consolidated IFRS profit/(loss) for the period attributable to Abengoa Yield plc		(31,612	)		—


Equity Reconciliation	As of December 31, 2014		As of December 31, 2013
Stand alone—IFRS shareholders equity		1,806,550		—
Additional shareholders equity if subsidiaries had been accounted for using the equity method of accounting as opposed to cost method		33,081		—
Consolidated IFRS shareholders equity		1,839,631		—

F-62