UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________________________________

FORM 10-K

______________________________________________________

(Mark One)

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

For the fiscal year ended November 30, 2017

or

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

For the transition period from _________ to _________

Commission File Number: 001-37447

____________________________________________________________________

8point3 Energy Partners LP

(Exact name of Registrant as specified in its Charter)

______________________________________________________________________________

Delaware	47-3298142
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
77 Rio Robles San Jose, California	95134
(Address of principal executive offices)	(Zip Code)
(408) 240-5500
(Registrant’s telephone number, including area code)

_______________________________________________________________________________

Securities registered pursuant to Section 12(b) of the Act:

Class A Shares representing limited partner interests	NASDAQ Global Select Market
(Title of each class)	(Name of exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act: None

______________________________________________________________________________

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

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes  ☐    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.    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).    Yes  ☒    No  ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ☒

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definition of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ☐	Accelerated filer ☒	Non-accelerated filer ☐	Small reporting company ☐	Emerging growth company ☒
		(Do not check if a small reporting company)

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☒

The aggregate market value of the registrant’s Class A Shares held by non-affiliates on May 31, 2017, the last business day of the Registrant’s most recently completed second fiscal quarter (based on the closing sale price of $13.64 of the Registrant’s Class A shares, as reported by the NASDAQ Global Select Market on such date) was approximately $382.0 million.

As of January 31, 2018, 28,088,673 shares of the Registrant’s Class A Shares were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

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Table of Contents

GLOSSARY

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

		Page
PART I
Item 1.	Business	13
Item 1A.	Risk Factors	31
Item 1B.	Unresolved Staff Comments	66
Item 2.	Properties	66
Item 3.	Legal Proceedings	60
Item 4.	Mine Safety Disclosures	66
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	67
Item 6.	Selected Financial Data	71
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	72
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	91
Item 8.	Financial Statements and Supplementary Data	93
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	143
Item 9A.	Controls and Procedures	143
Item 9B.	Other Information	143
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	144
Item 11.	Executive Compensation	149
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	152
Item 13.	Certain Relationships and Related Transactions, and Director Independence	154
Item 14.	Principal Accounting Fees and Services	171
PART IV
Item 15.	Exhibits, Financial Statement Schedules	172
Item 16.	Form 10-K Summary	178

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GLOSSARY

Unless the context provides otherwise, references herein to “we,” “us,” “our” and “the Partnership” or like terms refer to 8point3 Energy Partners LP together with its consolidated subsidiaries.

References in this Annual Report on Form 10-K to:

“(ac)” refers to alternating current.

“8point3 Solar CEI” refers to 8point3 Solar CEI, LLC, a Delaware limited liability company.

“AMAs” refers to asset management agreements.

“AROs” refers to asset retirement obligations.

“ATM Agents” refers to Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, and Mizuho Securities USA Inc. collectively.

“ATM Program” refers to the Partnership’s at-the-market offering program established on January 30, 2017 pursuant to the Equity Distribution Agreement, under which the Partnership may sell its Class A Shares from time to time to or through the ATM Agents.

“Blackwell Project” refers to the solar energy project located in Kern County, California, that is held by the Blackwell Project Entity and has a nameplate capacity of 12 MW.

“Blackwell Project Entity” refers to Blackwell Solar, LLC.

“BLM” refers to the U.S. Bureau of Land Management.

“Board” refers to the board of directors of our general partner.

“C&I” refers to commercial and industrial.

“C&I Holdings” refers to SunPower Commercial Holding Company I, LLC, an indirect subsidiary of OpCo and the holder of the Macy’s California Project Entities and the UC Davis Project Entity.

“C&I Project Entities” refers to, collectively, the Kern Project Entity, the Macy’s California Project Entities, the Macy’s Maryland Project Entity and the UC Davis Project Entity.

“CAISO” refers to the California Independent System Operator.

“Capital Dynamics” refers to Capital Dynamics Clean Energy Infrastructure V JV, LLC, an equity fund managed by Capital Dynamics, Inc.

“CD Clean Energy Holdco” refers to CD Clean Energy and Infrastructure V JV (Holdco), LLC, a Delaware limited liability company, an affiliate of Capital Dynamics.

“CFIUS” refers to the Committee on Foreign Investment in the United States.

“COD” refers to the commercial operation date.

“Conflicts Committee” refers to the Conflicts Committee of the Board.

“DG Solar” refers to distributed solar generation. DG Solar systems are deployed at the site of end-use, such as businesses and homes.

“EPA” refers to the U.S. Environmental Protection Agency.

“EPC” refers to engineering, procurement and construction.

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“Equity Distribution Agreement” refers to the Equity Distribution Agreement, dated as of January 30, 2017, by and among the Partnership and the General Partner, on the one hand, and the ATM Agents, on the other hand.

“Exchange Act” refers to the Securities Exchange Act of 1934, as amended.

“FASB” refers to the Financial Accounting Standards Board.

“FERC” refers to the U.S. Federal Energy Regulatory Commission.

“First Solar” refers to First Solar, Inc., a corporation formed under the laws of the State of Delaware, in its individual capacity, or to First Solar, Inc. and its subsidiaries, as the context requires. Unless otherwise specifically noted, references to First Solar and its subsidiaries exclude us, the General Partner, Holdings and our subsidiaries.

“First Solar MSA” refers to the Management Services Agreement, dated as of June 24, 2015, as amended, among the Partnership, OpCo, the General Partner and First Solar 8point3 Management Services, LLC.

“First Solar Project Entities” refers to, collectively, the IPO First Solar Project Entities and the Kingbird Project Entities.

“First Solar ROFO Agreement” refers to the Right of First Offer Agreement, dated as of June 24, 2015, as amended, by and between OpCo and First Solar.

“fiscal 2014” refers to the fiscal year ended December 28, 2014.

“fiscal 2015” refers to the eleven months ended November 30, 2015.

“fiscal 2016” refers to the fiscal year ended November 30, 2016.

“fiscal 2017” refers to the fiscal year ended November 30, 2017.

“fiscal 2018” refers to the fiscal year ended November 30, 2018.

“FPA” refers to the U.S. Federal Power Act.

“FSAM” refers First Solar Asset Management, LLC, a wholly owned subsidiary of First Solar.

“FSEC” refers to First Solar Electric (California), Inc., a Delaware corporation and an affiliate of First Solar.

“General Partner” or “our general partner” refers to 8point3 General Partner, LLC, our general partner, a limited liability company formed under the laws of the State of Delaware and a wholly owned subsidiary of Holdings.

“GW” refers to a gigawatt, or 1,000,000,000 watts. As used in this Annual Report on Form 10-K, all references to watts (e.g., MW or GW) refer to measurements of alternating current, except where otherwise noted.

“Henrietta Holdings” refers to Parrey Holding Company, LLC.

“Henrietta Project” refers to the solar energy project that is located in Kings County, California and is held by the Henrietta Project Entity.

“Henrietta Project Entity” refers to Parrey, LLC.

“HLBV Method” refers to Hypothetical Liquidation at Book Value Method.

“Holdings” refers to 8point3 Holding Company, LLC, a limited liability company formed under the laws of the State of Delaware, which is jointly owned by First Solar and SunPower and is the parent of the General Partner.

“Hooper Class B Partnership” refers to SSCO III Class B Holdings, LLC.

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“Hooper Holdings” refers to SSCO III Holding Company, LLC, the direct owner of 100% of the limited liability company membership interests of the Hooper Project Entity.

“Hooper Project” refers to the solar energy project located in Alamosa County, Colorado, that is held by the Hooper Project Entity and has a nameplate capacity of 50 MW.

“Hooper Project Entity” refers to Solar Star Colorado III, LLC.

“Hooper Purchase Agreement” refers to the Contribution Agreement, dated as of March 31, 2016, between OpCo and SunPower.

“HSR” refers to the Hart-Scott-Rodino Antitrust Improvements Act of 1976.

“IDRs” refers to Incentive Distribution Rights.

“Investor Co 1” refers to 8point3 Co-Invest Feeder 1, LLC.

“Investor Co 2” refers to 8point3 Co-Invest Feeder 2, LLC.

“IPO” refers to the Partnership’s initial public offering of its Class A shares, which was completed on June 24, 2015.

“IPO First Solar Project Entities” refers to the Lost Hills Project Entity, the Blackwell Project Entity, the Maryland Solar Project Entity, the North Star Project Entity and the Solar Gen 2 Project Entity and, with respect to certain of the foregoing, one or more of its direct or indirect holding companies.

“IPO Project Entities” refers to, collectively, the IPO First Solar Project Entities and the IPO SunPower Project Entities.

“IPO SunPower Project Entities” refers to the Macy’s California Project Entities, the Quinto Project Entity, the RPU Project Entity, the UC Davis Project Entity and the Residential Portfolio Project Entity and, with respect to certain of the foregoing, one or more of its direct or indirect holding companies.

“IRS” refers to the Internal Revenue Service.

“ITCs” refers to investment tax credits.

“Kern Class B Partnership” refers to SunPower Commercial II Class B, LLC.

“Kern Letter Agreement” refers to that certain letter agreement, dated June 9, 2017, by and between OpCo and SunPower in connection with the closing of the fifth phase of the Kern Project. Please read Part I, Item 1, “Financial Information—Notes to Consolidated Financial Statements—Note 3—Business Combinations” for further details.

“Kern Holdings” refers to SunPower Commercial Holding Company II, LLC, the direct owner of 100% of the limited liability company membership interests of the Kern Project Entity.

“Kern Phase 1(a) Assets” refers to the assets comprising the first phase of the Kern Project, with a nameplate capacity of approximately 3 MW.

“Kern Phase 1(b) Assets” refers to the assets comprising the second phase of the Kern Project, with a nameplate capacity of approximately 5 MW.

“Kern Phase 2(a) Assets” refers to the assets comprising the third phase of the Kern Project, with a nameplate capacity of approximately 5 MW.

“Kern Phase 2(b) Assets” refers to the assets comprising the fourth phase of the Kern Project, with a nameplate capacity of approximately 3 MW.

“Kern Phase 2(c) Assets” refers to the assets comprising the fifth phase of the Kern Project, with a nameplate capacity of up to approximately 2 MW.

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“Kern Purchase Agreement” refers to the Purchase, Sale and Contribution Agreement, dated as of January 26, 2016, between OpCo and SunPower, as amended.

“Kern Remaining Assets” refers to the certain assets of the Kern Project, with a nameplate capacity of up to approximately 3 MW, which could have been acquired by the Partnership if certain conditions precedent set forth in the Kern Letter Agreement had been satisfied on or prior to September 30, 2017.

“Kern Project” refers to the solar energy project located in Kern County, California, that is held by the Kern Project Entity and has an aggregate nameplate capacity of approximately 18 MW. OpCo’s acquisition of the Kern Project was effectuated in phases, with the closing for the Kern Phase 1(a) Assets having occurred on January 26, 2016, the closing for the Kern Phase 1(b) Assets having occurred on September 9, 2016, the closing for the Kern Phase 2(a) Assets having occurred on November 30, 2016, the closing for the Kern Phase 2(b) Assets having occurred on February 24, 2017, and the closing for the Kern Phase 2(c) Assets having occurred on June 9, 2017.

“Kern Project Entity” refers to Kern High School District Solar (2), LLC.

“Kingbird Project” refers to the solar energy project located in Kern County, California, that is held by the Kingbird Project Entities and has an aggregate nameplate capacity of 40 MW.

“Kingbird Project Entities” refers to, collectively, Kingbird Solar A, LLC and Kingbird Solar B, LLC.

“Kingbird Purchase Agreement” refers to the Purchase and Sale Agreement, dated March 31, 2016, between OpCo and First Solar.

“LMP” refers to “Locational Marginal Pricing,” as further defined in the CAISO open access transmission tariff.

“Lost Hills Blackwell Holdings” refers to Lost Hills Blackwell Holdings, LLC.

“Lost Hills Blackwell Project” refers to the solar energy project held collectively by the Lost Hills Project Entity and the Blackwell Project Entity that is comprised of the Lost Hills Project and the Blackwell Project and has a nameplate capacity of 32 MW.

“Lost Hills Project” refers to the solar energy project located in Kern County, California, that is held by the Lost Hills Project Entity and has a nameplate capacity of 20 MW.

“Lost Hills Project Entity” refers to Lost Hills Solar, LLC.

“Macy’s California Project” refers to the solar energy project consisting of seven sites in Northern California that is held by the Macy’s California Project Entities and has an aggregate nameplate capacity of 3 MW.

“Macy’s California Project Entities” refers to, collectively, Solar Star California XXX, LLC and Solar Star California XXX (2), LLC.

“Macy’s Maryland Class B Partnership” refers to SunPower Commercial III Class B, LLC.

“Macy's Maryland Holdings” refers to SunPower Commercial Holding Company III, LLC, the direct owner of 100% of the limited liability company membership interests of the Macy's Maryland Project Entity.

“Macy’s Maryland Project” refers to the solar energy project which holds roof-mounted solar power systems with an aggregate system size of approximately 5 MW, which was installed at certain Macy’s department stores in Maryland and is held by the Macy’s Maryland Project Entity.

“Macy’s Maryland Project Entity” refers to Northstar Macys Maryland 2015, LLC.

“Macy’s Maryland Purchase Agreement” refers to the Contribution Agreement, dated September 30, 2016, between OpCo and SunPower.

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“Maryland Solar Project” refers to the solar energy project located in Washington County, Maryland, that is held by the Maryland Solar Project Entity and has a nameplate capacity of 20 MW.

“Maryland Solar Project Entity” refers to Maryland Solar LLC.

“Mergers” refers to the transactions contemplated by the Merger Agreement.

“Merger Agreement” refers to the Agreement and Plan of Merger and Purchase Agreement, dated as of February 5, 2018, by and among the Partnership, the General Partner, OpCo, Holdings, and certain affiliates of Capital Dynamics, including 8point3 Solar CEI, Investor Co 1, Investor Co 2, CD Clean Energy Holdco, Partnership Merger Sub, OpCo Merger Sub 1 and OpCo Merger Sub 2.

“MSAs” refers, collectively, to the First Solar MSA and the SunPower MSA.

“MW” refers to a megawatt, or 1,000,000 watts. As used in this Annual Report on Form 10-K, all references to watts (e.g., MW or GW) refer to measurements of alternating current, except where otherwise noted.

“NASDAQ” refers to the NASDAQ Global Select Market.

“NERC” refers to the North American Electric Reliability Corporation.

“NOLs” refers to net operating losses.

“North Star Holdings” refers to NS Solar Holdings, LLC, the direct owner of 100% of the limited liability company membership interests of the North Star Project Entity.

“North Star Project” refers to the solar energy project located in Fresno County, California, that is held by the North Star Project Entity and has a nameplate capacity of 60 MW.

“North Star Project Entity” refers to North Star Solar, LLC.

“NPV” refers to net present value.

“O&M” refers to operations and maintenance services.

“offtake agreements” refers to PPAs, leases and other offtake agreements.

“offtake counterparties” refers to the customer under a PPA lease or other offtake agreement.

“Omnibus Agreement” refers to the Amended and Restated Omnibus Agreement, dated as of April 6, 2016, as amended, among the Partnership, OpCo, the General Partner, Holdings, First Solar and SunPower. Please read Part II, Item 8, “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 14—Related Parties” for further details.

“OpCo” refers to 8point3 Operating Company, LLC and its subsidiaries.

“OpCo LLC Agreement” refers to that certain Amended and Restated Limited Liability Company Agreement of OpCo, dated June 24, 2015.

“OpCo Merger Sub 1” refers to 8point3 OpCo Merger Sub 1, LLC, a Delaware limited liability company and wholly owned subsidiary of Parent.

“OpCo Merger Sub 2” refers to to 8point3 OpCo Merger Sub 2, LLC, a Delaware limited liability company and wholly owned subsidiary of Parent.

“OSHA” refers to Occupational Safety and Health Act.

“P50 production level” is the amount of annual energy production that a particular asset or group of assets is expected to meet or exceed 50% of the time.

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“Parent” refers to 8point3 Solar CEI, Investor Co 1 and Investor Co 2.

“Partnership Agreement” refers to our partnership agreement.

“Partnership Merger Sub” refers to 8point3 Partnership Merger Sub, LLC, a Delaware limited liability company and wholly owned subsidiary of 8point3 Solar CEI.

“PBI Rebates” refers to performance based incentives.

“PG&E” refers to Pacific Gas and Electric Company.

“Portfolio” refers to, collectively, our portfolio of solar energy projects as of November 30, 2017, which consists of the Henrietta Project, the Hooper Project, the Kern Project, the Kingbird Project, the Lost Hills Blackwell Project, the Macy’s California Project, the Macy’s Maryland Project, the Maryland Solar Project, the North Star Project, the Quinto Project, the Solar Gen 2 Project, the Stateline Project, the RPU Project, the UC Davis Project and the Residential Portfolio.

“PPA” refers to a power purchase agreement.

“Predecessor” refers to the operation of the IPO SunPower Project Entities prior to the completion of the IPO.

“Project Entities” refers to, collectively, the IPO First Solar Project Entities, the IPO SunPower Project Entities, the Henrietta Project Entity, the Hooper Project Entity, the Kern Project Entity, the Kingbird Project Entities, the Macy’s Maryland Project Entity and the Stateline Project Entity.

“PUHCA 2005” refers to the U.S. Public Utility Holding Company Act of 2005.

“Quinto Holdings” refers to SSCA XIII Holding Company, LLC, an indirect subsidiary of OpCo and the indirect holder of the Quinto Project Entity.

“Quinto Project” refers to the solar energy project located in Merced County, California, that is held by the Quinto Project Entity and has a nameplate capacity of 108 MW.

“Quinto Project Entity” refers to Solar Star California XIII, LLC.

“Residential Portfolio” refers to the approximately 5,800 solar installations located at homes in Arizona, California, Colorado, Hawaii, Massachusetts, New Jersey, New York, Pennsylvania and Vermont, that is held by the Residential Portfolio Project Entity and has an aggregate nameplate capacity of 38 MW.

“Residential Portfolio Project Entity” refers to SunPower Residential I, LLC.

“ROFO Agreements” refers, collectively, to the First Solar ROFO Agreement and the SunPower ROFO Agreement.

“ROFO Portfolio” refers to our portfolio of the SunPower ROFO Projects.

“RPS” refers to renewable portfolio standards mandated by state law that require a regulated retail electric utility to procure a specified percentage of its total electricity delivered to retail customers in the state from eligible renewable energy resources, such as solar energy projects, by a specified date.

“RPU Holdings” refers to SSCA XXXI Holding Company, LLC, an indirect subsidiary of OpCo and the holder of the RPU Project Entity.

“RPU Project” refers to the solar energy project located in Riverside, California, that is held by the RPU Project Entity and has a nameplate capacity of 7 MW.

“RPU Project Entity” refers to Solar Star California XXXI, LLC.

“SDG&E” refers to San Diego Gas & Electric Company, a subsidiary of Sempra Energy.

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“SEC” refers to the U.S. Securities and Exchange Commission.

“Securities Act” refers to the Securities Act of 1933, as amended.

“SG&A” refers to selling, general and administrative services.

“SG2 Holdings” refers to SG2 Holdings, LLC, the direct owner of 100% of the limited liability company membership interests in the Solar Gen 2 Project Entity.

“Short-Term Note” means the Promissory Note in the principal amount of $2.0 million issued by OpCo in favor of FSAM, a wholly owned subsidiary of First Solar.

“Solar Gen 2 Project” refers to the solar energy project located in Imperial County, California, that is held by the Solar Gen 2 Project Entity and has a nameplate capacity of 150 MW.

“Solar Gen 2 Project Entity” refers to SG2 Imperial Valley, LLC.

“Sponsors” refers, collectively, to First Solar and SunPower.

“SRECs” refers to Solar Renewable Energy Credits.

“Stateline Holdings” refers to Desert Stateline Holdings, LLC, the direct owner of 100% of the limited liability company membership interests in the Stateline Project Entity.

“Stateline Project” refers to the solar energy project located in San Bernardino, California that is held by the Stateline Project Entity and has a nameplate capacity of 300 MW.

“Stateline Project Entity” refers to Desert Stateline, LLC.

“Stateline Promissory Note” means the Promissory Note in the principal amount of $50.0 million issued by OpCo in favor of FSAM, a wholly owned subsidiary of First Solar, in connection with our acquisition of interests in the Stateline Project.

“SunPower” refers to SunPower Corporation, a corporation formed under the laws of the State of Delaware, in its individual capacity or to SunPower Corporation and its subsidiaries, as the context requires. Unless otherwise specifically noted, references to SunPower and its subsidiaries exclude us, the General Partner, Holdings and our subsidiaries, including OpCo.

“SunPower Capital” refers to SunPower Capital Services, LLC, a wholly owned subsidiary of SunPower.

“SunPower MSA” refers to the Management Services Agreement, dated as of June 24, 2015, as amended, among the Partnership, OpCo, the General Partner and SunPower Capital.

“SunPower Project Entities” refers to, collectively, the IPO SunPower Project Entities, the Henrietta Project Entity, the Hooper Project Entity, the Kern Project Entity and the Macy’s Maryland Project Entity.

“SunPower ROFO Agreement” refers to the Right of First Offer Agreement, dated as of June 24, 2015, as amended, by and between OpCo and SunPower.

“SunPower ROFO Projects” refers to, collectively, the projects set forth in the chart in Part I, Item 1, under the heading “Business—Our Portfolio—SunPower ROFO Projects” as to which we have a right of first offer under the SunPower ROFO Agreement should SunPower decide to sell them.

“SunPower Systems” refers to SunPower Corporation, Systems, a wholly owned subsidiary of SunPower.

“UC Davis Project” refers to the solar energy project located in Solano County, California, that is held by the UC Davis Project Entity and has a nameplate capacity of 13 MW.

“UC Davis Project Entity” refers to Solar Star California XXXII, LLC.

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“U.S. GAAP” refers to U.S. generally accepted accounting principles.

“Utility Project Entities” refers to the Henrietta Project Entity, the Hooper Project Entity, the Kingbird Project Entities, the Lost Hills Project Entity, the Blackwell Project Entity, the Maryland Solar Project Entity, the North Star Project Entity, the Quinto Project Entity, the RPU Project Entity, the Solar Gen 2 Project Entity and the Stateline Project Entity.

“Waiver Agreement” refers to the Waiver to Right of First Offer Agreement, dated as of February 5, 2018, by and between SunPower and OpCo.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations and contain projections of results of operations or of financial condition or forecasts of future events. Words such as “could,” “will,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential” or “continue” and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report on Form 10-K include statements concerning our Sponsors’ ownership interest in us, our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and believe that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report on Form 10-K. Those risk factors and other factors noted throughout this Annual Report on Form 10-K could cause our actual results to differ materially from those disclosed in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

• the failure to complete, or delays in completing, the Mergers with Capital Dynamics could negatively impact the market price of our Class A shares and our financial results;

• the announcement and pendency of the Mergers and related uncertainty could cause disruptions in our business, which could have an adverse effect on our business and financial results and the price of our Class A shares;

• the inability to actively pursue certain other alternatives to the Mergers until the Mergers with Capital Dynamics are completed or the Merger Agreement is terminated;

• risks inherent with being subject to certain operating restrictions until completion of the Mergers;

• risks relating to the Mergers, including being subject to class action lawsuits, which could materially adversely affect our business, financial condition and operating results or prevent or delay completion of the Mergers;

• changes in the capital markets or interest rate environment, including changes in market sentiment toward cash generating vehicles similar to us in general, which could impair our ability to raise capital, on terms that are economically acceptable to us, to fund future project acquisitions;

• an inability or decreased ability to acquire interests in projects until we pay in full the principal of and interest on the Stateline Promissory Note;

• a failure to locate and acquire interests in additional attractive projects at favorable prices, or the inability to obtain adequate financing for such projects;

• risks inherent in newly constructed solar energy projects, including underperformance relative to our expectations, system failures and outages;

• changes in U.S. federal, state, provincial and local laws, regulations, policies and incentives, including those related to taxation and environmental regulation;

• the failure of our projects, including our Portfolio, or any project we may acquire, including the SunPower ROFO Projects, to perform as we expect or, in the case of the SunPower ROFO Projects, to reach their commercial operation date;

• the risk that our limited number of offtake counterparties will be unwilling or unable to fulfill their contractual obligations to us or that they otherwise terminate their agreements with us;

• risks inherent in the operation and maintenance of solar energy projects;

• the impairment or loss of any one or more of the projects in our Portfolio, such as the Henrietta Project, the Maryland Solar Project, the Quinto Project, the Solar Gen 2 Project, the Stateline Project, or any other projects in our Portfolio or that we may otherwise acquire;

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• the failure of a supplier to fulfill its warranty or other contractual obligations;

• the failure of our Sponsors to fulfill their respective indemnification obligations under the Omnibus Agreement;

• the inability of our projects to operate or deliver energy for any reason, including if interconnection or transmission facilities on which we rely become unavailable;

• effects of a natural disaster, climate change or other severe weather or meteorological conditions or other event of force majeure;

• risks to our Sponsors and third party development companies relating to pricing under offtake agreements, project siting, financing, construction, permitting, the environment, governmental approvals and the negotiation of project development agreements, reducing opportunities available to us;  

• risks associated with our ownership or acquisition of projects that remain under construction;

• terrorist or other attacks and responses to such acts;

• the occurrence of a significant incident for which we do not have adequate insurance coverage;

• liabilities and operating restrictions arising from environmental, health and safety laws and regulations;

• risks associated with litigation and administrative proceedings;

• a failure to comply with anti-corruption laws and regulations in the United States and elsewhere;

• our inability to renew or replace expiring or terminated agreements, such as our offtake agreements, at favorable rates or on a long-term basis;

• energy production by our projects or availability of our projects that does not satisfy the minimum obligations under our offtake agreements;

• limits on OpCo’s ability to grow and make acquisitions because of its obligations under its limited liability company agreement to distribute available cash;

• lower prices for fuel sources used to produce energy from other technologies, which could reduce the demand for solar energy;

• risks inherent in the acquisition of existing solar energy projects;

• risks related to information technology system failures, or network disruptions and security breaches, including cybersecurity breaches;

• substantial competition from utilities, independent power producers and other industry participants;

• conflicts arising from our general partner’s or our Sponsors’ relationship with us;

• increases in our tax liability; and

• certain factors discussed elsewhere in this Annual Report on Form 10-K.

Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to publicly update or revise any forward-looking statements except as required by law.

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PART I

Item 1. Business.

Overview

8point3 Energy Partners LP is a Delaware limited partnership formed on March 3, 2015, by our general partner pursuant to a joint venture between First Solar and SunPower. We are a limited partnership formed to own, operate and acquire solar energy generation projects. On June 24, 2015, we completed our IPO of 20,000,000 Class A shares. Our Class A shares representing limited partner interests in 8point3 Energy Partners LP are traded on the NASDAQ under the symbol “CAFD.” As of November 30, 2017, we owned a 35.5% limited liability interest in OpCo, as well as a controlling non-economic managing member interest in OpCo. As of November 30, 2017, our Sponsors collectively owned 51,000,000 Class B shares in the Partnership, with SunPower and First Solar owning 28,883,075 and 22,116,925 Class B shares, respectively, and together owning a noncontrolling 64.5% limited liability company interest in OpCo.

As of November 30, 2017, our Portfolio consisted of interests in 946 MW of solar energy projects. As of November 30, 2017, we owned interests in ten utility-scale solar energy projects and four C&I solar energy projects, all of which are operational, and a portfolio of residential DG Solar assets. Each utility-scale and C&I solar energy project in our Portfolio sells its energy output under long-term, fixed-price offtake agreements and our residential portfolios are comprised of solar installations which are leased to homeowners under a fixed monthly rate. Our operations comprise one reportable segment containing our Portfolio of solar energy projects. Please read Part II, Item 8, “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 16—Segment Information.”

On February 5, 2018, we, our general partner, OpCo and Holdings entered into the Merger Agreement with certain affiliates of Capital Dynamics. Upon the terms and subject to the conditions set forth in the Merger Agreement, (i) OpCo Merger Sub 1 will merge with and into OpCo (“OpCo Merger 1”) and the separate existence of OpCo Merger Sub 1 will cease and OpCo will continue as the surviving limited liability company of OpCo Merger 1 (the “Initial Surviving LLC”), (ii) OpCo Merger Sub 2 will merge with and into the Initial Surviving LLC (“OpCo Merger 2” and, together with OpCo Merger 1, the “OpCo Mergers”) and the separate existence of OpCo Merger Sub 2 will cease and the Initial Surviving LLC will continue as the surviving limited liability company of OpCo Merger 2 (the “Surviving LLC”), (iii) Partnership Merger Sub will merge with and into the Partnership (the “Partnership Merger” and, together with the OpCo Mergers, the “Mergers”) and the separate existence of Partnership Merger Sub will cease and the Partnership shall continue as the surviving partnership of the Partnership Merger (the “Surviving Partnership” and, together with the Surviving LLC, the “Surviving Entities”), (iv) Holdings will transfer to 8point3 Solar or an affiliate thereof, and 8point3 Solar (or its designated affiliate) will accept, for no consideration, the transfer and delivery of, 100% of the issued and outstanding membership interests in the General Partner, including all rights and obligations relating thereto and all economic and capital interests therein, and 100% of the issued and outstanding Incentive Distribution Rights (as defined in the OpCo LLC Agreement).

The Merger Agreement was approved unanimously by the members of our Board, following the approval and recommendation of the Conflicts Committee. Completion of the Mergers is expected to occur, subject to satisfaction of closing conditions, in the second or third quarter of 2018.

At the effective time of OpCo Merger 1, the OpCo LLC Agreement shall be amended by Amendment No. 1 to permit a special distribution to the members of OpCo pro rata in accordance with their ownership of common and subordinated units of OpCo, and the Initial Surviving LLC shall make a special distribution in an amount equal to the difference between $1.1 billion and the amount of debt then outstanding to the members of OpCo (the “Special Distribution”). At the effective time of OpCo Merger 2, each issued and outstanding common unit and subordinated unit of OpCo, other than the common units owned by us, will be converted into the right to receive an amount in cash equal to $12.35 per share, less the amount received in the Special Distribution and as further adjusted pursuant to the Merger Agreement. At the effective time of the Partnership Merger, each issued and outstanding Class A Share will be converted into the right to receive an amount in cash equal to $12.35 per share, as adjusted pursuant to the Merger Agreement. During the pendency of the Mergers, we intend to make quarterly distributions of $0.2802 per share, which maintains the distribution level at the end of fiscal 2017.

The following diagram depicts a simplified version of our organizational and ownership structure as of November 30, 2017.

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Our Portfolio

The following table provides an overview of the assets that comprise the Portfolio as of November 30, 2017:

Project	Location	Commercial Operation Date(1)	MW(ac) (2)	Counterparty	Counterparty Credit Rating / Avg. FICO Score	Remaining Term of Offtake Agreement (in years)(3)
Utility
Maryland Solar	Maryland	February 2014	20	FirstEnergy Solutions	CCC-	15.3
Solar Gen 2	California	November 2014	150	San Diego Gas & Electric	A	22.0
Lost Hills Blackwell	California	April 2015	32	City of Roseville/Pacific Gas and Electric	AA- / A-	26.1	(4)
North Star	California	June 2015	60	Pacific Gas and Electric	A-	17.6
RPU	California	September 2015	7	City of Riverside	AA-	22.8
Quinto	California	November 2015	108	Southern California Edison	BBB+	18.0
Hooper	Colorado	December 2015	50	Public Service Company of Colorado	A-	18.1
Kingbird	California	April 2016	40	Southern California Public Power Authority(5)	AA-	18.4
Henrietta	California	October 2016	102	Pacific Gas and Electric	A-	18.8
Stateline	California	August 2016	300	Southern California Edison	BBB+	18.8
Commercial & Industrial
UC Davis	California	September 2015	13	University of California	AA-	17.8
Macy's California	California	October 2015	3	Macy's Corporate Services	BBB-	17.9
Macy’s Maryland	Maryland	December 2016	5	Macy's Corporate Services	BBB-	19.1
Kern(6)	California	September 2017	18	Kern High School District	AA-	19.2	(7)
Residential Portfolio	U.S. – Various	June 2014	38	Approx. 5,800 homeowners(8)	765 Average / 680 Minimum(9)	14.8	(10)
Total			946

(1) For the Macy’s California Project, the Macy’s Maryland Project and the Kern Project, COD represents the first date on which all of the solar generation systems within each of the Macy’s California Project, the Macy’s Maryland Project and the Kern Project, respectively, achieved COD. For the Residential Portfolio, COD represents the first date on which all of the residential systems within the Residential Portfolio achieved COD.

(2) The MW for the projects in which the Partnership owns less than a 100% interest or in which the Partnership is the lessor under any sale-leaseback financing are shown on a gross basis.

(3) Remaining term of offtake agreement is measured from November 30, 2017.

(4) Remaining term comprised of 1.1 years on a PPA with the City of Roseville, California, followed by a 25-year PPA with PG&E starting in 2019.

(5) The Kingbird Project is subject to two separate PPAs with member cities of the Southern California Public Power Authority.

(6) OpCo’s acquisition of the Kern Project was effectuated in phases, with the closing of the first phase, reflecting a nameplate capacity of approximately 3 MW, having occurred on January 26, 2016, the closing of the second phase, reflecting a nameplate capacity of approximately 5 MW, having occurred on September 9, 2016, the closing of the third phase, reflecting a nameplate capacity of approximately 5 MW, having occurred on November 30, 2016, the closing of the fourth phase, reflecting a nameplate capacity of approximately 3 MW, having closed on February 24, 2017, and the closing of the fifth phase, reflecting a nameplate capacity of approximately 2 MW, having closed on June 9, 2017.

(7) Remaining term is the weighted average duration of the five phases of the Kern Project.

(8) Comprised of the approximately 5,800 solar installations located at homes in Arizona, California, Colorado, Hawaii, Massachusetts, New Jersey, New York, Pennsylvania and Vermont, that are held by the Residential Portfolio Project Entity and have an aggregate nameplate capacity of 38 MW.

(9) Measured at the time of initial contract.

(10) Remaining term is the weighted average duration of all of the residential leases, in each case measured from November 30, 2017.

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Tax Equity Financing

Most of our projects are financed using partnership structures with investors, known as tax equity investors, who can more efficiently monetize the value of the tax benefits, primarily ITCs and accelerated depreciation that support solar energy projects in the United States. These partnership structures usually allocate tax and cash items disproportionately to the share of the project capital contributed by the tax equity investor and OpCo. These partnership structures are designed to effectively allocate project attributes (e.g., tax benefits, cash flows and residual value) to the party best suited to monetize the attributes. Often these partnerships are structured with allocations that change over time or as the tax equity investor realizes its projected return on investment and are known as “flip partnerships.” Partnership allocations vary by project based on specific project characteristics and investor preferences.

For each of the Solar Gen 2 Project, the Lost Hills Blackwell Project, the North Star Project and the Henrietta Project, a modified flip-partnership structure was utilized that distributes available cash on the basis of (i) 51% to the tax equity investor and (ii) 49% to OpCo. For the Stateline Project, a modified flip-partnership structure was utilized that distributes available cash on the basis of (i) 66% to the tax equity investor and (ii) 34% to OpCo.

The flip partnership structures employed on the Kern Project, the Kingbird Project, the Hooper Project, the Macy’s California Project, the Macy’s Maryland Project, the Quinto Project, the RPU Project and the UC Davis Project allocate a certain share of project cash flow to OpCo pursuant to the project-specific distribution waterfall applicable to the project. Pursuant to each of these distribution waterfalls, the tax equity investor is entitled to a monthly or quarterly amount of project cash flow until a specified “flip” point is achieved. After the “flip” point, the cash allocations to OpCo are expected to increase. In addition, upon reaching the flip point, OpCo has a right to purchase the tax equity investor’s interests in the project for an amount that is not less than its fair market value. The H.R. 1 (Pub. L. No. 115-97), informally known as the “Tax Cuts and Jobs Act” (the “2017 Tax Act”), which was signed into law December 22, 2017, made certain changes to the US Internal Revenue Code that could affect the timing of the flip point for certain of the Projects noted above. Notably, the decrease in the corporate tax rate from 35% to 21% decreases the potential tax advantages of depreciation to potential investors.

The Maryland Solar Project Entity has leased the Maryland Solar Project to an affiliate of First Solar, with the lease term expiring on December 31, 2019 (unless terminated earlier pursuant to its terms). Under the arrangement, First Solar’s affiliate is obligated to pay a fixed amount of rent that is set based on the expected operations of the plant. Upon expiration of this lease, we will directly benefit from the operating results of the Maryland Solar Project. Please read Part I, Item 1A, “Risk Factors—Risks Related to Our Business—We rely on a limited number of offtake counterparties and we are exposed to the risk that they are unwilling or unable to fulfill their contractual obligations to us or that they otherwise terminate their offtake agreements with us.”

Under these tax equity financing structures, a tax equity investor may be entitled to indemnification or to a diversion to it of distributable cash from a project in order to compensate the tax equity investor (i) for a breach of representation, warranty or covenant made to it in connection with its tax equity investment, (ii) for a reduction in or change in allocation of ITCs, tax basis, fair market value or other tax-related matters on which its investment was based or (iii) with respect to tax equity arrangements where the determination of the flip date is based on the tax equity investor achieving a target after-tax internal rate of return, for a delay in achieving the target return (including due to a change in federal tax law that results in a reduction in the applicable corporate tax rate (which could reduce the value of depreciation deductions)), a reduction in available ITCs or a change to available depreciations deductions. Except for indemnification or diversion caused by OpCo or diversions resulting from corporate tax rate reductions (including potentially due to the 2017 Tax Act’s corporate tax rate reduction from 35% to 21%), OpCo is entitled to indemnification under the Omnibus Agreement for payments made to a tax equity investor in respect of indemnification or diversion obligations that arise under clauses (i) or (ii) above.

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ROFO Projects

In connection with our IPO, our Sponsors granted us rights of first offer on certain of their solar energy projects that are currently contracted or are expected to be contracted prior to being sold, should our Sponsors decide to sell such projects before June 24, 2020. Due to our higher cost of capital and difficulty in accessing the capital markets on a consistent basis, commencing in fiscal 2016, we and our Sponsors agreed to make several adjustments to the projects subject to the ROFO Agreements, replacing interests in certain projects with alternatives. Later, when certain projects were ultimately offered to us under the ROFO Agreement, we were unable to transact due to these same fiscal constraints. The offered projects were subsequently acquired by third party buyers at purchase prices higher than those offered to us. As a result of such adjustments, we no longer have a right of first offer on any projects developed by First Solar. The SunPower ROFO Agreement includes assets similar to the projects in our Portfolio and represent interests in 304 MW capacity as of November 30, 2017. However, due to the limitations on our ability to acquire projects under the Merger Agreement, in connection with the Conflicts Committee’s and the Board’s approval of the Merger Agreement, we agreed to enter into the Waiver Agreement with SunPower of all the projects subject to the SunPower ROFO Agreement during the pendency of the Merger Agreement. In the event that the Merger Agreement terminates without the closing of the Mergers, the waiver would terminate with respect to all projects subject to the SunPower ROFO Agreement, except, with respect to individual projects still owned by SunPower at the termination of such waiver, such project is either under an exclusivity agreement with a third party or has an offer for purchase from a third party pursuant to which SunPower is in negotiations. Despite the chart detailed below, during the pendency of the Merger Agreement, we do not have a right of first offer on any or all such projects should SunPower decide to sell.

The following table provides a brief description of the SunPower ROFO Projects as of November 30, 2017 (subject to the waiver described above):

Project	Location	COD(1)	MW(ac)(2)	Counterparty	Counterparty Credit Rating / Avg. FICO Score	Remaining Term of Offtake Agreement (years)(3)
Utility ROFO Projects
Contracted
Boulder Solar 1	Nevada	December 2016	100	Nevada Power Company d/b/a NV Energy	A	19.1
C&I ROFO Projects
Contracted
Commercial Portfolio 1	U.S. – Various	December 2013	45	Various		13.3	(4)
Commercial Portfolio 2	U.S. – Various	August 2016	49	Various (5)		13.5	(6)
Commercial Portfolio 3	U.S. – Various	March 2018	42	Various		24.0	(7)
CU Boulder	Colorado	March 2016	1	The Regents of The University of Colorado	AA+	24.0
Kern Remaining Assets	California	June 2018	3	Pacific Gas and Electric	A-	20.0
Rancho California Water District	California	April 2016	4	Rancho California Water District	AAA	24.0
Macy’s Connecticut	Connecticut	June 2016	1	Macy’s Corporate Services	BBB-	19.0
Napa Sanitation District	California	December 2015	1	Napa Sanitation District	AA	24.0
Macy's SDG&E	California	September 2016	2	Macy’s Corporate Services	BBB-	19.0
Macy's Massachusetts	Massachusetts	October 2016	1	Macy’s Corporate Services	BBB-	19.0
Riverside Public Utility District - Water Division	California	December 2016	6	Riverside Public Utility District - Water Division	AA-	24.1
UC Santa Barbara	California	December 2016	5	The Regents of The University of California	AA-	19.1
Awarded (8)
California 1 (9)	California	June 2016	2
Alabama	Alabama	September 2016	8
Residential ROFO Portfolio	U.S. – Various	October 2014	34	Approx. 5,000 homeowners	766 Average / 700 Minimum (10)	16.2	(11)
Total			304

(1) For each utility project that has yet to reach its COD, COD is the expected COD. For C&I solar energy projects that have yet to reach COD, COD represents the first date on which all of the solar generation systems within such project are expected to achieve COD. For C&I solar energy projects that have attained COD and for our Residential ROFO Portfolio, COD represents the first date on which all of the solar generation systems or residential systems within such project or portfolio, as applicable, have achieved COD.

(2) The MW for the projects in which SunPower owns less than a 100% interest are shown on a gross basis. At or prior to COD of the projects subject to the SunPower ROFO Agreement, SunPower may enter into arrangements, often referred to as tax equity financing, with investors seeking to utilize the tax attributes of their projects which may result in a reduction of our expected economic ownership of such SunPower ROFO Project. These arrangements have multiple potential structures which have differing impacts on our economic ownership. Please read Part I, Item 1, “Business—Tax Equity Financing.” With respect to certain utility-scale solar energy projects, these arrangements may result in our expected economic ownership percentage of such project being not less than 45% at the time of purchase, unless approved by the Partnership. SunPower is also permitted to sell a partial economic interest in the SunPower ROFO Project as part of a tax equity investment in the SunPower ROFO Project.

(3) Remaining term of offtake agreement is measured from the later of November 30, 2017 or the expected COD of the applicable project.

(4) Remaining term is the weighted average duration of all of the commercial PPAs. The shortest remaining term is 11.2 years and the longest remaining term is 15.4 years.

(5) This portfolio is partially contracted with a utility offtaker to assist such offtaker with its capacity requirements.

(6) Remaining term is the weighted average duration of all of the commercial PPAs. The shortest remaining term is 11.5 years and the longest remaining term is 15.8 years.

(7) Remaining term is the weighted average duration of all of the commercial PPAs. The shortest remaining term is 23.0 years and the longest remaining term is 24.0 years.

(8) Awarded projects are projects that have been awarded by the offtake counterparty to the developing Sponsor and are expected to be contracted.

(9) The California 1 Project has been canceled.

(10) Measured at the time of initial contract.

(11) Remaining term is the weighted average duration of all of the residential leases. The shortest remaining term is 14.9 years and the longest remaining term is 16.9 years.

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Utility Projects

Typical Project Agreements

Our Utility Project Entities have entered into agreements that are customary for utility-scale solar energy projects. These include agreements for energy sales, interconnection, construction, equipment supply, O&M services, asset management services and real estate rights, among others. Our Utility Project Entities have also secured necessary and customary project permits.

Power Purchase Agreements.    Our Utility Project Entities have entered into offtake agreements under which each Utility Project Entity generally receives a fixed price over the term of the offtake agreement with respect to 100% of its output, subject in some cases to annual escalations and/or time of delivery adjustments. Such offtake agreements are designed to provide a stable and predictable revenue stream.

Under our Utility Project Entities’ offtake agreements, each party typically has the right to terminate upon written notice ranging from ten to 60 days following the occurrence of an event of default that has not been cured within the applicable cure period, if any. In addition, following an uncured event of default under an offtake agreement by the applicable offtake counterparty, the applicable Utility Project Entity may withhold amounts due to such offtake counterparty, suspend performance, receive payment for damages and, in most cases, receive termination payments from the applicable offtake counterparty or pursue other remedies available at law or in equity. Events of default under these offtake agreements typically include:

• failure to pay amounts due;

• bankruptcy proceedings;

• failure to provide certain credit support;

• failure to hold necessary licenses or permits; and

• breach of material obligations.

Our Utility Project Entities’ offtake agreements have certain availability or production requirements, and if such requirements are not met, then in some cases the applicable Utility Project Entity is required to pay the offtake counterparty a specified damages amount. In addition, such failure, in certain cases, may give the offtake counterparty a right to terminate the offtake agreement or reduce the contract quantity. Certain obligations (other than payment obligations) under our offtake agreements may be excused by force majeure events, and in some cases, the offtake agreement may be terminated if any such force majeure event continues for a continuous period of between 12 and 36 months (depending on the offtake agreement).

Interconnection Agreements.    We depend on interconnection and transmission facilities owned and operated by third parties to deliver the energy from our utility projects. As such, our Utility Project Entities or their affiliates have entered into interconnection agreements with large regional utility companies, local distribution companies or independent system operators, which allow our projects to connect to the energy transmission system or, in some cases, to a distribution system. The interconnection agreements define the cost allocation and schedule for interconnection, as well as any upgrades required to connect the project to the transmission system or distribution system, as applicable.

Construction and Equipment Supply Agreements.    Our Utility Project Entities have entered into construction agreements with qualified contractors and equipment supply agreements with industry leading suppliers, including our Sponsors. In addition to setting forth the terms and conditions of construction or equipment delivery, as applicable, our Utility Project Entities receive system-wide warranties and product warranties for the major equipment pursuant to these construction and equipment supply agreements (which vary in coverage and length by project).

O&M Agreementsand Asset Management Agreements.    Our Utility Project Entities and certain other subsidiaries have entered into O&M agreements and AMAs with First Solar or SunPower affiliates, as applicable (except where such persons are otherwise subject to O&M agreements or AMAs with unaffiliated third parties). Under the terms of the O&M agreements and AMAs, such affiliates have agreed to provide a variety of operation, maintenance and asset management services, and certain performance warranties or availability guarantees, to our Utility Project Entities in exchange for fixed annual fees, which are subject to certain adjustments. For a detailed description of the terms of the O&M agreements and AMAs applicable to our projects, please read Part III, Item 13. “Certain Relationships and Related Transactions, and Director Independence.”

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Real Estate Rights.    Our Utility Project Entities and certain other subsidiaries have secured real property interests and access rights that we believe will allow our utility projects in our Portfolio to operate without material real estate claims until the expiration of the initial terms of applicable offtake agreements.

Our Utility Projects

Henrietta

The Henrietta Project Entity owns the 102 MW Henrietta Project located in Kings County, California. The Henrietta Project achieved commercial operation in October 2016. We indirectly control 100% of the class B membership interests in Henrietta Holdings, the indirect owner of 100% of the limited liability company membership interests of the Henrietta Project Entity. Such class B membership interests in Henrietta Holdings entitle us to a 49% economic interest and initially 1% of the tax allocations and the net income or loss of the Henrietta Project Entity. A subsidiary of Southern Company acts as the class A member of Henrietta Holdings. The class A member owns a 51% economic interest and initially 99% of the tax allocations and the net income or loss of the Henrietta Project Entity. After the Henrietta Project has been operational for approximately fifteen years, the allocation of tax-related items between the class A and class B members of Henrietta Holdings will shift to match the economic interests. An affiliate of the class A member has managerial responsibilities, subject to the class A members’ and the class B members’ approval rights with respect to certain decisions, including expenditures in excess of budgeted amounts, certain sales of assets, execution, termination or amendment of certain contracts and the incurrence of debt. The Henrietta Project is located on leased property pursuant to a ground lease and ancillary beneficial easements executed in August 2015, which provide the Henrietta Project Entity with an initial 31 years of site control and the ability to extend the lease term up to two additional five-year terms.

Hooper Project

The Hooper Project Entity owns the 50 MW Hooper Project located on an approximately 320 acre site owned by the Hooper Project Entity in Alamosa County, Colorado. The Hooper Project achieved commercial operation in December 2015. We indirectly control 100% of the class B membership interests in Hooper Holdings, the indirect owner of 100% of the limited liability company membership interests of the Hooper Project Entity. The class A membership interests in Hooper Holdings are held by an affiliate of Wells Fargo & Company, who is a tax motivated project equity investor, and the class C membership interests in Hooper Holdings are held by SunPower Capital, an affiliate of SunPower. Distributions of cash flows from the Hooper Project are subject to a waterfall. Until the date (the “Hooper Flip Point”), which is the later of the date that the class A member’s effective after-tax internal rate of return equals 7.0% per annum and December 29, 2020, the class A member, the class B member and the class C member are entitled to approximately 15.78%, 84.14% and 0.08%, respectively, of any distributions in excess of a monthly preferred distribution payable to the tax equity investor. The preferred distribution is currently estimated to be approximately $2.0 million per year. After the Hooper Flip Point, the preferred distribution will terminate and the class A member, the class B member and the class C member will be entitled to approximately 5.48%, 94.425% and 0.095%, respectively, of all distributions. Notwithstanding the foregoing, the terms of the operating agreement of Hooper Holdings provide that, in the event that the class A member has not achieved an effective after-tax internal rate of return of at least 7.0% per annum as of the date that is eight years after the closing of the transaction contemplated by the purchase and sale agreement, the priority distribution plus 25% of net cash flow in excess thereof shall be distributed to the class A member until the class A member achieves such after-tax internal rate of return.

SunPower Capital is the managing member of Hooper Holdings through their class C membership interests. The class A member and the class B member are not involved in the day-to-day management of Hooper Holdings or the Hooper Project; however, the managing member of Hooper Holdings is required to obtain the other members’ consent for certain customary major decisions concerning the Hooper Holdings and the Hooper Project as set forth in the Hooper Holdings operating agreement. Such major decisions subject to the approval of the class A member and/or the class B member include, for example, incurring indebtedness other than permitted indebtedness, encumbering project assets other than permitted encumbrances, selling project assets other than permitted sales, terminating material project documents under certain conditions, certain changes in method of accounting, merging and consolidating the projects and other such major actions. The class B member has the right to remove the managing member for convenience, and, with the approval of the class A member, install a new managing member.

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Kingbird Project

The Kingbird Project Entities own the 40 MW Kingbird Project located on two adjoining sites in Kern County, California. The Kingbird Project achieved commercial operation in April 2016. OpCo indirectly owns 100% of the class B membership interests in Kingbird Holdings, the direct owner of 100% of the limited liability company membership interests of the Kingbird Project Entities. The class A membership interests in Kingbird Holdings are held by an affiliate of State Street Bank, who is a tax motivated project equity investor. Distributions of cash flows from the Kingbird Project are subject to a waterfall. Until the date (the “Kingbird Flip Point”), which is the later of the date that the class A member’s effective after-tax internal rate of return equals 6.5% per annum and April 30, 2021, the class A member and the class B member are entitled to 30% and 70%, respectively, of any distributions. After the Kingbird Flip Point, the class A member and the class B member will be entitled to 6.42% and 93.58%, respectively, of all distributions. Notwithstanding the foregoing, the terms of the operating agreement of Kingbird Holdings provide that, in the event that the class A member has not achieved an effective after-tax internal rate of return of at least 6.5% per annum as of the date that is ten years after the closing of the transaction contemplated by the purchase and sale agreement, 40% of cash flow shall be distributed to the class A member until the earlier of the class A member achieving such after-tax internal rate of return or the eleventh anniversary. If the class A member did not achieve an effective after-tax internal rate of return of at least 6.5% per annum by the eleventh anniversary, 50% of cash flow shall be distributed to the class A member until the earlier of the class A member achieving such after-tax internal rate of return or the twelfth anniversary. If the class A member did not achieve an effective after-tax internal rate of return of at least 6.5% per annum by the twelfth anniversary, 100% of cash flows shall be distributed to the class A member until the class A member achieves such after-tax internal rate of return.

We are the managing member of Kingbird Holdings through our class B membership interest. The class A member is not involved in the day-to-day management of Kingbird Holdings or the Kingbird Project; however, the managing member of Kingbird Holdings is required to obtain the class A member’s consent for certain customary major decisions concerning Kingbird Holdings and the Kingbird Project as set forth in the Kingbird Holdings operating agreement. Such major decisions subject to the approval of the class A member include, for example, incurring indebtedness other than permitted indebtedness, encumbering project assets other than permitted encumbrances, selling project assets other than permitted sales, terminating material project documents under certain conditions, certain changes in method of accounting, merging and consolidating the projects and other such major actions.

The Kingbird Project is situated on an approximately 324-acre site and consists of a leasehold interest governed by two lease agreements that runs for an initial term of 30 years from February 2, 2015, with an option to extend the lease term for up to two additional ten-year renewal periods at the discretion of the Kingbird Project Entities.

Lost Hills Blackwell

The Lost Hills Project Entity and the Blackwell Project Entity own the 20 MW Lost Hills Project and the 12 MW Blackwell Project, respectively, which are located on adjoining sites in Kern County, California. The Lost Hills Blackwell Project achieved commercial operation in April 2015. OpCo indirectly owns 100% of the class B membership interests in Lost Hills Blackwell Holdings, the owner of 100% of the limited liability company membership interests of the Lost Hills Project Entity and the Blackwell Project Entity. Such class B membership interests entitle us to a 49% economic interest and currently 1% of the tax allocations and net income or loss of both the Lost Hills Project Entity and the Blackwell Project Entity. A subsidiary of Southern Company acts as the class A member. The class A member owns a 51% economic interest and currently 99% of the tax allocations and net income or loss of the Lost Hills Project Entity and the Blackwell Project Entity. After the Lost Hills Blackwell Project has been operational for approximately 11 years, the allocation of tax-related items between the class A and class B members of Lost Hills Blackwell Holdings is expected to shift to match the economic interests. An affiliate of Southern Company has managerial responsibilities for Lost Hills Blackwell Holdings and the project entities subject to the class A members’ and the class B members’ approval rights with respect to certain decisions, including expenditures in excess of budgeted amounts, certain sales of assets, execution, termination or amendment of certain contracts and the incurrence of debt. Each of the Lost Hills Project and the Blackwell Project consists of a leasehold interest governed by separate lease agreements, which include commonly leased areas for shared uses. The initial term of both leases commenced in July 2014, and each lease runs for a term of 30 years with an option to renew for an additional ten years at the discretion of the Lost Hills Project Entity and the Blackwell Project Entity.

Maryland Solar

The Maryland Solar Project Entity owns the 20 MW Maryland Solar Project located in Washington County, Maryland. The Maryland Solar Project achieved commercial operation in February 2014. The Maryland Solar Project is subject to a lease between the Maryland Solar Project Entity and an affiliate of First Solar, that runs until December 31, 2019 (unless terminated

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earlier pursuant to its terms). The lease requires fixed rent payments and does not feature any purchase option exercisable by the lessee. The Maryland Solar Project consists of a leasehold interest governed by a single ground lease, which expires on December 31, 2032, with the option to renew for five additional years at the discretion of the Maryland Solar Project Entity and an additional right to renew for a subsequent term of another five years upon the mutual agreement of the Maryland Solar Project Entity and the land owner and approval by the Maryland Board of Public Works. Please read Part I, Item 1A, “Risk Factors—Risks Related to Our Business—We rely on a limited number of offtake counterparties and we are exposed to the risk that they are unwilling or unable to fulfill their contractual obligations to us or that they otherwise terminate their offtake agreements with us” and Part III, Item 13, “Certain Relationships and Related Transactions, and Director Independence—Maryland Solar Lease Agreement.”

North Star

The North Star Project Entity owns the 60 MW North Star Project, located in Fresno County, California. The North Star Project achieved commercial operation in June 2015. OpCo indirectly owns 100% of the class B membership interests in North Star Holdings, the direct owner of 100% of the limited liability company membership interests of the North Star Project Entity. Such class B membership interests entitle us to a 49% economic interest and initially 1% of the tax allocations and the net income or loss of the North Star Project Entity. A subsidiary of Southern Company acts as the class A member. The class A member owns a 51% economic interest and initially 99% of the tax allocations and the net income or loss of the North Star Project Entity. After the North Star Project has been operational for approximately 11 years, the allocation of tax-related items between the class A and class B members of North Star Holdings will shift to match the economic interests. An affiliate of the class A member has managerial responsibilities, subject to the class A members’ and the class B members’ approval rights with respect to certain decisions, including expenditures in excess of budgeted amounts, certain sales of assets, execution, termination or amendment of certain contracts and the incurrence of debt. The North Star Project consists of a leasehold interest governed by a lease that runs for an initial term of 30 years from July 17, 2014, with an option to renew the lease term for an additional ten years at the discretion of the North Star Project Entity.

Quinto Project

The Quinto Project Entity owns the 108 MW Quinto Project located in Merced County, California. The Quinto Project achieved commercial operation in November 2015. OpCo indirectly owns 100% of the class B membership interests in Quinto Holdings, the indirect owner of 100% of the limited liability company membership interests of the Quinto Project Entity. The class A membership interests in Quinto Holdings are held by affiliates of US Bancorp Community Development Corporation, who are tax motivated project equity investors, and the class C membership interests in Quinto Holdings are held by SunPower Capital, an affiliate of SunPower. Distributions of cash flows from the Quinto Project are subject to a waterfall. Until October 27, 2020 (the “Quinto Flip Point”), and assuming a P50 production level, the class B member would be entitled to all cash flows after the payment, on a quarterly basis, of an annual preferred distribution of approximately $3.3 million. If the production from the Quinto Project exceeds a P50 production level, the class A member will be entitled to the preferred distribution and 4.95% of all distributions received from production in excess of the P50 production level until the Quinto Flip Point, at which point the preferred distribution will terminate and the class A member will be entitled to 5% of all distributions. In addition, the class C member is entitled to a distribution equal to 0.01% of the tax profit of Quinto Holdings in years when Quinto Holdings has a tax profit, and such distribution is allocated entirely from the distributions that would be otherwise payable to the class B member. Upon reaching the Quinto Flip Point, the class B member has a right to purchase the class A members’ interests in the Quinto Project for an amount that is not less than its fair market value.

SunPower Capital is the managing member of Quinto Holdings through their class C membership interests. The manager may be replaced at the class B member’s discretion at any time (such removal to be effective upon the appointment of a replacement manager). If the class B member removes the manager, the class B member’s selection of a replacement manager is subject to the reasonable consent of the class A members and certain credit and experience thresholds.

The Quinto Project is situated on an approximately 949-acre site leased by the Quinto Project Entity pursuant to a ground lease and ancillary beneficial easements, which provide the Quinto Project Entity with an initial 27 years of site control and the ability to extend the lease term for an additional seven years and ten months.

Solar Gen 2

The Solar Gen 2 Project Entity owns the 150 MW Solar Gen 2 Project located in Imperial County, California. The Solar Gen 2 Project achieved commercial operation in November 2014. OpCo indirectly owns 100% of the class B interests in SG2 Holdings, the direct owner of 100% of the limited liability company membership interests in the Solar Gen 2 Project Entity. Such class B membership interests entitle us to a 49% economic interest and currently 1% of the tax allocations and net income

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or net loss of the Solar Gen 2 Project Entity. A subsidiary of Southern Company acts as the class A member. The class A member owns a 51% economic interest and currently 99% of the tax allocations and the net income or net loss of the Solar Gen 2 Project Entity. After the Solar Gen 2 Project has been operational for approximately 11 years, the allocation of tax-related items between the class A and class B member will shift to match the economic interests. An affiliate of the class A member has managerial responsibilities for SG2 Holdings and the Solar Gen 2 Project Entity, subject to the class A members’ approval and the class B members’ approval rights with respect to certain decisions, including expenditures in excess of budgeted amounts, certain sales of assets, execution, termination or amendment of certain contracts and the incurrence of debt.

The Solar Gen 2 Project Entity sells 100% of the output from the Solar Gen 2 Project to SDG&E under a 25-year power purchase agreement (the “Solar Gen 2 PPA”). The Solar Gen 2 PPA is structured as a “contract for differences.” As such, the Solar Gen 2 Project receives revenue directly from CAISO, based on the day-ahead LMP, for energy at the Imperial Valley Substation. In turn, pursuant to the Solar Gen 2 PPA, SDG&E pays the Solar Gen 2 Project Entity the positive difference (if any) between the applicable Solar Gen 2 PPA price and the applicable day-ahead LMP. In circumstances where the day-ahead LMP exceeds the Solar Gen 2 PPA price, the Solar Gen 2 Project Entity may be required to pay SDG&E for the price difference. The Solar Gen 2 PPA has a stated price that escalates each year of the 25-year term and is subject to time of delivery adjustments.

The Solar Gen 2 Project consists of a leasehold interest governed by a ground lease that runs for an initial term of 30 years from August 2013, with an option to renew the lease term for an additional ten years at the discretion of the Solar Gen 2 Entity. 

RPU Project

The RPU Project Entity owns the 7 MW RPU Project located in Riverside County, California. The RPU Project achieved commercial operation in September 2015. OpCo indirectly owns 100% of the class B membership interests in RPU Holdings, the owner of 100% of the limited liability company membership interests of the RPU Project Entity. The class A membership interests in RPU Holdings are held by affiliates of US Bancorp Community Development Corporation and Symetra Financial Corporation, who are tax motivated project equity investors, and the class C membership interests in RPU Holdings are held by SunPower Capital, an affiliate of SunPower. Distributions of cash flows from the RPU Project are subject to a waterfall. Until October 31, 2020 (the “RPU Flip Point”), and assuming a P50 production level, the class B member would be entitled to all cash flows after the payment, on a quarterly basis, of an annual preferred distribution of approximately $0.3 million. If the production from the RPU Project exceeds a P50 production level, the class A member will be entitled to the preferred distribution and 4.95% of all distributions received from production in excess of the P50 production level until the RPU Flip Point, at which point the preferred distribution will terminate and the class A member will be entitled to 5% of all distributions. In addition, the class C member is entitled to a distribution equal to 0.01% of the tax profit of RPU Holdings in years when RPU Holdings has a tax profit, and such distribution is allocated entirely from the distributions that would be otherwise payable to the class B member. Upon reaching the RPU Flip Point, the class B member has a right to purchase the class A members’ interests in the RPU Project for an amount that is not less than its fair market value.  

SunPower Capital is the managing member of RPU Holdings through their class C membership interests. The manager may be replaced at the class B member’s discretion at any time (such removal to be effective upon the appointment of a replacement manager). If the class B member removes the manager, the class B member’s selection of a replacement manager is subject to the reasonable consent of the class A members and certain credit and experience thresholds.

The RPU Project is situated on a portion of a 120-acre site licensed by the City of Riverside to the RPU Project Entity, which such license allows for the access, construction, maintenance and operation of the RPU Project.

Stateline Project

The Stateline Project Entity owns the 300 MW Stateline Project located in San Bernardino, California. The Stateline Project achieved commercial operation in August 2016. OpCo indirectly owns 100% of the class B interests in Stateline Holdings, the direct owner of 100% of the limited liability company membership interests in the Stateline Project Entity. Such class B membership interests entitle us to a 34% economic interest and currently 1% of the tax allocations and net income or net loss of the Stateline Project Entity. A subsidiary of Southern Company acts as the class A member. The class A member owns a 66% economic interest and currently 99% of the tax allocations and the net income or net loss of the Stateline Project Entity. After the Stateline Project has been operational for approximately 11 years, the allocation of tax-related items between the class A and class B member will shift to match the economic interests. An affiliate of Southern Company has managerial responsibilities for Stateline Holdings and the Stateline Project Entity, subject to the class A members’ and the class B

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members’ approval rights with respect to certain decisions, including expenditures in excess of budgeted amounts, certain sales of assets, execution, termination or amendment of certain contracts and the incurrence of debt.

The Stateline Project is situated on an approximately 1,685-acre site governed by a ground lease that runs for an initial term of 30 years from August 2016.

C&I Projects

Typical Project Agreements

Our C&I Project Entities have entered into agreements that are customary for C&I solar energy projects. These include agreements for energy sales, construction, equipment supply, O&M services, asset management services and real estate rights. Our C&I Project Entities have also secured necessary and customary construction and operating permits.

Power Purchase Agreements.    Our C&I Project Entities have entered into offtake agreements under which each C&I Project Entity generally receives a fixed price over the term of the offtake agreement with respect to 100% of its output (except as otherwise set forth in the project descriptions below). Such offtake agreements are designed to provide a stable and predictable revenue stream.

Under our C&I Project Entities’ offtake agreements, each party typically has the right to terminate upon written notice ranging from ten to 30 days following the occurrence of an event of default that has not been cured within the applicable cure period, if any. In addition, following an uncured event of default under an offtake agreement by the applicable offtake counterparty, the applicable C&I Project Entities may in most cases, receive termination payments from the applicable offtake counterparty or pursue other remedies available at law or in equity. Events of default under these offtake agreements typically include:

• failure to pay amounts due;

• bankruptcy proceedings;

• failure to provide certain credit support; and

• breach of material obligations.

Certain of our C&I Project Entities’ offtake agreements have availability or production requirements, and if such requirements are not met, the offtake counterparty has the right to terminate the offtake agreement. Additionally, the obligations (other than payment obligations) of each party under our offtake agreements may be excused by force majeure events, and in some cases, the agreement may be terminated if the force majeure events continue for a continuous period of 12 months.

Interconnection Agreements.    Our C&I Project Entities’ projects interconnect with the applicable offtake customer’s facilities. In certain cases, the counterparties under our offtake agreements or their affiliates have entered into interconnection agreements with large regional utility companies or local distribution companies allowing our applicable project to operate in parallel with their distribution system.

Construction and Equipment Supply Agreements.    Our C&I Project Entities have entered into EPC agreements with a SunPower affiliate. In addition to setting forth the terms and conditions of construction or equipment delivery, as applicable, our C&I Project Entities receive a 25-year power and product warranty on the modules and a two- to ten-year warranty on the system.

O&M and Asset Management Agreements.    Our C&I Project Entities and certain other subsidiaries have entered into O&M agreements and AMAs with SunPower affiliates. Under the terms of the O&M agreements and AMAs, such affiliates agreed to provide a variety of operation, maintenance and asset management services and certain performance warranties to our C&I Project Entities in exchange for a fixed annual fee, subject to certain adjustments. For a detailed description of the terms of the O&M agreements and AMAs applicable to our projects, please read Part III, Item 13. “Certain Relationships and Related Transactions and Director Independence.”

Real Estate Rights.    Our C&I Project Entities and certain other subsidiaries have secured real property interests and access rights that allow our C&I solar energy projects in our Portfolio to operate without material real estate claims until the expiration of the initial terms of applicable offtake agreements, which in some cases are extendable in connection with an extension of the applicable offtake agreements.

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Our C&I Projects

Kern Project

Overview.    The Kern Project Entity owns the 18 MW Kern Project,asolar energy project consisting ofsystems attached to fixed-tilt carports located at 25 school sites in the Kern High School Districtlocated in Kern County, California. The Kern Project Entity entered into site lease agreements with Kern High School District for each project site, which are coterminous with the 20-year power purchase agreements for the Kern Project and permit the Kern Project Entity to access, construct and operate the project.

Our acquisition of the Kern Project was effectuated in phases as summarized below:

(i) Phase 1(a): On January 26, 2016, we acquired 100% of the class B limited liability company interests of the Kern Class B Partnership from SunPower. Prior to January 26, 2016, the Kern Project Entity, an indirect subsidiary of the Kern Class B Partnership, acquired the assets included in the Kern Phase 1(a) Assets. The initial phase of the acquisition of the Kern Project is referred to herein as the “Kern Phase 1(a) Acquisition.”

(ii) Phase 1(b): On September 9, 2016, the Kern Project Entity acquired the assets included in the Kern Phase 1(b) Assets. The second phase of the acquisition of the Kern Project is referred to herein as the “Kern Phase 1(b) Acquisition.”

(iii) Phase 2(a): On November 30, 2016, the Kern Project Entity acquired the assets included in the Kern Phase 2(a) Assets. The third phase of the acquisition of the Kern Project is referred to herein as the “Kern Phase 2(a) Acquisition.”

(iv) Phase 2(b): On February 24, 2017, the Kern Project Entity acquired the assets included in the Kern Phase 2(b) Assets. The fourth phase of the acquisition of the Kern Project is referred to herein as the “Kern Phase 2(b) Acquisition.”

(v) Phase 2(c): On June 9, 2017, the Kern Project Entity acquired the assets included in the Kern Phase 2(c) Assets. The fifth phase of the acquisition of the Kern Project is referred to herein as the “Kern Phase 2(c) Acquisition.”

The conditions precedent to the acquisition of the Kern Remaining Assets set forth in the Kern Letter Agreement were not met on or prior to September 30, 2017. On October 3, 2017, SunPower provided written notice to OpCo terminating the Kern Purchase Agreement, pursuant to Section 9.01(c) of the Kern Purchase Agreement, with respect to OpCo’s obligations to purchase the Kern Remaining Assets pursuant to the Kern Purchase Agreement and the Kern Letter Agreement. Pursuant to the terms of the Kern Letter Agreement, the Kern Remaining Assets are now considered SunPower ROFO Projects.

OpCo indirectly owns 100% of the class B membership interests in Kern Holdings, the direct owner of 100% of the limited liability company membership interests of the Kern Project Entity. The class A membership interests in Kern Holdings are held by an affiliate of Wells Fargo & Company, who is a tax motivated project equity investor, and the class C membership interests in Kern Holdings are held by SunPower Capital, an affiliate of SunPower. Distributions of cash flows from the Kern Project are subject to a waterfall. Until the date (the “Kern Flip Point”) which is the later of the date that the class A member’s effective after-tax internal rate of return equals 7.62% per annum and September 25, 2022, the class A member, the class B member and the class C member are entitled to approximately 5.381%, 94.524% and 0.095%, respectively, of any distributions in excess of a monthly preferred distribution payable to the tax equity investor. The preferred distribution associated with the Kern Project is currently estimated to be $1.0 million per year. After the Kern Flip Point, the preferred distribution will terminate and the class A member, the class B member and the class C member will be entitled to approximately 5.38%, 94.53% and 0.09%, respectively, of all distributions. Notwithstanding the foregoing, the terms of the operating agreement of Kern Holdings provide that, in the event that the class A member has not achieved an effective after-tax internal rate of return of at least 7.62% per annum as of July 22, 2024, the priority distribution plus 25% of net cash flow in excess thereof shall be distributed to the class A member until the class A member achieves such after-tax internal rate of return.

SunPower Capital is the managing member of Kern Holdings through their class C membership interests. The class A member and the class B member are not involved in the day-to-day management of Kern Holdings or the Kern Project; however, the managing member of Kern Holdings is required to obtain the other members’ consent for certain customary major decisions concerning the Kern Holdings and the Kern Project as set forth in the Kern Holdings operating agreement. Such major decisions subject to the approval of the class A member and/or the class B member include, for example, incurring indebtedness other than permitted indebtedness, encumbering project assets other than permitted encumbrances, selling project assets other than permitted sales, terminating material project documents under certain conditions, certain changes in method of

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accounting, merging and consolidating the projects and other such major actions. The class B member has the right to remove the managing member for convenience, and, with the approval of the class A member, install a new managing member.

Macy’s California Project

Overview.    The Macy’s California Project Entity owns the 3 MW Macy's California Project, which is comprised of seven solar generation systems located in Sacramento, Santa Clara, Santa Cruz, Alameda and San Francisco counties in California. The Macy’s California Project achieved commercial operation in October 2015. The Macy’s California Project is comprised of seven sites located on rooftops of six stores and one distribution center of Macy’s Corporate Services, Inc. (“Macy’s”), all of which are owned by an affiliate of Macy’s and leased to the Macy’s California Project Entities. The Macy’s California Project Entities entered into site lease agreements with Macy’s for each project rooftop site, which are coterminous with the 20-year power purchase agreements for the Macy’s California Project and permit the Macy’s California Project Entities to access, construct and operate the project. Please read Part I, Item 1A, “Risk Factors—Risks Related to Our Business—We rely on a limited number of offtake counterparties and we are exposed to the risk that they are unwilling or unable to fulfill their contractual obligations to us or that they otherwise terminate their offtake agreements with us.”

OpCo indirectly owns 100% of the class B membership interests in C&I Holdings, the direct owner of 100% of the limited liability company membership interests of the Macy’s California Project Entities. The class A membership interests in C&I Holdings are held by an affiliate of Wells Fargo & Company, who is a tax motivated project equity investor, and the class C membership interests in C&I Holdings are held by SunPower Capital, an affiliate of SunPower. Distributions of cash flows from the Macy’s California Project are subject to a waterfall. Until the date (the “C&I Flip Point”) which is the later of the date that the class A member’s effective after-tax internal rate of return equals 7.5% per annum and October 31, 2020, the class A member, the class B member and the class C member are entitled to approximately 2.85%, 96.18% and 0.97%, respectively, of any distributions in excess of a monthly preferred distribution payable to the tax equity investor. The preferred distribution is currently estimated to be $0.4 million a year. After the C&I Flip Point, the preferred distribution will terminate and the class A member, the class B member and the class C member will be entitled to approximately 10.55%, 88.55% and 0.90%, respectively, of all distributions. Notwithstanding the foregoing, the terms of the operating agreement of C&I Holdings provide that, in the event that the class A member has not achieved an effective after-tax internal rate of return of at least 7.5% per annum as of June 8, 2023, the priority distribution plus 25% of net cash flow in excess thereof shall be distributed to the class A member until the class A member achieves such after-tax internal rate of return.

SunPower Capital is the managing member of C&I Holdings through their class C membership interests. The class A member and the class B member are not involved in the day-to-day management of C&I Holdings or the Macy’s California Project; however, the managing member of C&I Holdings is required to obtain the other members’ consent for certain customary major decisions concerning the C&I Holdings and the Macy’s California Project as set forth in the C&I Holdings operating agreement. Such major decisions subject to the approval of the class A member and/or the class B member include, for example, incurring indebtedness other than permitted indebtedness, encumbering project assets other than permitted encumbrances, selling project assets other than permitted sales, terminating material project documents under certain conditions, certain changes in method of accounting, merging and consolidating the projects and other such major actions. The class B member has the right to remove the managing member for convenience, and, with the approval of the class A member, install a new managing member.

Macy’s Maryland Project

The Macy’s Maryland Project Entity owns the 5 MW Macy's Maryland Project, which is comprised of roof-mounted solar generation systems installed at seven Macy’s department stores located in Maryland. The Macy's Maryland Project achieved commercial operation in December 2016. The Macy’s Maryland Project Entity entered into site lease agreements with Macy’s for each project rooftop site, which are coterminous with the 20-year power purchase agreements for the Macy’s Maryland Project and permit the Macy’s Maryland Project Entities to access, construct and operate the project. Please read Part I, Item 1A, “Risk Factors—Risks Related to Our Business—We rely on a limited number of offtake counterparties and we are exposed to the risk that they are unwilling or unable to fulfill their contractual obligations to us or that they otherwise terminate their offtake agreements with us.”

OpCo indirectly controls 100% of the class B membership interests in Macy’s Maryland Holdings, the direct owner of 100% of the limited liability company membership interests of the Macy’s Maryland Project Entity. The class A membership interests in Macy’s Maryland Holdings are held by an affiliate of the PNC Financial Services Group, Inc., who is a tax motivated project equity investor, and the class C membership interests in Macy’s Maryland Holdings are held by SunPower Capital, an affiliate of SunPower. Distributions of cash flows from the Macy’s Maryland Project are subject to a waterfall. Until the date (the “Macy’s Maryland Flip Point”) which is the later of the date that the class A member’s effective after-tax internal

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rate of return equals 7.5% per annum and December 31, 2021, or December 31, 2022 if earlier, the class A member, the class B member and the class C member are entitled to approximately 12.906%, 86.994% and 0.1%, respectively, of all distributions. After the Macy’s Maryland Flip Point, the class A member, the class B member and the class C member will be entitled to approximately 9.0%, 90.9% and 0.1%, respectively, of all distributions through June 30, 2030, and 18.493%, 81.407% and 0.1%, respectively, of all distributions after June 30, 2030. Notwithstanding the foregoing, the terms of the operating agreement of Macy’s Maryland Holdings provide that, in the event that the class A member has not achieved an effective after-tax internal rate of return of at least 7.5% per annum as of December 31, 2022, 36.5% of cash flow shall be distributed to the class A member until the class A member achieves such after-tax internal rate of return.

SunPower Capital is the managing member of Macy’s Maryland Holdings through their class C membership interests. The class A member and the class B member are not involved in the day-to-day management of Macy’s Maryland Holdings or the Macy’s Maryland Project; however, the managing member of Macy’s Maryland Holdings is required to obtain the other members’ consent for certain customary major decisions concerning the Macy’s Maryland Holdings and the Macy’s Maryland Project as set forth in the Macy’s Maryland Holdings operating agreement. Such major decisions subject to the approval of the class A member and/or the class B member include, for example, incurring indebtedness other than permitted indebtedness, encumbering project assets other than permitted encumbrances, selling project assets other than permitted sales, terminating material project documents under certain conditions, certain changes in method of accounting, merging and consolidating the projects and other such major actions. The class B member has the right to remove the managing member for convenience, and, with the approval of the class A member, install a new managing member.

SRECs retained by the Macy’s Maryland Project Entity pursuant to the 20-year power purchase agreement for the Macy’s Maryland Project are sold to a non-affiliated party pursuant to a five-year purchase agreement through December 31, 2020, at a stated contract price, which remains fixed throughout the term.

UC Davis Project

The UC Davis Project Entity owns the 13 MW UC Davis Project located in Solano County, California. The UC Davis Project achieved commercial operation in September 2015. The UC Davis Project is situated on a 62-acre site leased by the Regents of the University of California (the “University”) pursuant to a ground lease agreement that is coterminous with the 20-year power purchase agreement for the UC Davis Project. C&I Holdings is the owner of 100% of the limited liability company membership interests of the UC Davis Project Entity.  As such, distributions of cash flows and management of the UC Davis Project are the same that those of the Macy’s California Project, which are set forth above.

Residential Portfolio

Overview.    Our Residential Portfolio is comprised of residential solar power systems with an aggregate of 38 MW of capacity and an average solar power system capacity of approximately 7.95 kW. Our Residential Portfolio is comprised of approximately 5,800 solar installations located in Arizona, California, Colorado, Hawaii, Massachusetts, New Jersey, New York, Pennsylvania and Vermont. We own 100% of the membership interest in the Residential Portfolio Project Entity that owns these residential solar systems. These residential solar power systems are leased to our customers under long-term lease agreements.

Lease Agreements.    A typical lease term is for 20 years and homeowners are obligated to make lease payments to us on a monthly basis. The customer’s monthly payment is fixed based on a calculation that takes into account expected solar energy generation, and certain of our current customer contracts contain price escalators with an average increase of 1% annually. The lease includes a performance warranty under which we agree to make a payment to the customer if the leased system does not meet the guaranteed performance level. Over the term of the lease, we operate and maintain the system. Customers are eligible to purchase their leased solar systems to facilitate the sale or transfer of their homes. The leases also include an early buy-out option, at no less than fair market value, exercisable in the seventh year that allows customers to purchase the solar system.

Operations & Maintenance.    SunPower Systems, a wholly owned subsidiary of SunPower, maintains the Residential Portfolio, including performing system monitoring and preventative and corrective maintenance. The O&M term is concurrent with each customer lease in the Residential Portfolio.

Our Sponsors

First Solar (NASDAQ: FSLR) is a leading global provider of comprehensive photovoltaic solar systems which use its advanced module and system technology. First Solar develops, finances, engineers, constructs and operates solar power generation assets, with over 17.0 GW sold worldwide. First Solar’s integrated power plant solutions deliver an economically

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attractive alternative to fossil-fuel electricity generation. From raw material sourcing through end-of-life module recycling, First Solar renewable energy systems protect and enhance the environment.

SunPower (NASDAQ: SPWR) is a leading global energy company that delivers complete solar solutions and services to customers worldwide. SunPower designs, manufactures and delivers the highest efficiency, highest reliability solar panels and systems available today. Residential, business, government and utility customers rely on the company’s 30 years of experience. Headquartered in San Jose, California, SunPower has offices in Africa, Asia, Australia, Europe, North and South America. SunPower is majority owned by Total S.A., the fourth largest publicly-listed energy company in the world.

Seasonality

The amount of electricity our solar power systems produce is dependent in part on the amount of sunlight, or irradiation, where the assets are located. Because shorter daylight hours in winter months results in less irradiation, the generation of particular assets will vary depending on the season.

Our power generation is expected to be at its lowest during the winter season of each year. Similarly, our first quarter revenue generation is expected to be lower than other quarters. We reserve a portion of our cash available for distribution and maintain a revolving credit facility in order to, among other things, facilitate the payment of distributions to our Class A shareholders. As a result, we do not expect seasonality to have a material effect on the amount of our quarterly distributions.

Competition

We operate in a capital-intensive industry that is currently highly fragmented and diverse, with numerous industry participants. We compete on the basis of contract price and terms, as well as the location of our projects. There is a wide variation in terms of the capabilities, resources, scale and scope of the companies with which we compete. We have numerous competitors with a varied mix of characteristics including our Sponsors and cash generating vehicles similar to us that seek to acquire energy projects from our Sponsors or third parties, as well as other renewable and conventional power generation companies. In addition, competitive conditions may be substantially affected by energy legislation and regulation considered from time to time by federal, state and local legislatures and administrative agencies. Such laws and regulations may substantially increase the costs of acquiring, constructing and operating solar energy projects, and some of our competitors may be better able to adapt to and operate under such laws and regulations.

Environmental Matters

We are required to comply with various environmental, health and safety laws and regulations in each of the jurisdictions in which we operate. These existing and future laws and regulations may impact existing and new solar energy projects, require us to obtain and maintain permits and approvals, comply with all environmental laws and regulations applicable within each jurisdiction and implement environmental, health and safety programs and procedures to monitor and control risks associated with the construction, operation and decommissioning of regulated or permitted solar power systems, all of which involve a significant investment of time and resources.

We also incur costs in the ordinary course of business to comply with these laws, regulations and permit requirements. Environmental, health and safety laws and regulations frequently change, and often become more stringent or subject to more stringent interpretation or enforcement. Such changes in environmental, health and safety laws and regulations, or the interpretation or enforcement thereof, could require us to incur materially higher costs, or cause a costly interruption of operations due to delays in obtaining new or amended permits.

The failure of our operations to comply with environmental, health and safety laws, regulations and permit requirements may result in administrative, civil and criminal penalties, imposition of investigatory, cleanup and site restoration costs and liens, denial or revocation of permits or other authorizations and issuance of injunctions to limit, suspend or cease operations.

In addition, claims by third parties for damages to persons or property, or for injunctive relief, have been brought in the past, and may be brought in the future as a result of alleged environmental, and health and safety impacts associated with our activities.

To operate our projects, we are required to obtain from federal, state and local governmental authorities a range of environmental permits and other approvals, including those described below. In addition to being subject to these regulatory requirements, we have experienced significant opposition from private third parties during the permit application process or in subsequent permit appeal proceedings.

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Clean Water Act.    Our projects may be covered under federal Clean Water Act (“CWA”) regulations to prevent or contain expected discharges of pollutants or dredged and fill materials into state waters as well as waters of the United States, including adjacent wetlands. On June 29, 2015, the EPA published a final rule that made changes to the EPA’s definition of “waters of the United States.” Various states have filed lawsuits challenging the rule and, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. On February 28, 2017, a presidential Executive Order was issued directing the EPA to review and rescind or revise the rule. On June 27, 2017, EPA proposed a rulemaking that would implement this directive by rescinding the 2015 rulemaking and re-codifying the definition in place prior to 2015. In November 2017, EPA and the U.S. Army Corps of Engineers proposed the addition of an applicability date to the 2015 Clean Water Rule that would be two years after the date of a final rule. This change, if adopted, would effectively prevent the rule from coming back into effect immediately if the stay is lifted. Depending on the result of the proposed rulemaking and litigation which will likely result, the CWA permits required by our operations may not be issued, may not be issued in a timely fashion, or may be issued with new requirements which could impose additional obligations on our operations.

BLM Right-of-Way Grants.    Some of our projects are located, or partially located, and projects that we acquire in the future may be located, on lands administered by the BLM. Therefore, we may be required to obtain and maintain BLM right-of-way grants for access to, or operations on, such lands. Obtaining and maintaining a grant requires that the project conduct environmental reviews (discussed below) and implement a plan of development and demonstrate compliance with the plan to protect the environment, including potentially expensive measures to protect biological, archeological and cultural resources encountered on the grant.

Environmental Reviews.    Solar energy projects may be subject to federal, state, or local environmental reviews, where a broad array of the solar energy project’s potential environmental impacts is assessed. Compliance with the environmental review process can be time-consuming and expensive, and generally requires public comment periods, which may open a proposed project up to adverse comments, protests or appeals. Furthermore, an agency may decide to deny a permit based on such an environmental review, or an agency may require environmental mitigation measures to offset any identified impacts. Although we do not expect any delays because of such environmental reviews, they may extend the time and/or increase the costs for obtaining necessary governmental approvals.

Endangered and Protected Species.    Federal agencies considering the permit applications for our projects are required to consult with the U.S. Fish and Wildlife Service (the “USFWS”) to consider the impact on potentially affected endangered and threatened species and their habitats under the U.S. Endangered Species Act (the “ESA”). Our projects are also required to comply with the Migratory Bird Treaty Act (the “MBTA”) and the Bald and Golden Eagle Protection Act (the “BGEPA”). Because the operation of solar energy projects could result in harm to endangered species or their habitats, or could result in injury or fatalities to protected birds, federal and state agencies may require ongoing monitoring, mitigation activities, or financial compensation as a condition to issuing a permit for a project. Violations of the ESA, MBTA, BGEPA and similar state laws may result in fines, penalties, criminal sanctions or injunctions, including the possibility of curtailment or shutdown.

Historic Preservation.    State and federal agencies may, under the National Historic Preservation Act or similar law, require our projects to protect historic, archaeological, or religious or cultural resources located or discovered near or on our project sites. Ongoing monitoring, mitigation activities, or financial compensation may be required as a condition of conducting project operations.

Clean Air Act/Climate Change.    In the past few years, the EPA has taken various actions to regulate greenhouse gas emissions under the Clean Air Act. For example, on August 3, 2015, the EPA finalized its Clean Power Plan (“CPP”), which establishes standards to limit carbon dioxide emissions from existing power generation facilities by 30% from 2005 levels by 2030. The current administration has indicated its intention to reverse some of these requirements. For instance, in October 2017, the EPA proposed a rulemaking that would withdraw the CPP. However, on December 18, 2017, the EPA issued an advance notice of proposed rulemaking (“ANPRM”) announcing it is considering new emission guidelines to replace the CPP and is soliciting information on how such limitations should be implemented. If, in implementing the CPP or any new or revised regulatory program aimed at reducing greenhouse gas emissions from the power sector, federal, state or local governments repealed or altered the incentives currently provided for renewable energy generation, it could adversely affect the attractiveness of renewable energy investments and therefore adversely impact, perhaps materially, our business, financial condition, results of operations and cash flows; however, to the extent that renewable energy is competing with higher greenhouse gas emitting energy sources, renewable energy would become more desirable.

Hazardous Waste.    We own and lease real property and may be subject to requirements regarding the management, disposal and remediation of prior contamination associated with the release of petroleum products and/or toxic or hazardous

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substances. These regulations include the federal Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act and analogous state laws. If our owned or leased properties are contaminated, whether during or prior to our ownership or operation, we could be responsible for the costs of investigation and cleanup and for any related liabilities, including claims for damage to property, persons or natural resources. That responsibility may arise even if we were not at fault and did not cause or were not aware of the contamination. In addition, waste we generate is at times sent to third party disposal facilities. If those facilities become contaminated, we and any other persons who arranged for the disposal or treatment of hazardous substances at those sites may be jointly and severally responsible for the costs of investigation and remediation, as well as for any claims for damage to third parties, their property or natural resources. We may incur significant costs in the future if we become responsible for the investigation or remediation of hazardous substances at our owned or leased properties or at third party disposal facilities.

Local Regulations.    Our operations are subject to local environmental and land use requirements, including county and municipal land use, zoning, building, water use and transportation requirements. Permitting at the local municipal or county level often consists of obtaining a special use or conditional use permit under a land use ordinance or code, or, in some cases, rezoning in connection with the solar energy project. Obtaining or maintaining a permit often requires us to demonstrate that the solar energy project will conform to development standards specified under the ordinance so that the solar energy project is compatible with existing land uses and protects natural and human environments. Local or state regulatory agencies may require modeling, testing, and, where applicable, ongoing mitigation of radar and other microwave interference in connection with the permitting and approval process. Local or state agencies also may require decommissioning plans and the establishment of financial assurance mechanisms for carrying out the decommissioning plan.

Safety and Maintenance

We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

We perform preventive and normal maintenance on all of our projects and make repairs and replacements when necessary or appropriate. We also conduct routine and required inspections of those projects in accordance with applicable regulation.

Regulatory Matters

As owners of contracted solar energy projects and participants in wholesale energy markets, our Project Entities are subject to regulation by various federal and state government agencies. These include the FERC and public utility commissions in states where our generating projects are located. In addition, some of our Project Entities are subject to the market rules, procedures and protocols of the various regional transmission organization and independent system operator markets in which they participate.

Federal Power Act

Section 205 of the FPA requires public utilities to obtain FERC’s approval of their rates for the wholesale sale of energy. Some of our Project Entities are public utilities, and each such entity has been granted authority by FERC to sell electricity at market-based rates, rather than on a traditional cost-of-service basis.

The FPA also gives FERC jurisdiction to review certain other activities of our Project Entities. In particular:

• Section 203 of the FPA requires FERC’s prior approval for any direct or indirect change of control over a public utility or its jurisdictional assets, unless otherwise granted authorization by FERC. In January 2016, FERC issued a declaratory order disclaiming jurisdiction under FPA Section 203 with respect to sales and purchases of our shares and determining that our shares are passive, non-voting securities that will not allow any shareholders to exercise control over our public utility subsidiaries.

• Section 204 of the FPA gives FERC jurisdiction over a public utility’s issuance of securities or its assumption of liabilities, subject to certain exceptions. However, FERC typically grants blanket approval for security issuances

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and the assumption of liabilities to public utilities having market-based rate authority. All of our Project Entities that are public utilities have received such blanket approval.

• In accordance with Section 215 of the FPA, FERC has approved the NERC as the national Electric Reliability Organization (“ERO”) for North America. As the ERO, NERC is responsible for the development and enforcement of mandatory reliability standards for the wholesale electric power system directly and through regional reliability organizations. Each of our Project Entities is required under the FPA to comply with NERC requirements and the requirements of the regional reliability entity for the region in which it is located.

Public Utility Holding Company Act of 2005

The PUHCA 2005 provides FERC with certain authority over and access to books and records of public utility holding companies and their subsidiaries that are not otherwise exempt from such requirements. We are a public utility holding company, but because all of our Utility Project Entities are either “Exempt Wholesale Generators” or “Qualifying Facilities,” as defined for purposes of PUHCA 2005, we are exempt from all of the FERC accounting, record retention and reporting requirements of the PUHCA 2005. We and our Project Entities are subject to state utility commission access to books and records under PUHCA 2005 in certain limited circumstances.

Government Incentives

U.S. federal, state and local governments have supported incentives to enhance industry growth and development of cost-competitive, self-sustaining renewable energy generation. These include tax incentives, regulatory programs and net metering policies. Federal tax incentives have historically been financed through tax equity transactions in which owners of renewable energy facilities utilize tax credits through partnerships with third-party investors.

Federal income tax incentives for equipment which uses solar energy to generate electricity include:

• The Investment Tax Credit:    ITC is a tax credit equal to a percentage of the basis of the eligible solar equipment at the commencement of construction (but subject to being placed into service by January 1, 2024) for tax purposes: 30% for eligible solar facilities that commence construction prior to January 1, 2020; 26% for eligible solar facilities that commence construction during 2020; 22% for eligible solar facilities that commence construction during 2021; and 10% for solar facilities that commence construction in 2022 or thereafter.

• Modified Accelerated Cost-Recovery System Depreciation:    Under MACRS depreciation, owners of the eligible solar equipment claim all of their depreciation deductions for tax purposes with respect to the equipment over five years, even though the useful economic life of such equipment is greater than five years.

• Bonus Depreciation:Under the “Protecting Americans From Tax Hikes Act of 2015,” which was signed into law December 18, 2015, owners of eligible solar equipment can claim bonus depreciation for qualified property acquired and placed in service during 2015 through 2019. The bonus depreciation percentage is 50% of the tax depreciable basis for property placed in service during 2015 through September 27, 2017. Under the H.R. 1 (Pub. L. No. 115-97), informally known as the “Tax Cuts and Jobs Act” (the “2017 Tax Act”), which was signed into law December 22, 2017, the bonus depreciation percentage is increased to 100% for qualified property acquired and placed in service after September 27, 2017 and before January 1, 2023, and phases down to 80% in 2023, 60% in 2024, 40% in 2025, 20% in 2026, and 0% for 2027 and thereafter.

Key state and local programs and incentives include:

• State Renewable Portfolio Standards:    RPS programs are state regulatory programs created by state legislatures to support growth in renewable energy by mandating that electric power providers produce or purchase certain levels of power from renewable sources. 29 states and the District of Columbia currently have an RPS program in place and eight other states have non-binding goals supporting renewable energy. Most states with mandatory RPS programs typically set a target between 10% and 30% of total energy capacity by a specific date, while other states set a MW target to achieve their RPS goals. RPS programs are expected to continue serving as drivers of U.S. renewable energy growth.

• Net Metering:    Net metering is a policy adopted by various states and utilities that provides customers who own grid-connected DG Solar assets with the ability to pay the utility only for electricity net of electricity generated by the customer’s solar system. Typically, customers receive a credit for any excess production on their regular utility bills.

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• Solar Renewable Energy Certificates:    SRECs supplement RPS programs by allowing electric power providers to purchase levels of renewable energy generation that can be used to fulfill state mandates relating to renewable energy. SRECs are purchased and traded separately from the underlying electricity generation in states that have authorized them.

Employees

We do not employ any of the individuals who manage our operations. The personnel that carry out these activities are typically employees of our Sponsors or their affiliates, and their services are provided to us or for our benefit under the MSAs, AMAs and O&M agreements of OpCo’s subsidiaries, except to the extent a project is operated, maintained or managed pursuant to an agreement with an unaffiliated third party (as in the case, for example, of the O&M agreement for the Maryland Solar Project). For a discussion of the individuals from our Sponsors’ management team that are involved in our business, please read Part III, Item 10. “Directors, Executive Officers and Corporate Governance—Management.”

Available Information

We maintain a website at http://www.8point3energypartners.com. We make available free of charge on our website our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after we electronically file these materials with, or furnish them to, the SEC. We also post our beneficial ownership reports filed by officers, directors and principal security holders under Section 16(a) of the Exchange Act, our corporate governance principles and guidelines, the charters of our audit committee, conflicts committee, and project operations committee and our code of business conduct and ethics on our website. In addition, we use our website as one means of disclosing material non-public information and for complying with our disclosure obligations under the SEC’s Regulation FD. Such disclosures will typically be included within the Investors section of our website (http://ir.8point3energypartners.com). Accordingly, investors should monitor such portions of our website in addition to following our press releases, SEC filings, public conference calls and webcasts. The information contained in or connected to our website is not incorporated by reference into this report.

The public may also read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet website that contains reports and other information regarding issuers, such as 8point3 Energy Partners, that file electronically with the SEC. The SEC’s Internet website is located at http://www.sec.gov.

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Item 1A. Risk Factors.

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks actually occur, they may materially harm our business and our financial condition and results of operations. In this event, we might not be able to pay distributions on our Class A Shares, and the trading price of our Class A Shares could decline.

Risks Related to Our Merger with Capital Dynamics

Failure to complete, or delays in completing, the Mergers with Capital Dynamics could negatively impact the market price of our Class A shares and our financial results.

Completion of the proposed Mergers with Capital Dynamics is subject to various conditions, including, among others, approval by our Class A shareholders, the absence of injunctions, the receipt of consents from third parties and governmental approvals including, but not limited to, CFIUS, FERC and HSR or other legal restrictions, and the truth and accuracy of representations and warranties, including those relating to the absence of any material adverse effect. There is no certainty that the various closing conditions will be satisfied and that the necessary approvals will be obtained. If these or other conditions are not satisfied or if there is a delay in the satisfaction of such conditions, then we may not be able to complete the Mergers timely or at all, and such failure or delay may have other adverse consequences. In addition, we and Capital Dynamics have the ability to terminate the Merger Agreement in certain circumstances.

If the Mergers are not completed or are delayed, we will be subject to a number of risks, including:

• the market price of our Class A shares may decline to the extent that their current market price reflects a market assumption that the Mergers will be completed;

• some costs relating to the Mergers, such as certain financial advisor and legal fees, must be paid even if the Mergers are not completed; and

• in specified circumstances, if the Mergers are not completed, we must pay Capital Dynamics either a termination fee of approximately $24 million or expense reimbursements up to $8 million, which may require us to borrow under our revolving credit facility.

Additionally, if the Mergers are not approved by our Class A shareholders or if the Mergers are not completed for any other reason, our Class A shareholders will not receive any payment for their Class A shares in connection with the Mergers. Instead, we will remain an independent public company, and the shares will continue to be traded on the NASDAQ. In addition, if the Mergers are not completed, we expect that management will have to reassess the Partnership’s long-term strategy, such as considering refinancing debt and other liabilities and not increasing or even reducing quarterly distributions in order to achieve sustainable long-term distributions, and that our Class A shareholders will continue to be subject to the same risks and opportunities to which they are currently subject, including, without limitation, risks related to our business as further set forth herein.

Furthermore, if the Mergers are not completed, the Board will continue to evaluate and review our business operations, properties and capitalization, among other things, make such changes as it deems appropriate and continue to seek to identify opportunities to enhance shareholder value. If the Mergers are not approved by our Class A shareholders or if the Mergers are not completed for any other reason, there can be no assurance that any other transaction acceptable to us will be offered or that our business, prospects or results of operation will not be adversely impacted. Additionally, if the Mergers are not completed, our Sponsors may continue to review their options regarding their continued ownership of us, which may include selling their interests, which could adversely impact our business, prospects or results of operations.

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The announcement and pendency of the Mergers and related uncertainty could cause disruptions in our business, which could have an adverse effect on our business and financial results and the price of our Class A shares.

Due to the terms and conditions of the Merger Agreement, the announcement of the Mergers could have an adverse effect on the price of our Class A shares. Additionally, we have important counterparties at every level of operations, including offtakers under our PPAs, lenders and tax equity investors. Uncertainty about the likelihood of completion and, the effect of the Mergers may negatively affect our relationship with our counterparties. These concerns may also cause our existing or potential new counterparties to be less likely to enter into new agreements or to demand more expensive or onerous terms, credit support, security or other conditions. Damage to our existing or potential future counterparty relationships may materially and adversely affect our business, financial condition and results of operations, including the price of our Class A shares.

Until the Mergers with Capital Dynamics are completed or the Merger Agreement is terminated, we will not be able to pursue certain other alternatives to the Mergers because of restrictions in the Merger Agreement.

Unless and until the Merger Agreement is terminated, subject to specified exceptions, we are restricted from soliciting, initiating or knowingly encouraging any inquiry, proposal or offer for an alternative transaction with any person. We may terminate the Merger Agreement and enter into an agreement with respect to a superior proposal only if specified conditions have been satisfied, including our compliance in all material respects with these non-solicitation provisions, and paying an approximately $24 million termination fee. These restrictions could affect the structure, pricing and other terms proposed by other parties seeking to enter into an alternative transaction with us and, as a result of these restrictions, we may not be able to enter into an agreement with respect to an alternative transaction on more favorable terms without incurring potentially significant liability to Capital Dynamics.

We will be subject to certain operating restrictions until completion of the Mergers.

The Merger Agreement generally restricts us, without Capital Dynamics’s consent, from taking actions outside the ordinary course of business or from taking other specified actions until the Mergers occur or the Merger Agreement terminates. These restrictions may prevent us from taking actions that we might otherwise consider beneficial.

We may be subject to class action lawsuits relating to the Mergers, which could materially adversely affect our business, financial condition and operating results or prevent or delay completion of the Mergers.

Our directors and officers may be subject to class action lawsuits relating to the Mergers, and other additional lawsuits that may be filed. Such litigation is common in connection with acquisitions of public companies, regardless of any merits related to the underlying acquisition. While we will evaluate and defend against any actions vigorously, the costs of the defense of such lawsuits and other effects of such litigation could have an adverse effect on our business, financial condition and operating results. In addition, the attention of our management may be diverted to the Mergers and related lawsuits rather than our own operations and pursuit of other opportunities that could have been beneficial to us.

One of the conditions to consummating the Mergers is that no injunction or other order prohibiting or otherwise preventing the consummation of the Mergers transactions shall have been issued by any court or governmental entity of competent jurisdiction in the United States. Consequently, if any lawsuit is filed challenging the Mergers and is successful in obtaining an injunction preventing the parties to the Merger Agreement from consummating the Mergers, such injunction may prevent the Mergers from being completed in the expected timeframe, or at all.

Failure to complete, or significant delays in completing, the Mergers could negatively affect the trading prices of our Class A shares and our future business and financial results.

The transactions contemplated by the Merger Agreement are taxable and the resulting tax liability of any Class A shareholder, if any, will depend on each such Class A shareholder’s particular situation.

The receipt of cash in exchange for our Class A shares pursuant to the Merger Agreement will be treated as a taxable sale by each holder of such Class A shares for U.S. federal income tax purposes. The amount of gain or loss recognized by each Class A shareholder will vary depending on each shareholder’s particular situation, including the amount of cash received by such shareholder pursuant to the Merger Agreement and the adjusted tax basis of the Class A shares exchanged by each shareholder therefor.

Risks Related to Our Business

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Our ability to make distributions to our Class A shareholders depends on the ability of OpCo to make cash distributions to its unitholders.

OpCo may not have sufficient available cash each quarter to pay the minimum quarterly distribution or any amount to its unitholders and therefore we may not have sufficient available cash to pay any amount to our Class A shareholders.

The amount of cash that OpCo can distribute to its unitholders, including us, each quarter principally depends upon the amount of cash its subsidiaries generate from their operations, which will fluctuate from quarter to quarter based on, among other things:

• the amount of revenue generated from the projects in which OpCo’s subsidiaries have an interest;

• the level of OpCo’s and its subsidiaries’ O&M and SG&A costs;

• the level of interest and principal amortization payments on any project-level indebtedness incurred by OpCo’s subsidiaries;

• the ability of OpCo to acquire additional projects;

• if OpCo acquires a project prior to its COD, timely completion of the project and the achievement of COD at expected capacity of the project; and

• except to the extent covered by a Sponsor pursuant to the Omnibus Agreement, indemnification obligations or diversions to tax equity investors of distributable cash from a project in order to compensate for breaches of representations, warranties or covenants; changes in allocation of ITCs, tax basis, fair market value or other tax-related matters; or delays in a distribution flip date beyond a specified date caused by a reduction of the corporate tax rate.

In addition, the amount of cash that OpCo will have available for distribution will depend on other factors, some of which are beyond its control, including:

• availability of borrowings under our revolving credit facility to pay distributions;

• debt service requirements and other liabilities, including state or local taxes we may be required to pay;

• the costs of acquisitions, if any;

• fluctuations in its working capital needs;

• timing and collectability of receivables;

• restrictions on distributions contained in existing or future debt agreements;

• prevailing economic conditions;

• access to credit or capital markets; and

• the amount of cash reserves established by the General Partner for the proper conduct of OpCo’s business.

Please read the other risks set forth in “—Risks Related to Our Business” for a discussion of risks affecting OpCo’s ability to generate cash available for distribution.

The amount of cash we have available for distribution to holders of our Class A shares depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.

The amount of cash that OpCo has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which is affected by non-cash items. As a result, even when OpCo records net losses in a period, it may be able to make cash distributions and may not be able to make cash distributions during periods when it records net income.

The seasonality of our operations may affect our liquidity.

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The amount of electricity our solar power systems produce is dependent in part on the amount of sunlight, or irradiation, where the assets are located. Because shorter daylight hours in winter months result in less irradiation, the generation of particular assets will vary depending on the season. We expect our Portfolio’s power generation to be at its lowest during the winter season of each year, thus, we expect our first quarter revenue generation to be lower than other quarters during our fiscal year.

We will need to maintain sufficient financial liquidity to absorb the impact of seasonal variations in energy production. We may need to reserve cash in other quarters or borrow under our revolving credit facility in order to pay distributions in quarters with shorter daylight hours.

Our level of indebtedness or restrictions in OpCo’s credit facility, or any future indebtedness of OpCo’s subsidiaries, could adversely affect our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

As of November 30, 2017, we had outstanding borrowings of $300.0 million under the term loan facility, $250.0 million under the incremental term loan facility, $25.0 million under the delayed draw term loan facility and $70.0 million under the revolving credit facility, as well as approximately $54.6 million of letters of credit outstanding under the revolving credit facility. The remaining portion of the revolving credit facility, or approximately $75.4 million, was undrawn as of November 30, 2017. In the future, we may significantly increase our debt to fund our operations or future acquisitions. We may also enter into project-level financing arrangements for our existing projects or in connection with future acquisitions.  

OpCo’s credit facility matures in June 2020. We do not have available cash or short-term liquid investments sufficient to repay all of this medium-term debt and we have not obtained commitments for refinancing this debt. Therefore, we may not be able to extend the maturity of this debt or to otherwise successfully refinance current maturities if the corporate finance markets deteriorate substantially. Refinancing such indebtedness may force us to accept then-prevailing market terms that are less favorable than our existing debt, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders. In addition, in the future, we may significantly increase our debt to fund our operations or future acquisitions. We may also enter into project-level financing arrangements for our existing projects or in connection with future acquisitions. Moreover, in specified circumstances, if the Merger is not completed, we must pay Capital Dynamics either a termination fee of approximately $24 million or up to $8 million in expense reimbursements, which may require us to borrow under our revolving credit facility.  

OpCo’s credit facility contains various covenants and restrictive provisions that limit OpCo’s ability to, among other things:

• incur or guarantee additional debt;

• make distributions on or redeem or repurchase OpCo common units;

• make certain investments and acquisitions;

• incur certain liens or permit them to exist;

• enter into certain types of transactions with affiliates;

• merge or consolidate with another company; and

• transfer, sell or otherwise dispose of projects.

Any future project-level financing arrangements may contain similar covenants and restrictive provisions.

In addition, OpCo’s debt and any future project level debt could have important negative consequences on our financial condition, including:

• restricting the ability of OpCo’s subsidiaries to make certain distributions to OpCo, OpCo’s ability to make certain distributions to us and our ability to make certain distributions with respect to our Class A shares in light of restricted payment and other financial covenants in OpCo’s credit facility;

• increasing our vulnerability to general economic and industry conditions;

• requiring a substantial portion of OpCo’s cash flow from operations to be dedicated to the payment of principal and interest on its indebtedness, therefore reducing its ability to pay distributions to us and our ability to pay distributions to our Class A shareholders or to use OpCo’s cash flow to fund operations, capital expenditures and future business opportunities;

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• limiting our ability to enter into long-term offtake agreements because such offtake agreements require credit support which may not be permitted under our financing arrangements;

• limiting our ability to enter into power interconnection agreements, which typically require credit support, which may not be permitted under our financing arrangements, for the construction of interconnection facilities and network upgrades to the transmission grid;

• limiting our ability to fund operations or future acquisitions;

• exposing us to the risk of increased interest rates because certain of OpCo’s borrowings are at variable rates of interest;

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

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

OpCo’s credit facility also contains covenants requiring OpCo to maintain certain financial ratios, including as a condition to making cash distributions to us and its other unitholders. OpCo’s ability to meet those financial ratios and tests can be affected by events beyond our control, and it may be unable to meet those ratios and tests and therefore may be unable to make cash distributions to its unitholders including us. As a result, we may be unable to make distributions to our Class A shareholders. In addition, the credit facility contains events of default customary for transactions of this nature, including the occurrence of a change of control.

The provisions of the credit facility may affect our ability to pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. A failure to comply with the provisions of the credit facility could result in an event of default, which could enable the lenders to declare, subject to the terms and conditions of the applicable credit facility, any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable and entitle lenders to enforce their security interest. If the payment of the debt is accelerated, the revenue from the projects may be insufficient to repay such debt in full, lenders could enforce their security interest and our Class A shareholders could experience a partial or total loss of their investment.

In addition, a high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, commodity prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our Class A shares or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

Our ability to effectively consummate future acquisitions will also depend on our ability to arrange the required or desired financing for acquisitions.

OpCo distributes a substantial amount of its available cash to its unitholders, including us, and will rely primarily upon its cash reserves and external financing sources, including borrowings under its revolving credit facility and the issuance of debt and equity securities, including by us, as well as tax equity financing, to fund future acquisitions.

OpCo may not have sufficient availability under its credit facilities or have access to project-level financing on commercially reasonable terms when acquisition opportunities arise. In addition, our and its ability to access the capital markets is dependent on, among other factors, the overall state of the capital markets and investor appetite for investment in clean energy projects, cash generating vehicles similar to us in general, and our Class A shares in particular and may be limited by our and its financial condition at such time as well as the covenants in our debt agreements, general economic conditions and contingencies or other uncertainties that are beyond our control. An inability to obtain the required or desired financing, or any terms of such financing that makes an acquisition economically undesirable, could significantly limit our ability to consummate future acquisitions. If financing is available, it may be available only on terms that could significantly increase our interest expense, impose additional or more restrictive covenants and reduce cash available for distribution. Furthermore, under the terms of the Stateline Promissory Note, we are generally required to use the proceeds of sales of our Class A shares to pre-pay amounts outstanding under the Stateline Promissory Note until it is paid in full. As a result, the proceeds from such a sale will not be used to consummate future acquisitions until the Stateline Promissory Note is paid in full.

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Due to our higher cost of capital and inability to access the capital markets on a consistent basis, commencing in fiscal 2016, we and our Sponsors agreed to make several adjustments to the projects subject to the ROFO Agreements, replacing interests in certain projects with alternatives. Later, when certain projects were ultimately offered to us under the ROFO Agreement, we were unable to transact due to these same fiscal constraints. The offered projects were subsequently acquired by third party buyers at purchase prices higher than those offered to us. As a result of such adjustments, we no longer have a right of first offer on any projects developed by First Solar. Such challenges present certain strategic and financial implications on our operations, including, but not limited to, difficulty maintaining a sustainable, long-term distribution growth strategy, potential refinancing of our capital structure in order to acquire additional projects, and our prospects as a stand-alone public company without the Sponsors and our resulting competitive position in the market for renewable energy assets. In addition, due to the limitations on our ability to acquire projects under the Merger Agreement, we agreed to enter into the Waiver Agreement with SunPower which waives our right of first offer on all the projects subject to the SunPower ROFO Agreement during the pendency of the Merger Agreement.

To the extent we are unable to finance acquisitions with external sources of capital, the requirement in OpCo’s limited liability company agreement to distribute all of its available cash and our current cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, we may not be able to make acquisitions that businesses that reinvest all of their available cash to expand ongoing operations may be able to make.

To the extent we issue additional shares, the payment of distributions on those additional shares may increase the risk that we will be unable to maintain or increase our cash distributions per share. There are no limitations in our Partnership Agreement on our ability to issue additional shares, including shares ranking senior to our Class A shares, and our shareholders (other than our Sponsors and their affiliates) will have no preemptive or other rights (solely as a result of their status as shareholders) to purchase any such additional shares. If we incur additional debt (under our revolving credit facility or otherwise) to finance acquisitions, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our Class A shareholders.

OpCo is not permitted to acquire interests in projects until we pay in full the principal of and interest on the Stateline Promissory Note.

On December 1, 2016, in connection with the acquisition of the Stateline Project, OpCo issued the Stateline Promissory Note to a subsidiary of First Solar in the principal amount of $50.0 million. The Stateline Promissory Note is unsecured and matures on the date that is six months after the maturity date under OpCo’s credit facility. Interest will accrue at a rate of 4.00% per annum, except it will accrue at a rate of 6.00% per annum (i) upon the occurrence and during the continuation of a specified event of default and (ii) in respect of amounts accrued as payments-in-kind pursuant to the terms of the Stateline Promissory Note.

Until OpCo has paid in full the principal and interest on the Stateline Promissory Note, OpCo is restricted in its ability to:

• acquire interests in additional projects;

• use the net proceeds of equity issuances except as prescribed in the Stateline Promissory Note;

• incur additional indebtedness to which the Stateline Promissory Note would be subordinate; and

• extend the maturity date under OpCo’s credit facility.

Any of the above restrictions could substantially affect our ability to grow our business, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

Our inability to acquire additional solar energy projects due to our Sponsors’ decision to keep projects that they develop, competing bids for a solar energy project, our inability to agree on terms with the developer of a solar energy project, including our Sponsors, or our inability to arrange the required or desired financing for such acquisitions could have a significant effect on our ability to grow.

Our acquisition strategy is based on our expectation of ongoing divestitures of solar energy projects by project developers, including our Sponsors. Though the SunPower ROFO Agreement provides us with a right of first offer until June 24, 2020 with respect to certain projects that SunPower is developing should it choose to sell such projects, there is no guarantee that SunPower will make available to us any projects before our right of first offer expires or at all. In addition, due

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to the limitations on our ability to acquire projects under the Merger Agreement, in connection with the Conflicts Committee’s and the Board’s approval of the Merger Agreement, we agreed to enter into the Waiver Agreement with SunPower which waives our right of first offer on all the projects subject to the SunPower ROFO Agreement during the pendency of the Merger Agreement. In the event that the Merger Agreement terminates without the closing of the Mergers, the waiver would terminate with respect to all projects subject to the SunPower ROFO Agreement, except, with respect to individual projects still owned by SunPower at the termination of such waiver, the projects that are either under a binding, written exclusivity agreement with a third party or have an offer for purchase from a third party pursuant to which SunPower is in negotiations.

In addition, our Sponsors have developed, and may continue to develop in the future, many solar energy projects that are not subject to the SunPower ROFO Agreement. Our Sponsors may freely sell such projects to third parties without any obligation to us. Furthermore, even if we have the opportunity to make a first offer on projects that our Sponsors seek to sell or to acquire projects from a third party, we may choose not to pursue such opportunity, be unable to negotiate acceptable purchase contracts with them for such projects, be unable to obtain financing for these acquisitions on economically acceptable terms, be outbid by competitors including our Sponsors or cash generating vehicles similar to us or be unable to obtain necessary governmental or third-party consent. We are also restricted, under the terms of the Stateline Promissory Note, from acquiring interests in projects until we pay in full the principal of and interest on the Stateline Promissory Note. Additionally, our Sponsors are under no obligation to accept any offer made by us with respect to such opportunities and upon a failure to agree to such offer are subject to few restrictions when selling to a third party. Third party purchasers may have lower costs of capital than us, and our Sponsors may be able to sell projects to such third parties on more favorable terms than we would be able or willing to accept. Furthermore, for a variety of reasons, we may decide not to exercise these rights when they become available, and our decision will not be subject to shareholder approval. As such, there is no guarantee that we will be able to make any such offer or consummate any acquisition of solar energy projects from our Sponsors or others.

At or prior to COD of the projects subject to the SunPower ROFO Agreement, SunPower may enter into arrangements, often referred to as tax equity financing, with investors seeking to utilize the tax attributes of their projects which may result in a reduction of our expected economic ownership of such SunPower ROFO Project. These arrangements have multiple potential structures which have differing impacts on our economic ownership and may be on terms less favorable than those currently in place at certain of our existing projects.

We may not be able to make acquisitions of additional solar energy projects that are accretive or of the best economic interest to us.

Our ability to expand our business operations and increase our quarterly cash distributions depends on pursuing opportunities to acquire contracted solar energy projects from our Sponsors and others. The evolving nature of the solar industry has enabled the Sponsors’ strategies of recycling capital faster and more efficiently by selling projects at a stage of construction and development, which is earlier than best suited for us. Due to our higher cost of capital and inability to access the capital markets on a consistent basis, commencing in fiscal 2016, we and our Sponsors agreed to make several adjustments to the projects subject to the ROFO Agreements, replacing interests in certain projects with alternatives. Later, when certain projects were ultimately offered to us under the ROFO Agreement, we were unable to transact due to these same fiscal constraints. The offered projects were subsequently acquired by third party buyers at purchase prices higher than those offered to us. As a result of such adjustments, we no longer have a right of first offer on any projects developed by First Solar. In addition, until the Stateline Promissory Note is repaid in full, our ability to acquire new projects is restricted. Such challenges present certain strategic and financial implications on our operations, including, but not limited to, difficulty maintaining a sustainable, long-term distribution growth strategy, potential refinancing of our capital structure in order to acquire additional projects, and our prospects as a stand-alone public company without the Sponsors and our resulting competitive position in the market for renewable energy assets. In addition, due to the limitations on our ability to acquire projects under the Merger Agreement, we agreed to enter into the Waiver Agreement with SunPower which waives our right of first offer on all the projects subject to the SunPower ROFO Agreement during the pendency of the Merger Agreement.

Various factors, described in more detail in succeeding risk factors, could affect the availability, ability to acquire or performance of such solar energy projects we seek to acquire to grow our business, including the following factors, which are described in more detail in the additional risk factors herein:

• our inability to consummate an acquisition of a SunPower ROFO Project or other solar energy project due to the Waiver Agreement;

• our inability to acquire interests in projects until we pay in full the principal of and interest on the Stateline Promissory Note; or

• performance of the acquired assets at a level below expectations.

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The occurrence of any of these events could substantially affect our ability to grow our business which would correspondingly have a material adverse effect on our ability to grow our cash distributions to our Class A shareholders.

SunPower’s failure to complete the development of the SunPower ROFO Projects or project developers’, including our Sponsors’, failure to develop other solar energy projects, including those opportunities that are part of our Sponsors’ development pipeline, could have a significant effect on our ability to grow.

SunPower could decide not to develop or to discontinue development of the SunPower ROFO Projects and project developers, including our Sponsors, could decide not to develop additional solar energy projects, including those opportunities included in our Sponsors’ development pipeline, for a variety of reasons, including, among other things, the following:

• issues related to pricing and terms under offtake agreements;

• issues related to project siting, including permits, environmental regulations and governmental approvals, and the negotiation of project development agreements;

• difficulty accessing the capital markets to secure construction financing;

• sustained pressure on pricing for the solar modules sold by our Sponsors, which may adversely affect our Sponsors’ cash flows and ability to develop solar energy projects;

• issues with solar energy technology being unsuitable for widespread adoption at economically attractive rates of return;

• demand for solar power systems failing to develop sufficiently or taking longer than expected to develop, including as a result of the extension of the ITC;

• a reduction in government incentives or adverse changes in policy and laws for the development or use of solar energy;

• issues related to the imposition of safeguard tariffs on crystalline silicon photovoltaic products ("CSPV") pursuant to Proclamation 9693 of January 23, 2018, “To Facilitate Positive Adjustment to Competition From Imports of Certain Crystalline Silicon Photovoltaic Cells (Whether or Not Partially or Fully Assembled Into Other Products) and for Other Purposes,” including market volatility, price fluctuations, supply shortages, and project delays in the near term and materially increasing the price of solar products in the long term;

• competition from other alternative energy technologies or conventional energy companies;

• high development or capital costs; and

• a material reduction in the retail or wholesale price and availability of traditional utility generated electricity or electricity from other sources.

Due to our higher cost of capital and inability to access the capital markets on a consistent basis, commencing in fiscal 2016, we and our Sponsors agreed to make several adjustments to the projects subject to the ROFO Agreements, replacing interests in certain projects with alternatives. Later, when certain projects were ultimately offered to us under the ROFO Agreement, we were unable to transact due to these same fiscal constraints. The offered projects were subsequently acquired by third party buyers at purchase prices higher than those offered to us. As a result of such adjustments, we no longer have a right of first offer on any projects developed by First Solar. In addition, until the Stateline Promissory Note is repaid in full, our ability to acquire new projects is restricted. Such challenges present certain strategic and financial implications on our operations, including, but not limited to, difficulty maintaining a sustainable, long-term distribution growth strategy, potential refinancing of our capital structure in order to acquire additional projects, and our prospects as a stand-alone public company without the Sponsors and our resulting competitive position in the market for renewable energy assets. In addition, due to the limitations on our ability to acquire projects under the Merger Agreement, we agreed to enter into the Waiver Agreement with SunPower which waives our right of first offer on all the projects subject to the SunPower ROFO Agreement during the pendency of the Merger Agreement.

Both of our Sponsors also announced significant work force reductions in the second half of 2016. If the challenges of developing solar energy projects increase for project developers, including our Sponsors, our pool of available opportunities may be limited, which could have a material adverse effect on our ability to grow our business and make cash distributions to our Class A shareholders.

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Even if we consummate acquisitions that we believe will be accretive to cash available for distribution per Class A share, those acquisitions may decrease the cash available for distribution per Class A share as a result of incorrect assumptions in our evaluation of such acquisitions, unforeseen consequences or other external events beyond our control.

The acquisition of existing solar energy projects involves the risk of overpaying for such projects (or not making acquisitions on an accretive basis) and failing to retain the customers of such projects. In addition, upon consummation of an acquisition, such acquisition will be subject to many of the risks set forth above in “—Risks Related to Our Business.” While we will perform due diligence on prospective acquisitions, we may not discover all potential risks, operational issues or other issues in such solar energy projects. In addition, in determining to acquire attractively priced operating solar power systems, the General Partner may be influenced by factors that could result in a misalignment or conflict of interest. Further, the integration and consolidation of acquisitions require substantial human, financial and other resources and, ultimately, our acquisitions may divert our management’s attention from our existing business concerns, disrupt our ongoing business or not be successfully integrated. Future acquisitions might not perform as expected or the returns from such acquisitions might not support the financing utilized to acquire them or maintain them. A failure to achieve the financial returns we expect when we acquire solar energy projects could have a material adverse effect on our ability to grow our business and make cash distributions to our Class A shareholders. Any failure of our acquired solar energy projects to be accretive or difficulty in integrating such acquisition into our business could have a material adverse effect on our ability to grow our business and make cash distributions to our Class A shareholders.

We have a limited operating history and our projects may not perform as we expect.

The majority of projects in our Portfolio are relatively new. As of November 30, 2017, our Portfolio consisted of interests in 946 MW of solar energy projects located entirely in the United States, all of which are operational. As of November 30, 2017, we owned interests in ten utility-scale solar energy projects representing 92% of the generating capacity of our Portfolio, and four C&I solar energy projects and a portfolio of residential DG Solar assets representing 8% of the generating capacity of our Portfolio. In addition, all of our Residential Portfolio attained COD within the last five years. As a result, our assumptions and estimates regarding the performance of these projects are and will be made without the benefit of a meaningful operating history, which may impair our ability to accurately estimate our results of operations, financial condition and liquidity. The ability of our projects to perform as we expect will also be subject to risks inherent in newly constructed solar energy projects, including equipment and system performance below our expectations or equipment and system failures and outages. The failure of some or all of our projects to perform according to our expectations could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

Energy projects involve significant risks that could result in a business interruption or partial or complete shutdown for which we may not be adequately insured.

There are risks associated with the ownership and operation of our projects. These risks include:

• breakdown or failure of solar modules, inverters, transformers and other equipment that are not covered by warranty or insurance;

• catastrophic events, such as fires, earthquakes, severe weather, tornadoes, ice or hail storms or other meteorological conditions, landslides, effects of climate change and other similar events beyond our control, which could severely damage or destroy a project, reduce its energy output or result in personal injury, loss of life or property damage;

• technical performance below expected levels, including the failure of solar modules and other equipment to produce energy as expected due to incorrect measures of performance provided by equipment suppliers;

• increases in the cost of operating the projects, including costs relating to labor, equipment, insurance, permit compliance and taxes;

• operator, contractor or equipment provider error or failure to perform;

• serial design or manufacturing defects, which may not be covered by warranty or insurance;

• certain unremediated events under project contracts that may give rise to a termination right of the contract counterparty;

• failure to comply with permits and the inability to renew or replace permits that have expired or terminated;

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• the inability to operate within limitations that may be imposed by current or future governmental permits or project contracts;

• replacements for failed equipment, which may need to meet new interconnection standards or require system impact studies and compliance that may be difficult or expensive to achieve;

• land use, environmental or other regulatory requirements;

• disputes with owners of land on which our projects are located or adjacent landowners;

• changes in law, including changes in governmental permit requirements;

• terrorist attacks, cyber-attacks, theft, vandalism and other intentionally harmful acts;

• government or utility exercise of eminent domain power or similar events; and

• existence of superior interests, liens, encumbrances and other imperfections in title affecting ownership and use of real estate interests.

Any of the risks described above could significantly decrease or eliminate the revenues of a project, significantly increase its operating costs, cause OpCo or its subsidiaries to default under OpCo’s credit facility or other financing agreements or give rise to damages or penalties owed by us to a contractual counterparty, a governmental authority or other third parties or cause defaults under related contracts or permits. Any of these events could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

We rely on a limited number of offtake counterparties and we are exposed to the risk that they are unwilling or unable to fulfill their contractual obligations to us or that they otherwise terminate their offtake agreements with us.

In most instances, we sell the energy generated by each of our utility and C&I scale projects to a single counterparty under a long-term offtake agreement. These offtake agreements are the primary source of cash flows for these projects. Thus, the actions of even one offtake counterparty may cause material variability of our overall revenue, profitability and cash flows that are difficult to predict. Our counterparties may face liquidity and credit issues that could impair their ability to meet their payment obligations under such offtake agreements or cause them to renegotiate such offtake agreements at lower rates or for shorter terms. These conditions may lead some of our customers, particularly customers that are facing financial difficulties, to seek to renegotiate such offtake agreements on terms that are less attractive to us.

For example, FirstEnergy Solutions Corp. (“FirstEnergy”), our offtake counterparty with respect to the Maryland Solar Project, had its credit rating downgraded multiple times in 2016 and 2017. As of January 31, 2018, the credit rating of FirstEnergy was Ca and CCC- by Moody’s Investors Service and Standard & Poor’s Ratings Services, respectively, both of which are below investment grade. In addition, Standard & Poor’s Ratings Services placed FirstEnergy on CreditWatch with negative implications, based on a significant impairment charge that the company’s competitive business will incur from the deactivation of several coal units. In November 2016, FirstEnergy Corp., the parent of FirstEnergy, announced a strategic review of its competitive business, pursuant to which the company would seek to move away from competitive markets. In addition, Standard & Poor’s Ratings Services also placed another of our offtake counterparties, Macy’s, on CreditWatch in January 2016 and on CreditWatch negative in January 2017. FirstEnergy’s annual report on their Form 10-K for their 2016 fiscal year reported a substantial uncertainty as to their ability to continue as a going concern. Both First Energy and Macy’s remain on Standard & Poor’s Ratings Services under CreditWatch.

As further described in Part III, Item 13. “Certain Relationships and Related Transactions, and Director Independence—Agreements with our Sponsors—Maryland Solar Lease Arrangement,” the Maryland Solar Project Entity has leased the Maryland Solar Project to an affiliate of First Solar, with the lease term expiring on December 31, 2019. Under the arrangement, First Solar’s affiliate is obligated to pay a fixed amount of rent that is set based on the expected operations of the plant. Such lease agreement will terminate upon any termination of the PPA for the Maryland Solar Project or the site ground lease. Pursuant to the PPA for the Maryland Solar Project, a FirstEnergy bankruptcy would be an event of default under the PPA, permitting (subject to applicable law) the termination of the PPA, although FirstEnergy may choose to renegotiate or maintain the PPA in its current form. Upon any such early termination of the lease agreement, First Solar’s affiliate is obligated to return the facility in its then-current condition and location to us, without any warranties, and no rent shall thereafter be payable by such First Solar affiliate. In the event that the PPA was terminated, the Maryland Solar Project would have no agreement through which to sell the energy that it produces, which equates to approximately $8.0 million in annual revenue. We would attempt to replace the PPA with a similar offtake agreement; however, we may not be able to find a replacement offtake agreement in a timely manner or at all and the terms of any replacement agreement may be less favorable to us than the terminated PPA.

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We evaluate our long-lived assets, including property and equipment and projects, for impairment whenever events or changes in circumstances indicate the carrying value of such assets may not be recoverable. In consideration of the above events, we evaluated whether the carrying value of the project may no longer be recoverable using a probability-weighted assessment of potential outcomes and related undiscounted cash flows. As a result of such evaluation, we concluded the estimated future undiscounted net cash flows expected to be generated by the project over its estimated useful life exceeded the $51.5 million carrying value of the Maryland Solar Project's property and equipment as of November 30, 2017. Such assessment is subject to significant uncertainty and could change significantly as facts and circumstances change. In the event that the PPA for the Maryland Solar Project was terminated, if we are unable to enter into a replacement agreement or sell the energy it produces under similar terms, the carrying value of the project may not be recoverable, and we would record a material impairment loss in the amount by which the carrying value exceeds the fair value.

While as of November 30, 2017, both FirstEnergy and Macy’s are current with respect to payments due under the PPAs for the Maryland Solar Project, the Macy’s California Project and the Macy’s Maryland Project, as applicable, a failure by such offtake counterparties to fulfill their obligations under their respective PPAs, or any restructuring of their obligations pursuant to bankruptcy or similar proceedings, could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

Similarly, significant portions of our credit risk may be concentrated among a limited number of offtake counterparties and the failure of even one of these key offtake counterparties to pay its obligations to us could significantly impact our business and financial results. Our largest offtake counterparties are Southern California Edison and SDG&E. Our customers in our residential projects lease solar power systems from us under long-term lease agreements. The lease terms are typically for 20 years, and require the customer to make monthly payments to us. Accordingly, we are subject to the credit risk of our customers. The average FICO score of our residential customers was approximately 765 at the time of initial contract. The risk of customer defaults may increase if we grow our portfolio of residential projects. Any or all of our offtake counterparties may fail to fulfill their obligations under their offtake agreements with us, whether as a result of the occurrence of any of the following factors or otherwise:

• specified events beyond our control or the control of an offtake counterparty may temporarily or permanently excuse the offtake counterparty from its obligation to accept and pay for delivery of energy generated by a utility project. These events could include a system emergency, transmission failure or curtailment, adverse weather conditions or labor disputes;

• the ability of our offtake counterparties to fulfill their contractual obligations to us depends on their creditworthiness. We are exposed to the credit risk of our offtake counterparties over an extended period of time due to the long-term nature of our offtake agreements with them. These customers could become subject to insolvency or liquidation proceedings or otherwise suffer a deterioration of their creditworthiness when they have not yet paid for energy delivered, any of which could result in underpayment or nonpayment under such agreements; and

• a default or failure by us to satisfy minimum energy delivery requirements or in mechanical availability levels under our offtake agreements could result in damage payments to the offtake counterparty or termination of the applicable offtake agreement.

If our offtake counterparties are unwilling or unable to fulfill their contractual obligations to us, or if they otherwise terminate such offtake agreements prior to their expiration, we may not be able to recover contractual payments and commitments due to us. Since the number of utility and C&I customers is limited, we may be unable to find a new energy purchaser on similar or favorable terms or at all. In some cases, there currently is no economical alternative counterparty to the original offtake counterparty. The loss of or a reduction in sales to any of our offtake counterparties could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

We depend on certain projects for a substantial portion of our anticipated cash flows.

We depend on certain projects for a substantial portion of our anticipated cash flows. We may not be able to successfully execute our acquisition strategy in order to further diversify our sources of cash flow and reduce our portfolio concentration. Consequently, the impairment or loss of any one or more of our large utility-scale solar energy projects, such as the Henrietta Project, the Quinto Project, the Solar Gen 2 Project or the Stateline Project, would materially and disproportionately reduce our total energy generation and cash flows and, as a result, have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

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Our business is concentrated in certain markets, putting us at risk of region specific disruptions.

Of the 946 MW in our Portfolio as of November 30, 2017, approximately 855 MW is located in California, including approximately 799 MW of our utility projects and 56 MW of our DG Solar projects, further concentrating our customer base and operational infrastructure. Accordingly, our business and results of operations are particularly susceptible to adverse economic, regulatory, political, weather and other conditions in this market and in other markets where we become similarly concentrated. Any of these conditions could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders. In addition, all our assets are located in the United States, which makes us particularly susceptible to adverse changes in U.S. tax and environmental laws. Please read “—Government regulations providing incentives and subsidies for solar energy could change at any time, including pursuant to the proposed environmental and tax policies of the current administration” and “—Risks Related to Taxation—Our future tax liability may be greater than expected if we do not generate NOLs sufficient to offset taxable income or if tax authorities challenge certain of our tax positions.”

A subsidiary of Southern Company controls certain of the entities that own our largest projects, and we may acquire projects in the future that neither we nor our Sponsors control.

A subsidiary of Southern Company owns a 51% economic interest in, and we own a 49% economic interest in, each of the Henrietta Project Entity, the Lost Hills Blackwell Project Entity, the North Star Project Entity and the Solar Gen 2 Project Entity. In addition, a subsidiary of Southern Company owns a 66% economic interest in, and we own a 34% economic interest in the Stateline Project Entity. Collectively, these five project entities in which we own minority interests constitute over 68% of the MW of the projects in our portfolio of solar assets as of November 30, 2017.

We do not control the governing boards of these project entities and, as the minority interest holder, we have limited approval rights with respect to such project entities. As a result, we have limited influence over these project entities and limited flexibility to control the operation of or cash distributions received from these entities. Specifically,

• we may have limited ability to control decisions with respect to the operations of these entities and their subsidiaries, including decisions with respect to incurrence of expenses and distributions to us and to project contract compliance and enforcement of counterparty obligations under such project contracts;

• these entities may establish reserves for working capital, capital projects, environmental matters and legal proceedings which would otherwise reduce cash available for distribution to us;

• these entities may incur additional indebtedness, and principal and interest made on such indebtedness may reduce cash otherwise available for distribution to us;

• the terms of indebtedness of these entities may limit their ability to distribute cash to us; and

• these entities may require us to make additional capital contributions to fund working capital and capital expenditures, our funding of which could reduce the amount of cash otherwise available for distribution.

In addition to the other risks inherent in these projects, we are subject to the credit risk of Southern Company. If Southern Company were to fail to perform its obligations adequately, it could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

In the case of the Henrietta Project Entity, the Lost Hills Blackwell Project Entity, the North Star Project Entity, the Solar Gen 2 Project Entity and the Stateline Project Entity, cash distributions are made on a quarterly basis to the extent cash is available after payment of third-party expenses, member loans, indemnification obligations and reserves. Reserves are based on the amount of reserves in the annual approved budget, permitted agreements approved after the approval of the annual budget, reserves required by any indebtedness of the entity and working capital reserves not to exceed the amount of permitted budget variances. Subject to certain exceptions, the cash distribution amount is allocated (i) 51% to a subsidiary of Southern Company and 49% to OpCo with respect to the Henrietta Project Entity, the Lost Hills Blackwell Project Entity, the North Star Project Entity and the Solar Gen 2 Project Entity and (ii) 66% to a subsidiary of Southern Company and 34% to OpCo with respect to the Stateline Project Entity.

Further, additional solar energy projects we may acquire may be subject to a similar structure where we do not own a majority of the project entity and we may invest in joint ventures in which we share control or in which we are a minority investor. In these instances, the majority investor or controlling investor may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these assets optimally.

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Any of these items could significantly and adversely impact our ability to distribute cash to our Class A shareholders. For a more complete description of the agreements governing the management and operation of the entities in our Portfolio in which we own an interest, please read Part III, Item 13. “Certain Relationships and Related Transactions, and Director Independence.”

Government regulations providing incentives and subsidies for solar energy could change at any time, including pursuant to the proposed environmental and tax policies of the current administration, and such changes may negatively impact our business.

Our ability to acquire solar energy projects partly depends on current government policies that promote and support solar energy and enhance the economic viability of owning solar energy projects. Solar energy projects currently benefit from various U.S. federal, state and local governmental incentives, such as ITCs, loan guarantees, RPS programs or the Modified Accelerated Cost-Recovery System for depreciation and other incentives. These policies have had a significant impact on the development of solar energy and they could change at any time, especially in the event that the current administration were to embark on a significant change in federal energy policy. These incentives make the development of solar energy projects more competitive by providing tax credits and accelerated depreciation for a portion of the development costs, decreasing the costs associated with developing such projects or creating demand for renewable energy assets through RPS programs. A loss or reduction in such incentives or the value of such incentives or a reduction in the capacity of potential investors to benefit from such incentives could decrease the attractiveness of solar energy projects to project developers, including our Sponsors, and the attractiveness of solar power systems to utilities and DG Solar customers, which could reduce our acquisition opportunities. Such a loss or reduction could also reduce our willingness to pursue solar energy projects due to higher operating costs or lower revenues from offtake agreements.

The current administration’s proposed environmental and tax policies may create regulatory uncertainty in the clean energy sector, including the solar energy sector, and may lead to a reduction or removal of various clean energy programs and initiatives designed to curtail climate change. Such a reduction or removal of incentives may diminish the market for future solar energy offtake agreements and reduce the ability for solar developers to compete for future solar energy offtake agreements, which may reduce incentives for project developers, including our Sponsors, to develop such projects. The ITC is a U.S. federal incentive that provides an income tax credit to the owner of the project after the project commences construction of up to 30% of eligible basis. A solar energy project must commence construction prior to January 1, 2020 and be placed in service prior to January 1, 2024, to qualify for the 30% ITC. A solar project that commences construction during 2020 and is placed in service prior to January 1, 2024, may qualify for an ITC equal to 26% of eligible basis. Under the Modified Accelerated Cost-Recovery System, owners of equipment used in a solar project generally claim all of their depreciation deductions with respect to such equipment over five years, even though the useful life of such equipment is generally greater than five years. To the extent that these policies are changed in a manner that reduces the incentives or the value of such incentives or reduces the capacity of potential investors to benefit from such incentives that benefit our projects, they could generate reduced revenues and reduced economic returns, experience increased financing costs and encounter difficulty obtaining financing. The current administration has made public statements and issued Executive Orders regarding overturning or modifying policies of or regulations enacted by the prior administration that placed limitations on coal and gas electric generation, mining and/or exploration. Any effort to overturn federal and state laws, regulations or policies that are supportive of solar energy generation or that remove costs or other limitations on other types of generation that compete with solar energy projects could materially and adversely affect our business.

Additionally, some U.S. states with RPS targets have met, or in the near future will meet, their renewable energy targets. For example, California, which has among the most aggressive RPS laws in the United States, is poised to meet its current mandate of 33% renewable energy by 2020 with already-proposed new renewable energy projects, though significant additional investments will be required to meet the higher 50% renewable energy mandate that was adopted in 2015. If, as a result of achieving these targets, these and other U.S. states do not increase their targets in the near future, demand for additional renewable energy could decrease. Any of the foregoing could have a material adverse effect on our ability to grow our business and make cash distributions to our Class A shareholders.

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Warranties provided by the suppliers of equipment for our assets and maintenance obligations of the operators of our assets may be limited by the ability of a supplier and/or operator to satisfy its warranty or performance obligations or by the expiration of applicable time or liability limits, which could reduce or void the warranty protections or maintenance obligations, or may be limited in scope or magnitude of liabilities, and thus the warranties and maintenance obligations may be inadequate to protect us.

Our Sponsors are a significant source of our warranty and maintenance coverage under a number of related party agreements, including EPC agreements, O&M agreements and warranty agreements, including product quality and performance warranties. Certain of these warranties are also provided by other sources, including the suppliers of equipment for our assets, among others. In the event that such warranty providers or operators, including our Sponsors, file for bankruptcy, cease operations or otherwise become unable or unwilling to fulfill their warranty obligations, we may not be adequately protected by such warranties. Even if such warranty providers or operators fulfill their obligations, the warranty or maintenance obligations may not be sufficient to protect us against losses. In addition, these warranties have a term of at least one year, in the case of certain system warranties provided by EPC providers, to 25 years, in the case of manufacturer module warranties, after the date each equipment item is delivered or commissioned. These warranties are subject to liability and other limits. If we seek warranty protection and a warranty provider is unable or unwilling to perform its warranty obligations, or if an operator is unable or unwilling to perform its maintenance obligations, whether as a result of its financial condition or otherwise, or if the term of the warranty or maintenance obligation has expired or a liability limit has been reached, there may be a reduction or loss of protection for the affected assets, which could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our Class A shareholders.

We are exposed to the credit risk of our Sponsors, and any deterioration of our Sponsors’ creditworthiness could adversely affect our business, our credit ratings and our overall risk profile.

We are subject to the credit risk of our Sponsors, and any downgrades or any material deterioration of our Sponsors’ creditworthiness could have significant negative consequences to our business or financial condition. For example: 

• due to increased borrowing costs or an inability to raise capital, which could limit our ability to pursue acquisitions from them, and either or both of the Sponsors may be unable or unwilling to develop additional solar energy projects;

• as a result of our relationship with our Sponsors, investors may lose confidence in our financial condition and our ability to make distributions to our Class A shareholders, and the trading price of our Class A shares may decline;

• either or both of our Sponsors may be unable or unwilling to fulfill their indemnity, reimbursement and other payment obligations under the Omnibus Agreement; and

• either or both of our Sponsors may be unable or unwilling to perform the services for which we have contracted with them under various O&M agreements, AMAs, warranties, guarantees and EPC agreements, and we may be unable to secure adequate replacement arrangements.

In the event that either or both of our Sponsors file for bankruptcy, cease operations or otherwise become unable or unwilling to fulfill their contractual obligations, including as described in the third and fourth subbullets above, we may not be adequately protected by such make-whole, indemnification and other such arrangements.

In addition, the credit and business risk profiles of our general partner and our Sponsors may be considered in credit evaluations of us because our general partner, which is owned by our Sponsors, controls our business activities, including our and OpCo’s cash distribution policy. Any adverse change in the financial condition of First Solar or SunPower, including the degree of its financial leverage and its dependence on cash flows from us to service its indebtedness, may adversely affect our credit ratings and risk profile. If we were to seek a credit rating, our credit rating may be adversely affected by the leverage of our general partner, First Solar or SunPower, as credit rating agencies such as Standard & Poor’s Ratings Services, Moody’s Investors Service and Fitch Ratings, Inc. may consider the leverage and credit profile of First Solar or SunPower because of their ownership interests in and control of us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

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We rely on interconnection and transmission facilities of third parties to deliver energy from our utility projects. If these facilities become unavailable, our projects may not be able to operate or deliver energy.

We depend on interconnection and transmission facilities owned and operated by third parties to deliver the energy from our utility projects. Many of the interconnection and transmission arrangements for the utility projects in our Portfolio are governed by separate agreements with the owners of the transmission or distribution system. Congestion, emergencies, maintenance, outages, overloads, requests by other parties for transmission service and other events beyond our control could partially or completely curtail deliveries of energy by our utility projects and increase project costs. In addition, any termination of a utility project’s interconnection or transmission arrangements or non-compliance by an interconnection provider or another third party with its obligations under an interconnection or transmission arrangement may delay or prevent our projects from delivering energy to our contractual counterparties. If the interconnection or transmission arrangement for a utility project is terminated, we may not be able to replace it on similar terms to the existing arrangement, or at all, or we may experience significant delays or costs in connection with such replacement. Moreover, if we acquire any utility projects that are under construction or development, a failure or delay in the construction or development of interconnection or transmission facilities could delay the completion of the project. The unavailability of interconnection or transmission could adversely affect the operation of our utility projects and the revenues received, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

The development of utility-scale solar energy projects by our Sponsors and third parties face risks related to project siting, financing, construction, permitting, the environment, governmental approvals and the negotiation of project development agreements.

Utility-scale project development is a capital intensive business that relies heavily on the availability of debt and equity financing sources (including tax equity investments) to fund projected construction and other development-related capital expenditures. As a result, in order to successfully develop a utility-scale solar energy project, development companies, including our Sponsors, often require sufficient financing to complete the development phase of their projects. Any significant disruption in the credit and capital markets, the credit profile or financial condition of project development companies, including our Sponsors, or a significant increase in interest rates could make it difficult for development companies, including our Sponsors, to raise or access funds when needed to secure construction financing, which would limit a project developer’s ability to obtain financing to complete the construction of a utility-scale solar energy project we may seek to acquire. For example, the 2017 Tax Act, which was signed into law December 22, 2017, enacted major changes to the U.S. federal income tax laws, including a permanent reduction in the U.S. federal corporate income tax rate effective January 1, 2018. This reduction in the corporate income tax rate could diminish the capacity of potential investors to benefit from incentives and reduce the value of accelerated depreciation deductions. The availability of tax equity financing with respect to any future acquisitions by us may also be affected by other aspects of the 2017 Tax Act or other future tax law changes, potentially reducing the federal tax benefits of an investment in renewable energy assets to tax equity investors. Such a reduction of these tax benefits could cause a material adverse effect on the willingness of investors to provide tax equity financing.

Utility-scale project development also requires the successful negotiation and execution of a variety of project contracts, including contracts related to offtake, transmission (in the case of utility-scale solar energy projects), siting, land use and other arrangements with a variety of third parties. Failure to execute project contracts, or the lack of available economically attractive offtake agreements, would limit the ability of a project developer to complete development of a project, which would limit the projects available to us to acquire.

Project developers, including our Sponsors, develop, construct, manage, own and operate utility-scale solar energy generation and transmission facilities. A key component of their businesses is their ability to construct and operate generation and transmission facilities to meet customer needs. As part of these activities, project developers and EPC providers must periodically apply for licenses and permits from various regulatory authorities and abide by their respective conditions and requirements. If project developers and EPC providers, including our Sponsors, are unsuccessful in obtaining necessary licenses or permits on acceptable terms or encounter delays in obtaining or renewing such licenses or permits, or if regulatory authorities initiate any associated investigations or enforcement actions or impose penalties or reject projects, the potential number of solar energy projects that may be available for us to acquire may be reduced or potential transaction opportunities may be delayed.

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If we choose to acquire solar energy projects before COD in the future, we will be subject to risks associated with the acquisition of solar energy projects that remain under construction, which could result in our inability to complete construction projects on time or at all, and make solar energy projects too expensive to complete or cause the return on an investment to be less than expected.

As part of our acquisition strategy or if we need to qualify for tax incentives, we may choose to acquire other solar energy projects that have not yet commenced operations and remain under construction. There may be delays or unexpected developments in completing any future construction projects, which could cause the construction costs of these projects to exceed our expectations, result in substantial delays or prevent the project from commencing commercial operation. Various factors could contribute to construction-cost overruns, construction halts or delays or failure to commence commercial operation, including:

• delays in obtaining, or the inability to obtain, necessary permits and licenses;

• delays and increased costs related to the interconnection of new projects to the transmission system;

• the inability to acquire or maintain land use and access rights;

• the failure to receive contracted third-party services;

• interruptions to dispatch at our projects;

• supply interruptions;

• work stoppages;

• labor disputes;

• weather interferences;

• force majeure events;

• changes in laws;

• unforeseen engineering, environmental and geological problems, including discoveries of contamination, protected plant or animal species or habitat, archaeological or cultural resources or other environment-related factors;

• unanticipated cost overruns in excess of budgeted contingencies; and

• failure of contracting parties to perform under contracts, including the EPC provider.

In addition, where we have a relationship with a third party to complete construction of any construction project, we are subject to the viability and performance of the third party. Our inability to find a replacement contracting party, where the original contracting party has failed to perform, could result in the abandonment of the construction of such project, while we could remain obligated under other agreements associated with the project, including offtake agreements, which may result in a default or termination of such offtake agreement.

Any of these risks could cause our financial returns on these investments to be lower than expected or otherwise delay or prevent the completion of such projects or distribution of cash to us, or could cause us to operate below expected capacity or availability levels, which could have a material adverse effect on our ability to grow our business and make cash distributions to our Class A shareholders.

Terrorist or similar attacks could impact our utility projects or surrounding areas and adversely affect our business.

Terrorists have attacked energy assets such as substations and related infrastructure in the past and may attack them in the future. Any attacks on our utility projects or the facilities of third parties on which our utility projects rely could severely damage such projects, disrupt business operations, result in loss of service to customers and require significant time and expense to repair. Additionally, energy-related facilities, such as substations and related infrastructure, are protected by limited security measures, in most cases only perimeter fencing. Cyber-attacks, including those targeting information systems or electronic control systems used to operate our utility projects and the facilities of third parties on which our utility projects rely could severely disrupt business operations, result in loss of service to customers and significant expense to repair security breaches or system damage. Our Portfolio, as well as projects we may acquire and the facilities of third parties on which our projects rely, may be targets of terrorist acts and affected by responses to terrorist acts, each of which could fully or partially

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disrupt our projects’ ability to produce, transmit, transport and distribute energy. A terrorist act or similar attack could significantly decrease revenues or result in significant reconstruction or remediation costs, any of which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

We are not able to insure against all potential risks and we may become subject to higher insurance premiums.

We are exposed to numerous risks inherent in the operation of solar energy projects, including equipment or system failure, manufacturing defects, natural disasters, terrorist attacks, sabotage, vandalism and environmental risks. The occurrence of any one of these events may result in substantial liability to us, including being named as a defendant in lawsuits asserting claims for environmental cleanup costs, personal injury, property damage, fines and penalties.

We currently maintain general liability insurance coverage for ourselves and our affiliates, which covers legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. Where we maintain majority ownership in a solar energy project, we also maintain coverage for ourselves and our affiliates for physical damage to assets and resulting business interruption. However, such policies do not cover all potential losses and coverage is not always available in the insurance market on commercially reasonable terms. In addition, the insurance proceeds received for any loss of, or any damage to, any of our assets may be immediately claimed by lenders under our financing arrangements or otherwise may not be sufficient to restore the loss or damage without a negative impact on our results of operations and our ability to make cash distributions to our Class A shareholders. To the extent we experience covered losses under our insurance policies, the limit of our coverage for potential losses may be decreased. Furthermore, the losses that are insured through commercial insurance are subject to the credit risk of those insurance companies. While we believe our commercial insurance providers are currently creditworthy, we cannot assure you that such insurance companies will remain so in the future.

We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. The insurance coverage we do obtain may contain large deductibles or fail to cover certain risks or all potential losses. In addition, our insurance policies are subject to annual review by our insurers and may not be renewed on similar or favorable terms, including coverage, deductibles or premiums, or at all. If a significant accident or event occurs for which we are not fully insured or we suffer losses due to one or more of our insurance carriers defaulting on their obligations or contesting their coverage obligations, it could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

Our business is subject to liabilities and operating restrictions arising from environmental, health and safety laws and regulations.

Our projects are subject to numerous environmental, health and safety laws, regulations, guidelines, policies, directives, government approvals, permit requirements and other requirements governing or relating to, among other things:

• the protection of wildlife;

• the presence or discovery of archaeological, religious or cultural resources at or near our operations; and

• the protection of workers’ health and safety.

If our projects do not comply with such laws, regulations or requirements, we may be required to pay penalties or fines, or curtail or cease operations of the affected projects. Violations of environmental and other laws, regulations and permit requirements, including certain violations of laws protecting wetlands and threatened or endangered species, may also result in criminal sanctions or injunctions. In addition, our projects require various government approvals and permits. In some cases, these approvals and permits require periodic renewal and a subsequently-issued approval or permit may not be consistent with the approval or permit initially issued. We cannot predict whether all approvals or permits required for a given asset will be granted or whether the conditions associated with the approvals or permits will be achievable. The denial or loss of an approval or permit essential to an asset or the imposition of impractical conditions upon renewal could impair our ability to construct and/or operate an asset.

Our utility-scale solar energy projects also carry inherent environmental, health and safety risks, including the potential for related civil litigation, regulatory compliance, remediation orders, fines and other penalties. For instance, our projects could malfunction or experience other unplanned events resulting in personal injury, fines or property damage. Our projects may be constructed and operated on properties that have preexisting releases of hazardous substances or other preexisting environmental conditions that carry health and safety risks, including the potential for related civil litigation, regulatory

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compliance, remediation orders, fines and other penalties, regardless of whether we knew of or exacerbated the preexisting release or preexisting condition.

Additionally, we may be held liable for related investigatory costs, which are typically not limited by law or regulation, for any property where there has been a release or potential release of a hazardous substance, regardless of whether we knew of or caused the release or potential release. We could also be liable for other costs, including fines, personal injury or property damage or damage to natural resources. In addition, some environmental laws place a lien on a contaminated site in favor of the government as security for damages and costs it may incur for contamination and cleanup. Contained or uncontained hazardous substances on, under or near our projects, regardless of whether we own or lease the sited property, or the inability to remove or otherwise remediate such substances may restrict or eliminate our ability to operate our projects.

Our utility-scale solar energy projects are designed specifically for the landscape of each project site and cover a large area. As such, archaeological discoveries could occur at such projects at any time. Such discoveries could result in the restriction or elimination of our ability to operate our business at such project. Utility-scale projects and operations may cause impacts to certain landscape views, trails, or traditional cultural activities. Such impacts may trigger claims from citizens that our projects are infringing upon their legal rights or other claims, resulting in the restriction or elimination of our ability to operate our business at any project.

Environmental, health and safety laws and regulations have generally become more stringent over time, and we expect this trend to continue. Significant capital and operating costs may be incurred at any time to keep our projects in compliance with environmental, health and safety laws and regulations. If it is not economical to make those expenditures, or if we violate any of these laws and regulations, it may be necessary to retire projects or restrict or modify our operations, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

We are subject to risks associated with litigation or administrative proceedings that could materially impact our operations, including future proceedings related to projects we subsequently acquire.

We are subject to risks and costs, including potential negative publicity, associated with lawsuits or claims contesting the operation of our projects. The result and costs of defending any such lawsuit, regardless of the merits and eventual outcome, may be material. For example, individuals and interest groups may sue to challenge the issuance of a permit for a project or seek to enjoin a project’s operations. Any such legal proceedings or disputes could materially delay our ability to complete construction of a project in a timely manner or at all or materially increase the costs associated with commencing or continuing a project’s commercial operation. Settlement of claims and unfavorable outcomes or developments relating to these proceedings or disputes, such as judgments for monetary damages, injunctions or denial or revocation of permits, could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

Our projects may be adversely affected by legislative changes or a failure to comply with applicable energy regulations.

Certain of our Project Entities and offtake counterparties are subject to regulation by U.S. federal, state and local authorities. The wholesale sale of electric energy in the continental United States, other than certain areas in Texas, is subject to the jurisdiction of the FERC, and the ability of a Project Entity to charge the negotiated rates contained in its offtake agreement is subject to that project company’s maintenance of its general authorization from FERC to sell electricity at market-based rates or maintaining an exemption from such requirement. FERC may revoke a Project Entity’s market-based rate authorization if it determines that the Project Entity can exercise market power in transmission or generation, create barriers to entry or has engaged in abusive affiliate transactions. The negotiated rates entered into under the Project Entities’ offtake agreements could be changed by FERC if it determined such change is in the public interest. While this threshold public interest determination would require extraordinary circumstances under FERC precedent, if FERC decreases the prices paid to us for energy delivered under any of our offtake agreements, our revenues could be below our projections and our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders could be materially adversely affected.

Our Project Entities, with the exception of our DG Solar projects, are subject to the mandatory reliability standards of the NERC. The NERC reliability standards are a series of requirements that relate to maintaining the reliability of the North American bulk electric system and cover a wide variety of topics including physical and cybersecurity of critical assets, information protocols, frequency and voltage standards, testing, documentation and outage management. If we fail to comply with these standards, we could be subject to sanctions, including substantial monetary penalties. Although our Utility Project Entities are not subject to state utility rate regulation because they sell energy exclusively on a wholesale basis, we are subject to other state regulations that may affect our projects’ sale of energy and operations. Changes in state regulatory treatment are

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unpredictable and could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

With few material federal regulatory policies driving the growth of renewable energy, each U.S. state has its own renewable energy regulations and policies. Renewable energy developers must anticipate the future policy direction in each state and province and secure viable projects before they can bid to procure an offtake agreement or other contract through often highly competitive auctions. A failure to anticipate accurately the future policy direction in a jurisdiction or to secure viable projects could have a material adverse effect on our ability to grow our business and make cash distributions to our Class A shareholders.

The structure of the industry and regulation in the United States is currently, and may continue to be, subject to challenges and restructuring proposals. Additional regulatory approvals may be required due to changes in law or for other reasons. We expect the laws and regulation applicable to our business and the energy industry generally to be in a state of transition for the foreseeable future. Changes in such laws and regulations could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

Our DG Solar business depends in part on the regulatory treatment of third-party owned solar power systems.

Although we own the underlying solar power systems of our DG Solar projects, because we lease such systems to our residential DG Solar customers, their DG Solar offtake agreements are considered third-party ownership arrangements. Therefore, DG Solar customers are considered non-owner third parties. Sales of electricity by third parties face regulatory challenges in some U.S. states and jurisdictions. Other challenges pertain to whether third-party owned solar power systems qualify for the same levels of rebates, tax exemptions or other non-tax incentives available for customer-owned solar power systems and whether third-party owned solar power systems are eligible at all for these incentives. Reductions in, or eliminations of, rebates or incentives for these third-party ownership arrangements could reduce demand for our solar power systems, adversely impact our access to capital and could cause us to increase the price we charge our customers for energy.

A failure to comply with laws and regulations relating to our interactions with current or prospective residential customers could result in negative publicity, claims, investigations, and litigation, and adversely affect our financial performance.

A segment of our business focuses on transactions with residential customers. We must comply with numerous federal, state and local laws and regulations that govern matters relating to our interactions with residential consumers, including those pertaining to privacy and data security, consumer financial and credit transactions, home improvement contracts, warranties and door-to-door solicitation. These laws and regulations are dynamic and subject to potentially differing interpretations, and various federal, state and local legislative and regulatory bodies may expand current laws or regulations, or enact new laws and regulations, regarding these matters. Changes in these laws or regulations or their interpretation could dramatically affect how we do business, acquire customers, and manage and use information we collect from and about current and prospective customers and the costs associated therewith. We strive to comply with all applicable laws and regulations relating to our interactions with residential customers. It is possible, however, that these requirements may be interpreted and applied in a manner that is inconsistent from one jurisdiction to another and may conflict with other rules or our practices. Our non-compliance with any such law or regulations could also expose the company to claims, proceedings, litigation and investigations by private parties and regulatory authorities, as well as substantial fines and negative publicity, each of which may materially and adversely affect our business. We have incurred, and will continue to incur, significant expenses to comply with such laws and regulations, and increased regulation of matters relating to our interactions with residential consumers could require us to modify our operations and incur significant additional expenses, which could have an adverse effect on our business, financial condition and results of operations.

In addition, we are subject to federal, state and international laws relating to the collection, use, retention, security and transfer of personal information of our customers. In many cases, these laws apply not only to third-party transactions, but also to transfers of information between one company and its subsidiaries, and among the subsidiaries and other parties with which we have commercial relations. Several jurisdictions have passed new laws in this area, and other jurisdictions are considering imposing additional restrictions. These laws continue to develop and may be inconsistent from jurisdiction to jurisdiction. Complying with emerging and changing requirements may cause us to incur costs or require us to change our business practices. A failure by us, our suppliers or other parties with whom we do business to comply with a posted privacy policies or with other federal, state or international privacy-related or data protection laws and regulations could result in proceedings against us by governmental entities or others, which could have a detrimental effect on our business, results of operations and financial condition.

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We could be adversely affected by any violations of the U.S. Foreign Corrupt Practices Act and foreign anti-bribery laws.

The U.S. Foreign Corrupt Practices Act generally prohibits companies and their intermediaries from making improper payments to non-U.S. government officials for the purpose of obtaining or retaining business. We have implemented policies mandating compliance with these anti-bribery laws. We currently only operate in the United States. However, we may acquire businesses outside of the United States and operate in parts of the world that have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices. In addition, due to the level of regulation in our industry, our entry into new jurisdictions through acquisitions requires substantial government contact where norms can differ from U.S. standards. While we have implemented policies and procedures and conduct training designed to facilitate compliance with these anti-bribery laws, thereby mitigating the risk of violations of such laws, the employees of our Sponsors, subcontractors and agents may take actions in violation of our policies and anti-bribery laws. Any such violation, even if prohibited by our policies, could subject us to criminal or civil penalties or other sanctions, which could have a material adverse effect on our business, financial condition, cash flows and reputation.

We may not be able to extend, renew or replace expiring or terminated offtake agreements at favorable rates or on a long-term basis.

As of November 30, 2017, the weighted average remaining life of offtake agreements across our Portfolio was 19.1 years. Our ability to extend, renew or replace our existing offtake agreements depends on a number of factors beyond our control, including:

• whether the offtake counterparty has a continued need for energy at the time of expiration, which could be affected by, among other things, the presence or absence of governmental incentives or mandates, prevailing market prices and the availability of other energy sources;

• the satisfactory performance of our delivery obligations under such offtake agreements;

• the regulatory environment applicable to our offtake counterparties at the time;

• macroeconomic factors present at the time, such as population, business trends and related energy demand; and

• the effects of regulation on the contracting practices of our offtake counterparties.

If we are not able to extend, renew or replace on acceptable terms existing utility offtake agreements before contract expiration, or if such agreements are otherwise terminated in accordance with their terms prior to their expiration, we may be forced to sell the energy on an uncontracted basis at prevailing market prices, which could be materially lower than we received under the offtake agreement. Alternatively, if there is no market for a project’s uncontracted energy or we lose access to or the right to occupy and use the land on which a project sits, we may be required to decommission the project before the end of its useful life. Additionally, if we are not able to extend or renew our DG Solar offtake agreements before contract expiration, or if such agreements are otherwise terminated in accordance with their terms prior to expiration, we will lose all revenue with respect to such projects. Any failure to extend or replace a significant portion of our existing offtake agreements, or extending, renewing or replacing them at lower prices or with other unfavorable terms could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

Certain of the offtake agreements in our Portfolio and offtake agreements that we may enter into in the future contain or may contain provisions that allow the offtake counterparty to terminate the agreement or buyout all or a portion of the asset upon the occurrence of certain events. If these provisions are exercised and we are unable to enter into an offtake agreement on similar terms, in the case of a termination, or find suitable replacement assets to invest in, in the case of a buyout, our cash available for distribution could materially decline.

Certain of the offtake agreements in our Portfolio and offtake agreements that we may enter into in the future allow or may allow the offtake counterparty to purchase all or a portion of the applicable asset from us. For example, pursuant to the offtake agreements for several of our solar assets, the offtake counterparty has the option to either (i) purchase the applicable solar power system, no earlier than year six after COD of the system, and for a purchase price equal to the greater of a value specified in the contact or the fair market value of the asset determined at the time of exercise of the purchase option or (ii) pay an early termination fee as specified in the contract, terminate the contact and require the project company owned by us to remove the applicable solar power system from the site. If the offtake counterparty of the asset exercises its right to purchase the asset or terminate the offtake agreement, we would need to reinvest the proceeds from the sale or termination payment in one or more assets with similar economic attributes to maintain our cash available for distribution. If we were unable to locate

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and acquire suitable replacement assets in a timely manner, it could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our Class A shareholders.

In addition, some of the offtake agreements in our Portfolio and offtake agreements we may enter into in the future allow or may allow the offtake counterparty to terminate the offtake agreement in the event certain operating thresholds or performance measures are not achieved within specified time periods. In the event an offtake agreement for one or more of our assets is terminated under such provisions, it could materially and adversely affect our results of operations and cash available for distribution until we are able to replace the offtake agreement on similar terms. We cannot provide any assurance that offtake agreements containing such provisions will not be terminated or, in the event of termination, we will be able to enter into a replacement offtake agreement. Furthermore, any replacement offtake agreement may be on terms less favorable to us than the offtake agreement that was terminated.

A material drop in the price and or increase in the availability of other energy sources would harm our ability to acquire accretive utility projects.

A utility’s decision to buy renewable energy may be affected by the cost of other energy sources, including nuclear, coal, natural gas and oil, as well as other sources of renewable energy. For example, low natural gas prices have led, in some instances, to increased natural gas consumption in lieu of other energy sources. To the extent renewable energy, particularly solar energy, becomes less cost-competitive due to reduced government targets and incentives that favor renewable energy, cheaper alternatives or otherwise, demand for solar energy and other forms of renewable energy could decrease. Slow growth or a long-term reduction in the energy demand could cause a reduction in the development of utility-scale solar energy projects.

The price of electricity from utilities could also decrease as a result of:

• the construction of additional electric transmission and distribution lines;

• a reduction in the price of natural gas as a result of new drilling techniques, oversupply of natural gas or a relaxation of associated regulatory standards;

• governmental subsidies or policies benefiting non-renewable energy sources;

• the energy conservation technologies and public initiatives to reduce electricity consumption; and

• development of new renewable energy technologies that provide less expensive energy.

Decreases in the prices of electricity from the utilities could affect our ability to acquire accretive assets, as our Sponsors and other renewable energy developers may not be able to compete with providers of other energy sources at such lower utility wholesale prices. Our inability to acquire accretive assets could have a material adverse effect on our ability to grow our business and make cash distributions to our Class A shareholders.

A material drop in the price of retail electricity from utilities would harm our ability to acquire accretive C&I and residential assets.

A reduction in utility electricity prices would make the purchase of solar power systems or the purchase of energy under offtake agreements less economically attractive to residential and C&I customers. In addition, a shift in the timing of peak rates for utility-generated electricity to a time of day when solar energy generation is less efficient could make solar power system offerings less competitive and reduce demand for such solar power systems. If the price of energy available from utilities were to decrease due to any of these reasons, or otherwise, we would be unable to acquire accretive DG Solar assets, which could have a material adverse effect on our ability to grow our business and make distributions to our Class A shareholders.

The C&I market for energy is particularly sensitive to price changes. Typically, C&I customers pay less for energy from utilities than residential customers. Because the price we are able to charge C&I customers is only slightly lower than their current retail rate, any decline in the retail rate of energy for C&I entities could have a significant impact on the development of the C&I market due to the inability to attract additional C&I customers.

If the price of energy available from utilities were to decrease due to any of these reasons, or others, we would be unable to acquire accretive residential and C&I assets, which could have a material adverse effect on our ability to grow our business and make distributions to our Class A shareholders.

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We generally do not own any of the land on which the projects in our Portfolio are located and our use and enjoyment of the property may be adversely affected to the extent that there are any interest owners, lienholders or leaseholders that have rights that are superior to our rights.

We generally do not own any of the land on which the projects in our Portfolio are located and they generally are, and our future projects may be, located on land occupied under long-term easements, leases, licenses and rights of way. The fee ownership interests in the land subject to these easements, leases, licenses and rights of way may be subject to mortgages securing loans or other liens and other easements, lease rights, licenses and rights of way of third parties that were created prior to, or which are otherwise superior to, our projects’ easements, leases and rights of way. As a result, some of our projects’ rights under such easements, leases, licenses or rights of way may be subject to the rights of these third parties. While we generally perform title searches and obtain title insurance (except for the Kern Project, the Macy’s California Project and the Macy’s Maryland Project or where title insurance is commercially unobtainable), record our interests in the real property records of the projects’ localities and enter into non-disturbance agreements (when appropriate) to protect ourselves against such risks, such measures may be inadequate to protect against all risk that our rights to use the land on which our projects are or will be located and our projects’ rights to such easements, leases, licenses and rights of way could be lost, interrupted or curtailed. Any such loss, interruption or curtailment of our rights to use the land on which our projects are or will be located could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

Information technology system failures, or network disruptions and security breaches, including cybersecurity breaches, could damage our business operations, financial conditions, or reputation.

The secure maintenance of information and information technology systems is critical to our business operations. We may be subject to information technology system failures and network disruptions. These may be caused by natural disasters, accidents, power disruptions, telecommunications failures, acts of terrorism or war, computer viruses, physical or electronic break-ins, or similar events or disruptions. System redundancy may be ineffective or inadequate, and our disaster recovery planning may not be sufficient for all eventualities. System failures and disruptions could impede transactions processing and financial reporting.

In addition, our infrastructure may be increasingly vulnerable to attacks by hackers or terrorists as a result of the rise in the sophistication and volume of cyberattacks. Any such cyberattack or breach could: (i) compromise our projects thereby adversely affecting generation and transmission to the grid; (ii) adversely affect our business operations; (iii) corrupt data; or (iv) result in unauthorized access to the information stored on our networks, including, company proprietary information and employee data causing the information to be publicly disclosed, lost or stolen or result in incidents that could result in harmful effects on the environment and human health, including loss of life. Any such attack, breach, access, disclosure or other loss of information could result in lost revenue, the inability to conduct critical business functions, legal claims or proceedings, regulatory penalties, increased regulation, increased protection costs for enhanced cyber security systems or personnel, damage to our reputation and the rendering of our disclosure controls and procedures ineffective, all of which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

In addition, our directors and officers may be subject to class action lawsuits relating to the Mergers, and other additional lawsuits that may be filed. Such litigation is common in connection with acquisitions of public companies, regardless of any merits related to the underlying acquisition. For more information about the risks associated with potential lawsuits, please read Part I, Item 1A. “Risk Factors—Risks Related to Our Merger with Capital Dynamics—We may be subject to class action lawsuits relating to the Mergers, which could materially adversely affect our business, financial condition and operating results or prevent or delay completion of the Mergers.”

If solar energy technology is not suitable for widespread adoption at economically attractive rates of return, or if sufficient additional demand for solar power systems does not develop or takes longer to develop than we anticipate, our ability to acquire accretive projects may decrease.

The solar energy market is at a relatively early stage of development, in comparison to fossil fuel-based electricity generation. If solar energy technology proves unsuitable for widespread adoption at economically attractive rates of return or if additional demand for solar power systems fails to develop sufficiently or takes longer to develop than we anticipate, we may be unable to acquire additional accretive projects to grow our business. In addition, demand for solar power systems in our targeted markets may develop to a lesser extent than we anticipate. Many factors may affect the viability of widespread adoption of solar energy technology and demand for solar power systems, including the following:

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• availability, substance and magnitude of support programs including government targets, subsidies, incentives, renewable portfolio standards and residential net ownership rules to accelerate the development of the solar energy industry;

• fluctuations in economic and market conditions that affect the price of, and demand for, conventional and non-solar renewable energy sources, such as increases or decreases in the price of natural gas, coal, oil and other fossil fuels and the cost-effectiveness of the electricity generated by solar power systems compared to such sources and other non-solar renewable energy sources, such as wind;

• changes to government regulations and policies may present technical, regulatory, and economic barriers to the purchase and use of solar power products;

• performance, reliability and availability of energy generated by solar power systems compared to conventional and other non-solar renewable energy sources and products;

• competitiveness of other renewable energy generation technologies, such as hydroelectric, tidal, wind, geothermal, solar thermal, concentrated solar and biomass;

• fluctuations in capital expenditures by end-users of solar power systems which tend to decrease when the economy slows and when interest rates increase; and

• availability of certain solar technology and suitability for widespread adoption at economically attractive rates of return or if additional demand for solar technology fails to develop sufficiently or takes longer to develop than we anticipate.

Solar energy failing to achieve or being significantly delayed in achieving widespread adoption could have a material adverse effect on our ability to grow our business and make cash distributions to our Class A shareholders.

Our Residential Portfolio and certain of our C&I solar energy projects rely on net metering and other policies to offer competitive pricing to our customers in some of our key markets and to facilitate interconnection of new customers.

Most U.S. states, along with Washington, D.C., American Samoa, U.S. Virgin Islands and Puerto Rico, have a regulatory policy known as net energy metering, or net metering. Most of the states where we currently serve customers have adopted a net metering policy. Net metering allows our customers who own grid-connected DG Solar assets to pay the utility only for electricity used net of electricity generated by their solar system. At the end of the billing period, the customer simply pays for the net energy used or receives a credit at the retail rate if more energy is produced than consumed. Utilities that are not subject to a net metering policy typically compensate customers for solar electricity that is exported to the grid at a price lower than the retail price, usually a fixed rate or an “avoided cost” rate that is a proxy for the wholesale price of electricity.

Net metering policies have received recent scrutiny from legislatures and regulators. Some states, including but not limited to Arizona and Hawaii, have ended net metering on a prospective basis, grandfathering in existing residential customers for a set period of time. New York has replaced net metering on a prospective basis (subject to grandfathering for residential and certain commercial customers for a set period of time) with a “value of solar” tariff that values excess energy produced by a distributed generation system based on certain attributes, instead of at the retail rate. California has retained net metering for customers served by investor-owned utilities, but permits those utilities to impose certain additional charges. Our Residential Portfolio and certain of our C&I solar energy projects may be adversely impacted by the elimination of net metering where it is currently in place, the failure to adopt a net metering policy where it currently is not in place, the failure to expand caps on the availability of net metering to new customers in states that have implemented them, or reductions in the amount or value of credit that customers receive through net metering.

In addition, our Residential Portfolio and certain of our C&I solar energy projects may be adversely impacted by the unavailability of expedited or simplified interconnection for grid-tied solar power systems, delays in interconnection or any limitation on the number of customer interconnections or amount of solar energy that utilities are required to allow in their service territory or some part of the grid.

Utilities in some states, including (but not limited to) Arizona, California and Hawaii, have also adopted or proposed new rates or charges that only or disproportionately impact customers that install distributed generation systems or utilize net metering. For example, utilities in some states have proposed or received approval for imposing additional interconnection or monthly charges on customers who interconnect solar power systems installed on their homes or requiring those customers to receive service under “time of use” rates that provide for different rates during different periods of the day and that could result in a reduction in the amount or value of credits. If such rates or charges are imposed, the cost savings associated with solar

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energy for current and prospective customers may be significantly reduced and our ability to expand our Residential Portfolio and compete with traditional utility providers could be impacted.

Limits on net metering, interconnection of solar power systems and other operational policies in key markets could limit the number of solar power systems installed in those markets. If net metering is eliminated or replaced, if caps on net metering are reached, if the amount or value of credit that customers receive for net metering is significantly reduced, or if the utility imposes new rates or changes impacting customers who install distributed generation systems or utilize net metering, current or future customers will be unable to recognize the current cost savings associated with solar energy and net metering. Net metering is used to establish competitive pricing for prospective customers and the absence of net metering and other favorable policies for new customers would impair our ability to compete with utilities and other electricity providers and greatly limit demand for residential solar power systems.

Until we can effectively utilize tax benefits, we expect to be dependent on the availability of third-party tax equity financing arrangements, which may not be available in the future.

A goal of developers and owners of renewable energy assets, including our Sponsors, is to utilize the tax benefits produced by these projects. However, we cannot effectively utilize those benefits currently and may not be able to utilize them in the future. As such, we may acquire projects in the future that include third-party tax equity financing to utilize tax benefits available to certain renewable energy assets. However, no assurance can be given that tax equity investors will be available or willing to invest on acceptable terms at the time of any such acquisition or that the tax incentives and benefits that are needed to make tax equity financing available will remain in place. Tax equity investors have invested in and provided a significant amount of the permanent capital needed for the U.S. assets in our Portfolio and we expect to have similar arrangements for assets we acquire in the future, including any of the SunPower ROFO Projects. In a typical tax equity financing, a tax equity investor makes a capital investment in a class of equity interests of the entity that directly or indirectly owns the physical asset or assets. However, the availability of tax equity financing depends on federal tax incentives that encourage renewable energy development. These incentives primarily include (i) ITCs, which are federal income tax credits equal to (a) 30% multiplied by the basis of eligible assets that commence construction prior to January 1, 2020 and are placed in service before January 1, 2024; (b) 26% multiplied by the basis of eligible assets that commence construction during 2020 and are placed in service before January 1, 2024; (c) 22% multiplied by the basis of eligible assets that commence construction during 2021 and are placed in service before January 1, 2024; and (d) 10% multiplied by the basis of eligible assets that commence construction in 2022 or thereafter or are placed in service on or after January 1, 2024 and (ii) accelerated depreciation of renewable energy assets as calculated under the current tax depreciation system, the modified accelerated cost recovery system of the U.S. Internal Revenue Code of 1986, as amended (the “Code”). No assurance can be given that the federal government will maintain these incentive programs. The reduction or loss of these tax benefits could cause a material adverse effect on the willingness of investors to provide tax equity financing for a portion of the acquisition price of U.S. renewable energy assets, which in turn could impact our ability to make future acquisitions. The 2017 Tax Act, which was signed into law December 22, 2017, enacted major changes to the U.S. federal income tax laws, including a permanent reduction in the U.S. federal corporate income tax rate effective January 1, 2018. This reduction in the corporate income tax rate could diminish the capacity of potential investors to benefit from incentives and reduce the value of accelerated depreciation deductions. The availability of tax equity financing with respect to any future acquisitions by us may also be affected by other aspects of the 2017 Tax Act or other future tax law changes, potentially reducing the federal tax benefits of an investment in renewable energy assets to tax equity investors. Such a reduction of these tax benefits could cause a material adverse effect on the willingness of investors to provide tax equity financing.

Certain of our tax equity financing agreements provide, and tax equity financing arrangements of our future acquisitions may provide, our tax equity investors with a number of minority investor protection rights with respect to the applicable asset or assets that have been financed with tax equity, including restricting the ability of the entity that owns such asset or assets to incur debt. To the extent we want to incur project-level debt at a project in which we co-invest with a tax equity investor, we may be required to obtain the tax equity investor’s consent prior to such incurrence. In addition, the amount of debt that could be incurred by an entity in which we have a tax equity co-investor may be further constrained because even if the tax equity investor consents to the incurrence of the debt at the entity or project level, the tax equity investor may not agree to pledge its interest in the project which could reduce the amount that can be borrowed by the entity.

Further, there are a limited number of potential tax equity investors. Such investors have limited funds and renewable energy developers, operators and investors compete against one another and with others for tax equity financing for their capital. Our business strategy depends on the acquisition of additional assets to be able to meet our expected distribution rate. The inability of developers of renewable energy assets to enter into tax equity financing agreements with attractive pricing terms, or at all, could limit our ability to acquire additional assets and have a material adverse effect on our business, financial

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condition, results of operations and cash flows. Furthermore, as the renewable energy industry expands, the cost of tax equity financing may increase and there may not be sufficient tax equity financing available to meet the total demand in any year.

While we currently own only solar energy projects, we may acquire other sources of clean energy and other assets. Any future acquisition of non-renewable energy projects may present unforeseen challenges and result in a competitive disadvantage relative to our more-established competitors.

While we currently only own solar assets, we may in the future choose to acquire other sources of clean energy and other assets, including contracted wind and natural gas, and other types of projects, including land and transmission projects. We may also choose to leverage advancements in technology such as energy storage and increasingly efficient modules to compete against existing renewable generation technologies. We may be unable to identify attractive acquisition opportunities or acquire such projects or technology at a price and on terms that are attractive. In addition, expanding beyond our current expertise may result in our Sponsors not having the level of experience, technical expertise, human resources management and other attributes necessary to operate such assets optimally, which could expose us to increased operating costs, unforeseen liabilities or risks including regulatory and environmental issues associated with entering new sectors of the energy industry, including requiring a disproportionate amount of our management’s attention and resources, which could have an adverse impact on our business and place us at a competitive disadvantage relative to more established market participants. A failure to successfully integrate such acquisitions with our then-existing projects as a result of unforeseen operational difficulties or otherwise, could have a material adverse effect on our ability to grow our business and make cash distributions to our Class A shareholders.

Risks Related to Our Relationship with Our Sponsors

Since the economic and management rights of First Solar and SunPower are impacted by the performance of our business in different ways, First Solar and SunPower may fail to agree on our management, which could adversely affect our ability to execute our business plan.

Until November 30, 2019, our Sponsors each own (i) 50% of the economic interests of Holdings, which represent the incentive distribution rights, and (ii) 50% of the management interests of Holdings, which represent the right to govern Holdings and the General Partner. In addition, each of our Sponsors has certain rights to appoint the directors of the General Partner and to nominate the officers of the General Partner for approval by the board of the General Partner. Beginning after November 30, 2019, the economic interests of our Sponsors are subject to adjustment annually based on the relative performance of each Sponsor’s contributed Project Entities and any additional assets contributed to OpCo by such Sponsor against the performance of all Project Entities held by OpCo. If, after the adjustment to a Sponsor’s economic interests, such Sponsor has held at least 70% of the economic interests for at least two consecutive fiscal years, then such Sponsor shall have the option to require the other Sponsor to transfer part of its management interest to such Sponsor, thereby effectively giving such Sponsor management control. In addition, after November 30, 2019, payments on the economic interests of Holdings to our Sponsors are subject to an annual reallocation among the Sponsors based on the relative performance of the assets contributed by each Sponsor compared to the projected performance of such assets at the time of contribution. Each Sponsor can also lose its right to appoint directors and officers of the General Partner in the event such Sponsor (i) holds less than 40% of the economic interests for the three previous fiscal years or (ii) if, in each of such three fiscal years, the cash generated and distributed, subject to certain exclusions, by one Sponsor’s contributed Project Entities and any additional assets contributed by such Sponsor to OpCo prior to the end of the most recent fiscal year is less than 40% of the cash generated and distributed, subject to certain exclusions, by both Sponsors’ contributed Project Entities and any additional assets contributed by both Sponsors to OpCo prior to the end of the most recent fiscal year. In addition, in the event our Sponsors cannot agree on a management decision after a required negotiation period, either Sponsor can initiate a process that will result in the purchase by one Sponsor of the other Sponsor’s interests in Holdings or a sale to a third party. A shift in control to one of our Sponsors could result in significant changes to our business plan, results of operations and financial condition.

While these provisions are intended to incentivize our Sponsors to contribute high-performing assets to us, they also cause our Sponsors to have differently aligned interests in us, which could cause them to disagree on certain management decisions, including the timing, selection, cost and financing of acquisitions. While our Sponsors are under no obligation to provide us additional acquisition opportunities, we expect our Sponsors will be our primary source for the acquisition of additional solar energy projects in the future. If our Sponsors do not agree on their management of us, one or both of them may choose not to offer us additional future solar energy projects which could have a material adverse effect on our ability to grow our business and make distributions to our Class A shareholders.

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The General Partner and its affiliates, including our Sponsors, have conflicts of interest with us and limited duties to us and our Class A shareholders, and they may favor their own interests to the detriment of us and our Class A shareholders.

Our Sponsors indirectly own and control the General Partner and appoint all of the General Partner’s officers and directors. All of the General Partner’s executive officers and a majority of the General Partner’s directors also are employees of our Sponsors. Conflicts of interest exist and may arise as a result of the relationships between the General Partner and its affiliates, including our Sponsors, on the one hand, and us and our shareholders, on the other hand. Although the General Partner has a duty to manage us in a manner beneficial to us and our shareholders, the General Partner’s directors and officers have fiduciary duties to manage the General Partner in a manner beneficial to its owner, Holdings, which is owned by our Sponsors. In addition, under the MSAs, First Solar and SunPower each provide certain services or arrange for certain services to be provided to us, including with respect to carrying out our day-to-day management and providing individuals to act as the General Partner’s executive officers. These same executive officers may help the Board evaluate potential acquisition opportunities presented by First Solar under the First Solar ROFO Agreement and SunPower under the SunPower ROFO Agreement.

In resolving such conflicts of interest, the General Partner may favor its own interests and the interests of its affiliates, including our Sponsors, over the interests of our shareholders. These conflicts include the following situations, among others:

• none of our Partnership Agreement, the MSAs or any other agreement requires First Solar, SunPower or their affiliates to pursue a business strategy that favors us or dictates what markets to pursue or grow. First Solar’s and SunPower’s directors and officers have a fiduciary duty to make these decisions in the best interests of First Solar and SunPower, respectively, which may be contrary to our interests;

• contracts between us, on the one hand, and the General Partner and its affiliates, on the other, are not and may not be the result of arm’s-length negotiations;

• the General Partner’s affiliates are not limited in their ability to compete with us and neither the General Partner nor its affiliates have any obligation to present business opportunities to us except for the SunPower ROFO Projects if SunPower decides to sell such project during the term of the SunPower ROFO Agreement;

• the General Partner is allowed to take into account the interests of parties other than us, such as First Solar and SunPower, in resolving conflicts of interest;

• we do not have any officers or employees and rely solely on officers and employees of the General Partner and its affiliates, including First Solar and SunPower. The officers of the General Partner will also devote significant time to the business of First Solar and SunPower and will be compensated by First Solar and SunPower accordingly, as applicable;

• our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by the General Partner with contractual standards governing its duties and limits the General Partner’s liabilities and the remedies available to our shareholders for actions that, without these limitations, might constitute breaches of fiduciary duty under applicable Delaware law;

• except in limited circumstances, the General Partner has the power and authority to conduct our business without shareholder approval;

• actions taken by the General Partner may affect the amount of cash available to pay distributions to our Class A shareholders;

• the General Partner determines which costs incurred by it are reimbursable by us;

• we reimburse the General Partner and its affiliates for expenses;

• the General Partner intends to limit its liability regarding our contractual and other obligations;

• our Class A shares are subject to the General Partner’s limited call right;

• the General Partner controls the enforcement of the obligations that it and its affiliates owe to us, including SunPower’s obligations under the SunPower ROFO Agreement and our Sponsors’ other commercial agreements with us; and

• we may choose not to retain counsel, independent accountants or other advisors separate from those retained by the General Partner to perform services for us or for the holders of our Class A shares.

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A decision by the General Partner to favor its own interests and the interests of our Sponsors over our interests and the interests of our shareholders could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

Our Sponsors and other affiliates of the General Partner are not restricted in their ability to compete with us.

Our Partnership Agreement provides that the General Partner is restricted from engaging in any business activities other than acting as the General Partner and those activities incidental to its ownership of interests in us. Affiliates of the General Partner, including our Sponsors and their subsidiaries, are not prohibited, including under the MSAs, from owning solar energy projects or engaging in businesses that compete directly or indirectly with us. Our Sponsors currently hold interests in, and may make investments in and purchases of, entities that acquire, own and operate other power generators. Our Sponsors will be under no obligation to make any acquisition opportunities available to OpCo, other than under the SunPower ROFO Agreement.

Under the terms of our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to the General Partner or any of its affiliates, including its executive officers and directors and our Sponsors. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of the General Partner and result in less than favorable treatment of us and holders of our Class A shares.

If our Sponsors terminate their respective services agreements or other arrangements with us or our subsidiaries, or either of them defaults in the performance of its obligations thereunder, we may be unable to contract with a substitute service provider on similar terms, or at all, and may not get the expected benefit of such other arrangements.

We rely on our Sponsors to provide us with administrative and management services under the MSAs and do not have independent executive or senior management personnel. Under these agreements, certain of our Sponsors’ employees provide services to us. These services are not the primary responsibility of these employees, nor are these employees required to act for us alone. The MSAs do not require our Sponsors to engage any specific individuals for purposes of providing services to us and our Sponsors have the discretion to determine which of their respective employees will perform the services required to be provided to us. Each of the MSAs provides that First Solar and SunPower, respectively, may terminate the applicable agreement (i) upon 30 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 to First Solar, SunPower or any of their respective affiliates (other than our subsidiaries and us), and the default continues unremedied for a period of 60 days after written notice of the breach is given to us, (ii) upon the happening of certain events relating to the bankruptcy or insolvency of Holdings, the General Partner, OpCo, us or certain OpCo’s subsidiaries, or (iii) if First Solar and SunPower and their respective affiliates (other than our subsidiaries and us) cease to control us. If either First Solar or SunPower terminates its MSA or if either of them defaults in the performance of its obligations thereunder, 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, our Sponsors are familiar with our projects and, as a result, our Sponsors have certain synergies with us. Substitute service providers would lack such synergies and may not be able to provide the same level of service to us. If we cannot locate a service provider that is able to provide us with substantially similar services as our Sponsors provide under the MSAs on similar terms, it would likely have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

In addition, we depend on our Sponsors to provide a substantial portion of the services required for the operation and maintenance and the administration and management of our projects. Our Sponsors may not perform their services as, when and where required. Additionally, in the event that our Sponsors have a dispute, they have agreed to a resolution provision that could ultimately eliminate the ownership of one or both of our Sponsors, allowing such Sponsor(s) to terminate any agreements under which they provide operation and maintenance or administration and management services to us. To the extent that First Solar or SunPower do not fulfill their obligations to manage operations of our projects, are not effective in doing so or terminate the agreements governing such services, we may not be able to enter into replacement agreements on favorable terms, or at all. If we are unable to enter into long-term replacement agreements to provide for operation and maintenance and the administration and management of our projects and other required services, we would seek to purchase the related services under short-term agreements, exposing us to market price volatility. In addition, if our Sponsors fail to comply with their indemnification obligations related to tax equity financing arrangements for our current or future projects, we may be required to make payments thereunder, and such payments may be substantial. The failure of First Solar or SunPower to fulfill its

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obligations could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our Class A shareholders.

Our arrangements with our Sponsors limit their liability, and we have agreed to indemnify our Sponsors against claims that they may face in connection with such arrangements, which may lead our Sponsors to assume greater risks when making decisions relating to us than they otherwise would if acting solely for their own account.

Under the MSAs, our Sponsors and their affiliates have not assumed any responsibility other than to provide or arrange for the provision of the services described in the applicable MSA in good faith. Additionally, under the MSAs, the liability of our Sponsors and their affiliates is limited to the fullest extent permitted by law to conduct involving bad faith, fraud or willful misconduct or, in the case of a criminal matter, to action that was known to have been unlawful. We have agreed to indemnify our Sponsors and their affiliates to the fullest extent permitted by law from and against any claims, liabilities, losses, damages, costs or expenses incurred by an indemnified person or threatened in connection with our operations, investments and activities or in respect of or arising from the MSAs or the services provided by our Sponsors and their affiliates, except to the extent that the claims, liabilities, losses, damages, costs or expenses are determined to have resulted from the conduct in respect of which such persons have liability as described above. Additionally, the maximum amount of the aggregate liability of our Sponsors or any of their affiliates in providing services under the MSAs or of any director, officer, employee, agent or other representative of our Sponsors or any of their affiliates, is equal to the aggregate amount of the management fee received by the applicable Sponsor in the most recent calendar year. These protections may result in our Sponsors and their affiliates tolerating greater risks when making decisions than otherwise would be the case, including when determining whether to use leverage in connection with acquisitions. The indemnification arrangements to which our Sponsors and their affiliates are a party may also give rise to legal claims for indemnification, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

Risks Related to Ownership of Our Class A Shares

Holders of our Class A shares have limited voting rights and are not entitled to elect the General Partner or its directors.

Unlike the holders of common stock in a corporation, our shareholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our shareholders have no right on an annual or ongoing basis to elect the General Partner or its Board. Rather, the Board is appointed by our Sponsors, indirectly through their ownership of Holdings. Furthermore, if our shareholders are dissatisfied with the performance of the General Partner, they have little ability to remove the General Partner. As a result of these limitations, the price at which the Class A shares trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our Partnership Agreement also contains provisions limiting the ability of shareholders to call meetings or to acquire information about our operations, as well as other provisions limiting the shareholders’ ability to influence the manner or direction of management.

Our Partnership Agreement restricts the remedies available to holders of our Class A shares for actions taken by the General Partner that might otherwise constitute breaches of fiduciary duties.

Our Partnership Agreement contains provisions that restrict the remedies available to shareholders for actions taken by the General Partner that might otherwise constitute breaches of fiduciary duties under state fiduciary duty law. For example, our Partnership Agreement provides that:

• whenever the General Partner, the Board or any committee thereof (including the Conflicts Committee) makes a determination or takes, or declines to take, any other action in their respective capacities, or an affiliate of the general partner causes the general partner to do so, the General Partner, the Board and any committee thereof (including the Conflicts Committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in, or not adverse to, the best interests of our partnership, and, except as specifically provided by our Partnership Agreement, will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;

• the General Partner will not have any liability to us or our shareholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

• the General Partner and its officers and directors will not be liable for monetary damages to us or our shareholders resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or its officers and directors, as the case may be,

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acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; and

• the General Partner will not be in breach of its obligations under our Partnership Agreement (including any duties to us or our shareholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

• approved by the Conflicts Committee, although the General Partner is not obligated to seek such approval;

• approved by the vote of a majority of the outstanding shares, excluding any shares owned by the General Partner and its affiliates, although the General Partner is not obligated to seek such approval;

• determined by the Board to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

• determined by the Board to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by the General Partner, the Board or any committee thereof (including the Conflicts Committee) must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our shareholders or the Conflicts Committee and the Board determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth subbullets above, then it will be presumed that, in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our Partnership Agreement restricts the voting rights of shareholders owning 20% or more of any class of shares then outstanding.

Shareholders’ voting rights are further restricted by a provision of our Partnership Agreement providing that any shares held by a person or related group that owns 20% or more of any class of shares then outstanding, other than the General Partner, its affiliates, their transferees and persons who acquired such shares with the prior approval of the Board, cannot vote on any matter.

Our Partnership Agreement replaces the General Partner’s fiduciary duties to holders of our Class A shares with contractual standards governing its duties.

Our Partnership Agreement contains provisions that eliminate the fiduciary standards to which the General Partner would otherwise be held by state fiduciary duty law and replace those standards with several different contractual standards. For example, our Partnership Agreement permits the General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as the General Partner, free of any duties to us and our shareholders. This provision entitles the General Partner and its affiliates to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our shareholders. Examples of decisions that the General Partner and its affiliates may make in their individual capacities include:

• how to allocate corporate opportunities among us and its affiliates;

• whether to exercise its limited call right, preemptive rights or registration rights;

• whether to seek approval of the resolution of a conflict of interest by the Conflicts Committee;

• how to exercise its voting rights with respect to the units it or its affiliates own in OpCo and us;

• whether to exchange its OpCo common units for our Class A shares; and

• whether to consent to any merger, consolidation or conversion of us or OpCo or to an amendment to our Partnership Agreement or the OpCo limited liability company agreement.

These decisions may be made by the owner of the General Partner. Holdings, which is owned by our Sponsors, is the owner of the General Partner.

By purchasing a Class A share, a Class A shareholder becomes bound by the provisions in our Partnership Agreement, including the provisions discussed above.

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The General Partner interest or the control of the General Partner may be transferred to a third party without shareholder consent.

Our Partnership Agreement does not restrict the ability of Holdings to transfer all or a portion of its ownership interest in the General Partner to a third party. The new owner of the General Partner would then be in a position to replace the Board with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

The incentive distribution rights of our Sponsors, through Holdings, may be transferred to a third party without shareholder consent.

Our Sponsors may cause Holdings to transfer its incentive distribution rights to a third party at any time without the consent of our shareholders. If our Sponsors transfer their incentive distribution rights to a third party, they will have less incentive to support an increase in our distributions. A transfer of incentive distribution rights by our Sponsors could reduce the likelihood of First Solar or SunPower selling or contributing additional solar energy projects to us, which in turn would impact our ability to grow our portfolio.

Our Sponsors, through Holdings, or any transferee holding a majority of the incentive distribution rights, may elect to cause OpCo to issue common units to Holdings in connection with a resetting of the target distribution levels related to the incentive distribution rights, without the approval of the Conflicts Committee or our shareholders. This election may result in lower distributions to our Class A shareholders in certain situations.

The holder or holders of a majority of the incentive distribution rights, which is currently our Sponsors through Holdings, have the right, at any time when there are no OpCo subordinated units outstanding and the holders have received incentive distributions at the highest level to which they are entitled (200%) for each of the prior four consecutive fiscal quarters (and the aggregate amounts distributed in respect of such four-quarter period did not exceed adjusted operating surplus for such four-quarter period), to reset the minimum quarterly distribution and the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. Our Sponsors have the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as our Sponsors with respect to resetting target distributions.

In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the incentive distribution rights will be entitled to receive, in the aggregate, the number of OpCo’s common units equal to that number of OpCo common units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. We anticipate that the General Partner would exercise this reset right in order to facilitate acquisitions or internal expansion projects that would not otherwise be sufficiently accretive to cash distributions per OpCo common unit. It is possible, however, that our Sponsors or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued OpCo common units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our Class A shareholders to experience reduction in the amount of cash distributions that they would have otherwise received had we not issued Class A shares to the General Partner in connection with resetting the target distribution levels.

Even if holders of our Class A shares are dissatisfied, they cannot initially remove the General Partner without its consent.

Shareholders will be unable initially to remove the General Partner or OpCo’s managing member without its consent because the General Partner and its affiliates own sufficient shares to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding shares (including shares owned by the General Partner and its affiliates, including our Sponsors) is required to remove the General Partner. As of November 30, 2017, the General Partner and its affiliates, including our Sponsors, owned 64.5% of our outstanding shares through their ownership of Class B shares. In addition, any vote to remove the General Partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the Class A shares and a majority of the Class B shares, voting as separate classes. This provides Holdings the ability to prevent the removal of the General Partner.

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Furthermore, shareholders’ voting rights are further restricted by our Partnership Agreement provision providing that any shares held by a person that owns 20% or more of any class of shares then outstanding, other than the General Partner, its affiliates, their transferees and persons who acquired such shares with the prior approval of the Board, cannot vote on any matter.

Our Partnership Agreement also contains provisions limiting the ability of shareholders to call meetings or to acquire information about our operations, as well as other provisions limiting the shareholders’ ability to influence the manner or direction of management.

We may issue additional Class A shares or other partnership interests without shareholder approval, which would dilute shareholder interests.

At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our shareholders, and our shareholders (other than our Sponsors and their affiliates) have no preemptive or other rights (solely as a result of their status as shareholders) to purchase any such limited partner interests. Further, there are no limitations in our Partnership Agreement on our ability to issue equity securities that rank equal or senior to our Class A shares as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional Class A shares or other equity securities of equal or senior rank will have the following effects:

• our existing shareholders’ proportionate ownership interest in us will decrease;

• the amount of cash we have available to distribute on each Class A share may decrease;

• because a lower percentage of total outstanding OpCo units will be OpCo subordinated units, the risk that a shortfall in payment of the minimum quarterly distribution will be borne by OpCo’s common unitholders, including the Partnership, will increase;

• the ratio of taxable income to distributions may increase;

• the relative voting strength of each previously outstanding share may be diminished; and

• the market price of our Class A shares may decline.

The market price of our Class A Shares could be adversely affected by sales of substantial amounts of our Class A Shares in the public or private markets, including sales by our Sponsors, including upon conversion of the OpCo subordinated units.

Our Sponsors collectively own 15,500,000 OpCo common units that can be exchanged for 15,500,000 Class A Shares and sold into the public market at any time. In addition, the subordination period could end as soon as the first business day after the distribution with respect to the quarter ending August 31, 2018, at which time the 35,500,000 OpCo subordinated units owned by our Sponsors will automatically convert into 35,500,000 OpCo common units and be eligible to be exchanged for 35,500,000 Class A Shares as well. Sales by our Sponsors of a substantial number of our Class A Shares in the public or private markets at any time, including upon the end of the subordination period, or the perception that such sales might occur, could have a material adverse effect on the price of our Class A Shares or could impair our ability to obtain capital through an offering of equity securities. Our Sponsors have registration rights relating to the offer and sale of any Class A shares that they hold, which would facilitate the disposition of large blocks of Class A Shares.

The General Partner has a limited call right that may require you to sell your Class A shares at an undesirable time or price.

If at any time the General Partner and its affiliates, including our Sponsors, own more than 80% of the aggregate of the number of Class A shares then outstanding and the number of Class B shares equal to the number of OpCo common units owned by the Sponsors and their affiliates, the General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the Class A shares held by unaffiliated persons at a price not less than their then-current market price, as calculated pursuant to the terms of our Partnership Agreement. As a result, you may be required to sell your Class A shares at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your shares. At November 30, 2017, the General Partner and its affiliates own approximately 64.5% of our outstanding shares through their ownership of Class B shares. At the end of the subordination period, assuming no additional issuances of Class A shares by us, the General Partner and its affiliates will own OpCo common units convertible into approximately 64.5% of our outstanding Class A shares and therefore would not be able to exercise the call right at that time.

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Reimbursements and fees owed to the General Partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution. The amount and timing of such reimbursements and fees will be determined by the General Partner and there are no limits on the amount that OpCo may be required to pay.

Under the OpCo limited liability company agreement, prior to making any distributions on OpCo’s common units, OpCo will reimburse the General Partner and its affiliates, including the Partnership, for out-of-pocket expenses they incur and payments they make on our behalf. OpCo will also pay certain fees and reimbursements under the MSAs prior to making any distributions on OpCo’s common units. The reimbursement of expenses and certain payments made under credit support arrangements and payment of fees, if any, to the General Partner and its affiliates will reduce the amount of available cash OpCo has to pay cash distributions to us and the amount that we have available to pay distributions to our Class A shareholders. Under the OpCo limited liability company agreement, there is no limit on the fees and expense reimbursements OpCo may be required to pay.

The General Partner’s discretion in establishing cash reserves may reduce the amount of available cash.

The OpCo limited liability company agreement requires OpCo’s managing member to deduct from operating surplus cash reserves that it determines are necessary to fund future operating expenditures. In addition, our Partnership Agreement and the OpCo limited liability company agreement permit the General Partner to reduce available cash by establishing cash reserves for the proper conduct of business, to comply with applicable law or agreements to which we or our subsidiaries are a party or to provide funds for future distributions to OpCo’s members and our partners. These cash reserves will affect the amount of cash distributed by OpCo and the amount of cash available for distribution to our Class A shareholders.

We and OpCo can borrow money to pay distributions, which would reduce the amount of credit available to operate our business.

The OpCo limited liability company agreement allows us to make working capital borrowings to pay distributions to our Class A shareholders or OpCo’s unitholders. Accordingly, if we or OpCo have available borrowing capacity, we or OpCo can make distributions on our Class A shares or OpCo’s common and subordinated units, as applicable, even though cash generated by our operations may not be sufficient to pay such distributions. Any working capital borrowings by us or OpCo to make distributions will reduce the amount of working capital borrowings we or OpCo can make for operations.

Increases in interest rates could adversely impact the price of our Class A shares, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our share price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on the price of our Class A shares, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Except in limited circumstances, the General Partner has the power and authority to conduct our business without shareholder approval.

Under our Partnership Agreement, the General Partner has full power and authority to do all things, other than those items that require shareholder approval or with respect to which the General Partner has sought Conflicts Committee approval, on such terms as it determines to be necessary or appropriate to conduct our business. In addition, since we are the managing member of OpCo, determinations made by us under the OpCo limited liability company agreement will be made at the direction of the General Partner. Decisions that may be made by the General Partner in accordance with our Partnership Agreement or the OpCo limited liability company agreement include:

• making any expenditures, lending or borrowing money, assuming, guaranteeing or contracting for indebtedness and other liabilities, issuing evidences of indebtedness, including indebtedness that is convertible into our securities, and incurring any other obligations;

• purchasing, selling, acquiring or disposing of our securities, or issuing additional options, rights, warrants and appreciation rights relating to our securities;

• acquiring, disposing, mortgaging, pledging, encumbering, hypothecating or exchanging any or all of our assets;

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• negotiating, executing and performing any contracts, conveyances or other instruments;

• making cash distributions;

• selecting and dismissing employees and agents, outside attorneys, accountants, consultants and contractors and determining their compensation and other terms of employment or hiring;

• maintaining insurance for our or OpCo’s benefit and the benefit of our respective partners;

• forming, acquiring an interest in, contributing property to and making loans to any limited or general partnership, joint venture, corporation, limited liability company or other entity;

• controlling any matters affecting our rights and obligations, including bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation, incurring legal expenses and settling claims and litigation;

• indemnifying any person against liabilities and contingencies to the extent permitted by law;

• making tax, regulatory and other filings or rendering periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

• entering into and terminating agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as the General Partner.

Our Partnership Agreement provides that the General Partner must act in good faith when making decisions on our behalf, and our Partnership Agreement further provides that in order for a determination to be made in good faith, the General Partner must subjectively believe that the determination is in, or not adverse to, the best interests of our partnership.

Contracts between us, on the one hand, and the General Partner and its affiliates, on the other hand, may not be the result of arm’s-length negotiations.

Our Partnership Agreement allows the General Partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. The General Partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. The General Partner will determine in good faith the terms of any arrangement or transaction entered into by the Partnership. Similarly, agreements, contracts or arrangements between us and the General Partner and its affiliates that are entered into by the Partnership will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, the General Partner may determine that the Conflicts Committee may make a determination on our behalf with respect to such arrangements.

The General Partner and its affiliates have no obligation to permit us to use any assets or services of the General Partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of the General Partner and its affiliates to enter into any contracts of this kind.

Class A shareholders have no right to enforce the obligations of the General Partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and the General Partner and its affiliates, on the other hand, do not, and in the future will not, grant to the shareholders, separate and apart from us, the right to enforce the obligations of the General Partner and its affiliates in our favor.

The General Partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who perform services for us are retained by the General Partner. Attorneys, independent accountants and others who perform services for us are selected by the General Partner or our Conflicts Committee and may perform services for the General Partner and its affiliates. We may retain separate counsel for ourselves or the holders of shares in the event of a conflict of interest between the General Partner and its affiliates, on the one hand, and us or the holders of shares, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

For so long as we are an emerging growth company, we will not be required to comply with certain requirements that apply to other public companies.

For as long as we remain an “emerging growth company” under the Jumpstart Our Business Act (the “JOBS Act”), we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies

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that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) and reduced disclosure obligations regarding executive compensation in our periodic reports. We could remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.1 billion of revenues in a fiscal year, have more than $700 million in market value of our Class A common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, our Class A shareholders will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our Class A shares to be less attractive as a result, the trading price of our Class A shares may decline.

Shareholders may have to repay distributions that were wrongfully distributed to them.

Under certain circumstances, shareholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our shareholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

While we believe we currently have effective internal control over financial reporting, we may identify a material weakness in our internal controls over financial reporting that could cause investors to lose confidence in the reliability of our financial statements and result in a decrease in the value of our Class A shares.

Our management is responsible for maintaining internal control over financial reporting designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with U.S. GAAP.

We need to continuously maintain our internal control processes and systems and adapt them as our business grows and changes. This process is expensive, time-consuming and requires significant management attention. We cannot be certain that our internal control measures will continue to provide adequate control over our financial processes and reporting and ensure compliance with Section 404 of the Sarbanes-Oxley Act. Furthermore, as we grow our business or acquire other businesses, our internal controls may become more complex and we may require significantly more resources to ensure they remain effective. Failure to implement required new or improved controls, or difficulties encountered in their implementation, either in our existing business or in businesses that we may acquire, could harm our operating results or cause us to fail to meet our reporting obligations. If we or our independent registered public accounting firm identify material weaknesses in our internal controls, the disclosure of that fact, even if quickly remedied, may cause investors to lose confidence in our financial statements and the trading price of our Class A shares may decline.

Remediation of a material weakness could require us to incur significant expense and if we fail to remedy any material weakness, our financial statements may be inaccurate, our ability to report our financial results on a timely and accurate basis may be adversely affected, our access to the capital markets may be restricted, the trading price of our Class A shares may decline, and we may be subject to sanctions or investigation by regulatory authorities, including the SEC or the NASDAQ. We may also be required to restate our financial statements from prior periods.

The NASDAQ does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

Because we are a publicly traded limited partnership, the NASDAQ does not require us, and we do not have, a majority of independent directors on the Board or a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional partnership interests, including to affiliates, will not be subject to the NASDAQ’s shareholder approval rules that apply to a corporation. Accordingly, shareholders will not have the same protections afforded to certain corporations that are subject to all of the NASDAQ corporate governance requirements.

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Risks Related to Taxation

Our future tax liability may be greater than expected if we do not generate NOLs sufficient to offset taxable income or if tax authorities challenge certain of our tax positions.

Even though we are organized as a limited partnership under state law, we are treated as a corporation for U.S. federal income tax purposes and thus are subject to U.S. federal income tax at regular corporate rates on our net taxable income. We expect to generate NOLs and NOL carryforwards that we can use to offset future taxable income. As a result, we do not expect to pay meaningful U.S. federal income tax for approximately ten years. This estimate is based upon assumptions we have made regarding, among other things, OpCo’s income, capital expenditures and operating expenses and it ignores the effect of any possible acquisitions of additional assets, including the SunPower ROFO Projects. While we expect that our NOLs and NOL carryforwards will be available to us as a future benefit, in the event that they are not generated as expected, are successfully challenged by the IRS (in a tax audit or otherwise), or are subject to future limitations as described below, our ability to realize these benefits may be limited. Further, the IRS or other tax authorities could challenge one or more tax positions we or OpCo take, such as the classification of assets under the income tax depreciation rules, the characterization of expenses for income tax purposes, the extent to which sales, use or goods and services tax applies to operations in a particular state or the availability of property tax exemptions with respect to our projects, which could reduce the NOLs we generate. Further, any change in law may affect our tax position, including the size of our expected NOLs.

Our federal and state tax positions may be challenged by the relevant tax authority. The process and costs, including potential penalties for nonpayment of disputed amounts, of contesting such challenges, administratively or judicially, regardless of the merits, could be material. A reduction in our expected NOLs and NOL carryforwards, a limitation on our ability to use such losses, or other tax attributes, such as tax credits, and future tax audits or a challenge by tax authorities to our tax positions may result in a material increase in our estimated future income or other tax liabilities, which would negatively impact the amount of after-tax cash available for distribution to our Class A shareholders and our financial condition.

Our ability to use NOLs and NOL carryforwards to offset future income may be limited.

Our ability to use any NOLs generated by us could be substantially limited if we were to experience an “ownership change” as defined under Section 382 of the Code. In general, an “ownership change” would occur if our “5-percent shareholders,” as defined under Section 382 of the Code, including certain groups of persons treated as “5-percent shareholders,” collectively increased their ownership in us by more than 50 percentage points over a rolling three-year period. An ownership change can occur as a result of a public offering of our Class A shares, as well as through secondary market purchases of our Class A shares and certain types of reorganization transactions. A corporation (including any entity that is treated as a corporation for U.S. federal income tax purposes) that experiences an ownership change will generally be subject to an annual limitation on the use of its pre-ownership change NOLs and NOL carryforwards (and certain other losses and/or credits) equal to the equity value of the corporation immediately before the ownership change, multiplied by the “long-term tax-exempt rate” (as determined by the IRS) for the month in which the ownership change occurs. Such a limitation could, for any given year, have the effect of increasing the amount of our U.S. federal income tax liability, which would negatively impact the amount of after-tax cash available for distribution to our Class A shareholders and our financial condition.

Our ability to use any NOLs generated by us could also be substantially limited by changes in U.S. federal tax law.

Distributions to Class A shareholders may be taxable as dividends.

Even though we are organized as a limited partnership under state law, we are treated as a corporation for U.S. federal income tax purposes. Accordingly, if we make distributions from current or accumulated earnings and profits as computed for U.S. federal income tax purposes, such distributions will generally be taxable to Class A shareholders as ordinary dividend income for U.S. federal income tax purposes. Distributions paid to non-corporate U.S. shareholders will be subject to U.S. federal income tax at preferential rates, provided that certain holding period and other requirements are satisfied. We estimate that we will have limited earnings and profits for eight or more years. However, it is difficult to predict whether we will generate earnings and profits as computed for U.S. federal income tax purposes in any given tax year, and although we expect that a portion of our distributions to Class A shareholders will exceed our current and accumulated earnings and profits as computed for U.S. federal income tax purposes and therefore constitute a non-taxable return of capital distribution to the extent of a shareholder’s basis in its Class A shares, this may not occur. In addition, although return-of-capital distributions are generally non-taxable to the extent of a shareholder’s basis in its Class A shares, such distributions will reduce the shareholder’s adjusted tax basis in its Class A shares, which will result in an increase in the amount of gain (or a decrease in the amount of loss) that will be recognized by the shareholder on a future disposition of our Class A shares, and to the extent any return-of-

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capital distribution exceeds a shareholder’s basis, such distributions will be treated as gain on the sale or exchange of the Class A shares.

Changes in ownership outside our control may increase property tax exposure.

A subsidiary of Southern Company owns a 51% economic interest in, and we own a 49% economic interest in, each of the Henrietta Project Entity, the Lost Hills Blackwell Project Entity, the North Star Project Entity and the Solar Gen 2 Project Entity. In addition, a subsidiary of Southern Company owns a 66% economic interest in, and we own a 34% economic interest in, the Stateline Project Entity. Collectively, these five project entities in which we own minority interests constitute over 68% of the MW of the projects in our portfolio of solar assets as of November 30, 2017.

The assets of each of these five joint venture projects are all located in California, which exempts active solar power systems from state and local property taxes. However, California’s property tax exemption for these projects will terminate if there is a direct or indirect change in ownership of the systems. As a result of our minority interest, we cannot prevent a change in ownership in these project entities if Southern Company sells its controlling interest to a third party. Exposure to California state and local property taxes would negatively impact the amount of after-tax cash available for distribution to our Class A shareholders and our financial condition.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

The information required by Item 2 is contained in Item 1. Business.

Item 3. Legal Proceedings.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us.

Item 4. Mine Safety Disclosures.

None.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Quarterly Class A Share Prices and Cash Distributions Per Class A Share

The Partnership’s Class A shares representing limited partner interests began trading on the NASDAQ under the symbol “CAFD” on June 19, 2015. The Partnership’s Class B shares representing limited partner interests are not publicly traded.

As of January 31, 2018, there were eight holders of record of the Partnership’s Class A shares representing limited partner interests, and two holders of record of the Partnership’s Class B shares representing limited partner interests. In determining the number of Class A shareholders, we consider clearing agencies and security position listings as one Class A shareholder for each agency or listing. A substantially greater number of holders of the Partnership’s Class A shares are in “street name” or beneficial holders, whose shares are held of record by banks, brokers and other financial institutions.

The table below sets forth, for the periods indicated, the intraday high and low sale prices per Class A share and cash distributions declared to our Class A shares for each quarter of fiscal 2017 and fiscal 2016:

	Class A Share Price
	High		Low		Quarterly Cash Distribution per Class A Share
2017
First Quarter	$	14.77	$	12.04	$	0.2490
Second Quarter	13.99		11.51		0.2565
Third Quarter	15.25		13.61		0.2642
Fourth Quarter	15.79		14.06		0.2721
2016
First Quarter	$	16.93	$	12.22	$	0.2246
Second Quarter	16.49		13.54		0.2325
Third Quarter	17.34		14.00		0.2406
Fourth Quarter	15.98		12.44		0.2490

On January 12, 2018, we distributed $22.2 million on our Class A shares and OpCo’s common and subordinated units, or $0.2802 per share or unit for the period from September 1, 2017 to November 30, 2017. Although our Partnership Agreement requires that we distribute our available cash each quarter, we do not have a legal obligation to distribute any particular amount per Class A share or per OpCo unit. During the pendency of the Mergers, we intend to make quarterly distributions of $0.2802 per share, which maintains the distribution level at the end of fiscal 2017.

Distributions of Available Cash

Distributions of Our Available Cash

Our Partnership Agreement requires that, within 45 days after the end of each fiscal quarter, we distribute our available cash to Class A shareholders of record on the applicable record date.

Our Partnership Agreement requires us to distribute our available cash quarterly. Generally, our available cash is all cash on hand or received before the date of distribution in respect of such quarter, less the amount of cash reserves established by our general partner. We currently expect that cash reserves of the Partnership would be established solely to provide for the payment of income taxes payable by the Partnership, if any. Our cash flow is generated from distributions we receive from OpCo.

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Shares Eligible for Distribution

As of November 30, 2017, we had 28,088,673 Class A shares outstanding and 51,000,000 Class B shares outstanding, with SunPower and First Solar owning 28,883,075 and 22,116,925 Class B shares, respectively. Each Class A share is entitled to receive distributions (including upon liquidation) on a pro rata basis. Our Class B shares are not entitled to receive any distributions. We may issue additional Class A shares to fund the redemption of OpCo common units and our Class B shares tendered by our Sponsors under the Exchange Agreement among us, our Sponsors, our general partner and OpCo. Please read Part III, Item 13. “Certain Relationships and Related Transactions, and Director Independence—Exchange Agreement.”

General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own Class A shares or other equity securities in us and would be entitled to receive cash distributions on any such interests.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with our Partnership Agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors and distribute any remaining proceeds pro rata to our Class A shareholders.

Intent to Distribute a Quarterly Distribution

We intend to make a quarterly distribution to the holders of our Class A shares of at least $0.2097 per share, or $0.8388 per share on an annualized basis, which is equal to OpCo’s minimum quarterly distribution on the OpCo common units. However, our ability to pay any such quarterly distribution will depend on the amount of distributions we receive from OpCo, as a holder of OpCo common units.

Even if we receive sufficient cash from OpCo to pay any such quarterly distribution, our ability to pay such quarterly distribution will also depend on whether we have sufficient remaining cash after the establishment of cash reserves as determined by our general partner. Consequently, we may not be able to pay a quarterly distribution on our Class A shares in any quarter, even if the minimum quarterly distribution on the OpCo common units has been paid in full.

Distributions of Available Cash by OpCo

General

The OpCo limited liability company agreement requires that, within 45 days after the end of each quarter, OpCo will distribute its available cash to its unitholders of record on the applicable record date.

Units Eligible for Distribution

As of November 30, 2017, we owned 28,088,673 common units in OpCo, as well as a controlling non-economic managing member interest in OpCo, SunPower owned 8,778,190 common units and 20,104,885 subordinated units in OpCo, and First Solar owned 6,721,810 common units and 15,395,115 subordinated units in OpCo.

Definition of OpCo’s Available Cash

Available cash generally means, for any quarter, the sum of all cash and cash equivalents on hand at the end of that quarter:

• less, the amount of cash reserves established by our general partner to:

• provide for the proper conduct of OpCo’s business, including reserves for anticipated future debt service requirements, future capital expenditures and future acquisitions, subsequent to that quarter;

• comply with applicable law or any of OpCo’s or its subsidiaries’ debt instruments or other agreements; or

• provide funds for distributions to OpCo’s unitholders for any one or more of the next four quarters, provided that we may not establish cash reserves for future distributions if the effect of the establishment of such

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reserves will prevent OpCo from making the minimum quarterly distribution on all OpCo common units and any cumulative arrearages on such OpCo common units for the current quarter;

• plus, all cash on hand on the date of determination resulting from dividends or distributions received after the end of the quarter from equity interests in any person other than a subsidiary in respect of operations conducted by such person during the quarter; and

• plus, if we so determine, all or any portion of the cash on hand on the date of determination of available cash resulting from working capital borrowings after the end of such quarter.

The purpose and effect of the last bullet point above is to allow us, if we so decide, to cause OpCo to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to OpCo’s unitholders. Under the OpCo limited liability company agreement, working capital borrowings are generally borrowings under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to members, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

We intend to cause OpCo to pay at least the minimum quarterly distribution to the holders of OpCo common units, including us, and OpCo’s subordinated units of $0.2097 per unit, or $0.8388 per unit on an annualized basis, to the extent OpCo has sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including (i) expenses of our general partner and its affiliates, (ii) our expenses and (iii) payments to our Sponsors and their affiliates under the MSAs. However, OpCo may not be able to pay the minimum quarterly distribution or any other amount on its units in any quarter. Since we own all of the non-economic managing member interest of OpCo, determinations made by OpCo will ultimately be made by our general partner. Please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Sources of Liquidity— Term Loan, Delayed Draw Term Loan and Revolving Credit Facility and Stateline Promissory Note” for a discussion of the restrictions in OpCo’s senior secured credit facility that may restrict its ability to make distributions.

Incentive Distribution Rights

Holdings currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash OpCo distributes from operating surplus (as defined in the OpCo limited liability company agreement) in excess of $0.31455 per common and subordinated unit per quarter. The maximum distribution of 50% does not include any distributions that Holdings or its affiliates may receive on OpCo common or subordinated units that they own.

Percentage Allocations of Available Cash From Operating Surplus

The following table sets forth the percentage allocations of available cash from operating surplus between Holdings (in respect of the incentive distribution rights) and OpCo’s unitholders (in respect of their common and subordinated units) based on the specified target quarterly distribution levels. The amounts set forth under “Marginal Percentage Interest in Available Cash” are the percentage interests of Holdings (in respect of the incentive distribution rights) and the OpCo unitholders (in respect of their common and subordinated units) in any available cash from operating surplus OpCo distributes up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit Target Amount.” The percentage interests shown for OpCo’s unitholders and Holdings for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

			Marginal Percentage Interest in Available Cash
	Total Quarterly Distribution  per Unit Target Amount		Unitholders		Incentive Distribution Rights
Minimum Quarterly Distribution	$	0.2097	100.0	%	—	%
First Target Distribution	above $0.2097 up to $0.31455		100.0	%	—	%
Second Target Distribution	above $0.31455 up to $0.366975		85.0	%	15.0	%
Third Target Distribution	above $0.366975 up to $0.4194		75.0	%	25.0	%
Thereafter	above $0.4194		50.0	%	50.0	%

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Subordination Period

The OpCo limited liability company agreement provides that, during the subordination period (which we define below), the OpCo common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.2097 per OpCo common unit, which amount is defined in the OpCo limited liability company agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the OpCo common units from prior quarters, before any distributions of available cash from operating surplus may be made on the OpCo subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the OpCo subordinated units will not be entitled to receive any distributions from operating surplus until the OpCo common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages from prior quarters. Furthermore, no arrearages will accrue or be payable on the OpCo subordinated units. The practical effect of the OpCo subordinated units is to increase the likelihood that, during the subordination period, there will be available cash from operating surplus to be distributed on the OpCo common units and our Class A shares.

Except as described below, the subordination period began on June 24, 2015 and will expire on the first business day after the distribution to OpCo’s unitholders in respect of any quarter, beginning with the quarter ending August 31, 2018, if each of the following has occurred:

• for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date, aggregate distributions from operating surplus equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of OpCo common and subordinated units outstanding for each quarter of each period;

• for the same three consecutive, non-overlapping four-quarter periods, the “adjusted operating surplus” (as defined in the OpCo limited liability company agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of OpCo common and subordinated units outstanding during each quarter on a fully diluted weighted average basis; and

• there are no arrearages in payment of the minimum quarterly distribution on the OpCo common units.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the OpCo subordinated units will convert into OpCo common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter beginning with the quarter ended August 31, 2016, if each of the following has occurred:

• for the four-quarter period immediately preceding that date, aggregate distributions from operating surplus exceeded the product of 150.0% of the minimum quarterly distribution multiplied by the total number of OpCo common and subordinated units outstanding in each quarter in the period;

• for the same four-quarter period, the “adjusted operating surplus” equaled or exceeded the product of 150.0% of the minimum quarterly distribution multiplied by the total number of OpCo common and subordinated units outstanding during each quarter on a fully diluted weighted average basis, plus the related distribution on the incentive distribution rights; and

• there are no arrearages in payment of the minimum quarterly distributions on the OpCo common units.

Expiration of the Subordination Period

When the subordination period ends, each outstanding OpCo subordinated unit will convert into one OpCo common unit and will thereafter participate pro rata with the other OpCo common units in distributions of available cash.

Securities Authorized for Issuance under Equity Compensation Plans

Please read Part III, Item 11. “Executive Compensation” and Part III, Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding our equity compensation plans as of November 30, 2017.

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Issuer Purchases of Equity Securities

We did not repurchase any of our Class A Shares in fiscal 2017.

Item 6. Selected Financial Data.

The Partnership’s historical selected financial data is presented in the following table. For all periods prior to the IPO, the amounts shown in the table below represent the Predecessor’s financial data, and were prepared using SunPower’s historical basis in assets and liabilities. For all periods subsequent to the IPO, the amounts shown in the table below represent the results of the Partnership. This historical data should be read in conjunction with Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and the related notes thereto in Part II, Item 8. “Financial Statements and Supplementary Data.”

	Year Ended						Eleven Months Ended			Year Ended
	November 30, 2017			November 30, 2016			November 30, 2015			December 28, 2014			December 29, 2013
Statement of Operations Data:
Revenues:
Operating revenues	$	70,089		$	61,198		$	10,660		$	9,231		$	24,489
Total revenues	70,089			61,198			10,660			9,231			24,489
Operating costs and expenses:
Cost of operations	8,450			6,959			2,624			(3,195		)	13,111
Cost of operations—SunPower, prior to IPO	—			—			468			937			928
Selling, general and administrative	9,732			7,003			10,702			4,818			4,272
Depreciation and accretion	28,070			22,792			4,291			2,339			3,224
Acquisition-related transaction costs	56			2,271			212			—			—
Total operating costs and expenses	46,308			39,025			18,297			4,899			21,535
Operating income (loss)	23,781			22,173			(7,637		)	4,332			2,954
Other expense (income):
Interest expense	23,497			12,081			1,860			5,525			6,751
Interest income	(1,198		)	(1,203		)	(1,470		)	—			—
Other expense (income)	(971		)	(1,518		)	12,536			—			—
Total other expense, net	21,328			9,360			12,926			5,525			6,751
Income (loss) before income taxes and equity in earnings of unconsolidated investees	2,453			12,813			(20,563		)	(1,193		)	(3,797		)
Income tax provision	(6,587		)	(18,244		)	(12,503		)	(23		)	(30		)
Equity in earnings of unconsolidated investees	43,379			18,341			9,055			—			—
Net income (loss)	39,245			12,910			(24,011		)	$	(1,216	)	$	(3,827	)
Less: Predecessor loss prior to IPO on June 24, 2015	—			—			(20,095		)
Net income (loss) subsequent to IPO	39,245			12,910			(3,916		)
Less: Net income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests	27,838			(14,191		)	(22,642		)
Net income attributable to 8point3 Energy Partners LP Class A shares	$	11,407		$	27,101		$	18,726
Net income per Class A share:
Basic	$	0.41		$	1.27		$	0.94
Diluted	$	0.41		$	1.27		$	0.94
Distributions per Class A share:	$	1.04		$	0.91		$	0.16
Weighted average number of Class A shares:
Basic	28,079			21,420			20,002
Diluted	43,579			36,920			35,034
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	88,668		$	54,636		$	1,836		$	1,801		$	5,380
Investing activities	$	(280,996	)	$	(272,001	)	$	(219,016	)	$	(55,231	)	$	(8,082	)
Financing activities	$	191,595		$	174,845		$	273,961		$	53,430		$	2,702
Balance Sheet Data:
Cash and cash equivalents	$	13,528		$	14,261		$	56,781		$	—		$	—
Cash grants and rebates receivable	$	—		$	—		$	—		$	1,216		$	9,692
Accounts receivable and short-term financing receivables, net	$	5,572		$	5,401		$	4,289		$	2,910		$	2,850
Prepaid and other current assets	$	16,990		$	15,745		$	8,033		$	—		$	—
Property and equipment, net	$	713,284		$	720,132		$	486,942		$	158,208		$	100,010
Long-term financing receivables, net	$	76,201		$	80,014		$	83,376		$	85,635		$	87,864
Investments in unconsolidated affiliates	$	768,258		$	475,078		$	352,070		$	—		$	—
Other long-term assets	$	15,372		$	24,432		$	26,142		$	—		$	—
Total assets	$	1,609,205		$	1,335,063		$	1,017,633		$	247,969		$	200,565
Long-term debt and financing obligations	$	689,847		$	384,436		$	297,206		$	91,183		$	31,545
Total liabilities	$	751,851		$	455,530		$	325,500		$	120,459		$	60,632
Redeemable noncontrolling interests	$	17,346		$	17,624		$	89,747		$	—		$	—
Total equity	$	840,008		$	861,909		$	602,386		$	127,510		$	139,933

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

You should read the following discussion and analysis of our financial condition and results of operations in conjunction with our consolidated financial statements for and as of the year ended November 30, 2017, November 30, 2016 and the eleven months ended November 30, 2015, and the notes thereto included elsewhere in this Annual Report on Form 10-K.

Overview

Description of Partnership

We are a limited partnership formed by First Solar and SunPower, our Sponsors, to own, operate and acquire solar energy generation projects.

On February 5, 2018, we, our general partner, OpCo and Holdings entered into the Merger Agreement with certain affiliates of Capital Dynamics. Upon the terms and subject to the conditions set forth in the Merger Agreement, (i) OpCo Merger Sub 1 will merge with and into OpCo and the separate existence of OpCo Merger Sub 1 will cease and OpCo will continue as the surviving limited liability company of OpCo Merger 1, (ii) OpCo Merger Sub 2 will merge with and into the Initial Surviving LLC and the separate existence of OpCo Merger Sub 2 will cease and the Initial Surviving LLC will continue as the surviving limited liability company of OpCo Merger 2, (iii) Partnership Merger Sub will merge with and into the Partnership and the separate existence of Partnership Merger Sub will cease and the Partnership shall continue as the surviving partnership of the Partnership Merger, (iv) Holdings will transfer to 8point3 Solar or an affiliate thereof, and 8point3 Solar (or its designated affiliate) will accept, for no consideration, the transfer and delivery of, 100% of the issued and outstanding membership interests in the General Partner, including all rights and obligations relating thereto and all economic and capital interests therein, and 100% of the issued and outstanding Incentive distribution Rights (as defined in the OpCo LLC Agreement).

Our Portfolio

As of November 30, 2017, our Portfolio consisted of interests in 946 MW of solar energy projects located entirely in the United States, all of which are operational. As of November 30, 2017, we owned interests in ten utility-scale solar energy projects representing 92% of the generating capacity of our Portfolio, and four C&I solar energy projects and a portfolio of residential DG Solar assets representing 8% of the generating capacity of our Portfolio. Our utility-scale and C&I solar energy projects sell their output under long-term, fixed-price offtake agreements primarily with investment grade offtake counterparties and our residential DG Solar assets are leased under long-term fixed-price offtake agreements with high credit quality residential customers with FICO scores averaging 765 at the time of the initial contract. As of November 30, 2017, the weighted average remaining life of offtake agreements across our Portfolio was 19.1 years.

For an overview of the assets that comprise our Portfolio as of November 30, 2017, please read Part I. Item 1. “Business.”

How We Generate Revenues

Under our Utility Project Entities’ offtake agreements, each Utility Project Entity generally receives a fixed price over the term of the offtake agreement with respect to 100% of its output, subject to certain adjustments. Our Utility Project Entities’ offtake agreements have certain availability or production requirements, and if such requirements are not met, then in some cases the applicable project is required to pay the offtake counterparty a specified damages amount, and in some cases the offtake counterparty has the right to terminate the offtake agreement or reduce the contract quantity. In addition, under our Utility Project Entities’ offtake agreements, each party typically has the right to terminate upon written notice ranging from ten to 60 days following the occurrence of an event of default that has not been cured within the applicable cure period, if any.

Under the offtake agreements of our C&I Project Entities, each C&I Project Entity generally receives a fixed price over the term of the offtake agreement with respect to 100% of its output, subject to certain adjustments. Certain of our C&I Project Entities’ offtake agreements have availability or production requirements, and if such requirements are not met, the offtake counterparty has the right to terminate the offtake agreement. Under our C&I Project Entities’ offtake agreements, each party typically has the right to terminate upon written notice ranging from ten to 30 days following the occurrence of an event of default that has not been cured within the applicable cure period, if any. One of our C&I Project Entities has additionally entered into an SREC Sales Agreement under which SRECs are sold to a non-affiliated party at a fixed price over the term of the agreement.

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Under our Residential Portfolio Project Entity’s offtake agreements, homeowners are obligated to make lease payments to the Residential Portfolio Project Entity on a monthly basis. The customer’s monthly payment is fixed based on a calculation that takes into account expected solar energy generation, and certain of our current offtake agreements contain price escalators with an average of a 1% increase annually. Customers are eligible to purchase the leased solar power systems to facilitate the sale or transfer of their home. The agreements also include an early buy-out option at fair market value exercisable in the seventh year that allows customers to purchase the solar power system.

How We Evaluate Our Operations

Our management uses a variety of financial metrics to analyze our performance. The key financial metrics we evaluate are Adjusted EBITDA and cash available for distribution.

Adjusted EBITDA.

We define Adjusted EBITDA as net income (loss) plus interest expense, net of interest income, income tax provision, depreciation, amortization and accretion, including our proportionate share of net interest expense, interest income, income taxes and depreciation, amortization and accretion from our unconsolidated affiliates that are accounted for under the equity method, and share-based compensation and transaction costs incurred for our acquisitions of projects; and excluding the effect of certain other non-cash or non-recurring items that we do not consider to be indicative of our ongoing operating performance such as, but not limited to, mark to market adjustments to the fair value of derivatives related to our interest rate hedges. Adjusted EBITDA is a non-U.S. GAAP financial measure. This measurement is not recognized in accordance with U.S. GAAP and should not be viewed as an alternative to U.S. GAAP measures of performance. The U.S. GAAP measure most directly comparable to Adjusted EBITDA is net income (loss). The presentation of Adjusted EBITDA should not be construed as an inference that our future results will be unaffected by unusual or non-recurring items.

We believe Adjusted EBITDA is useful to investors in evaluating our operating performance because securities analysts and other interested parties use such calculations as a measure of financial performance and borrowers’ ability to service debt. In addition, Adjusted EBITDA is used by our management for internal planning purposes including certain aspects of our consolidated operating budget and capital expenditures. It is also used by investors to assess the ability of our assets to generate sufficient cash flows to make distributions to our Class A shareholders.

However, Adjusted EBITDA has limitations as an analytical tool because it does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments, does not reflect changes in, or cash requirements for, working capital, does not reflect significant interest expense or the cash requirements necessary to service interest or principal payments on our outstanding debt or cash distributions on tax equity, does not reflect payments made or future requirements for income taxes, and excludes the effect of certain other cash flow items, all of which could have a material effect on our financial condition and results of operations. Adjusted EBITDA is a non-U.S. GAAP measure and should not be considered an alternative to net income (loss) or any other performance measure determined in accordance with U.S. GAAP, nor is it indicative of funds available to fund our cash needs. In addition, our calculations of Adjusted EBITDA are not necessarily comparable to EBITDA as calculated by other companies. Investors should not rely on these measures as a substitute for any U.S. GAAP measure, including net income (loss).

Cash Available for Distribution.

We use cash available for distribution, which we define as Adjusted EBITDA less equity in earnings of unconsolidated affiliates, cash interest paid, cash income taxes paid, maintenance capital expenditures, cash distributions to noncontrolling interests and principal amortization payments on any project-level indebtedness plus cash distributions from unconsolidated affiliates, indemnity payments and promissory notes from Sponsors, test electricity generation, cash proceeds from sales-type residential leases, state and local rebates and cash proceeds for reimbursable network upgrade costs. Our cash flow is generated from distributions we receive from OpCo each quarter. OpCo’s cash flow is generated primarily from distributions from the Project Entities. As a result, our ability to make distributions to our Class A shareholders depends primarily on the ability of the Project Entities to make cash distributions to OpCo and the ability of OpCo to make cash distributions to its unitholders.

We believe cash available for distribution is useful to investors in evaluating our operating performance because securities analysts and other interested parties use such calculations as a measure of our ability to generate sustainable distributions. In addition, when evaluating a potential acquisition, our management team projects expected cash available for distribution to determine whether to make such acquisition. The U.S. GAAP measure most directly comparable to cash available for distribution is net income (loss).

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However, cash available for distribution has limitations as an analytical tool because it does not capture the level of capital expenditures necessary to maintain the operating performance of our projects, does not include changes in operating assets and liabilities and excludes the effect of certain other cash flow items, all of which could have a material effect on our financial condition and results from operations. Cash available for distribution is a non-U.S. GAAP measure and should not be considered an alternative to net income (loss) or any other performance measure determined in accordance with U.S. GAAP, nor is it indicative of funds available to fund our cash needs. In addition, our calculations of cash available for distribution are not necessarily comparable to cash available for distribution as calculated by other companies. Investors should not rely on these measures as a substitute for any U.S. GAAP measure, including net income (loss).

The following table presents a reconciliation of net income (loss) to Adjusted EBITDA and cash available for distribution for fiscal 2017, fiscal 2016 and fiscal 2015:

	Year Ended						Eleven Months Ended
(in thousands)	November 30, 2017			November 30, 2016			November 30, 2015
Net income (loss)	$	39,245		$	12,910		$	(24,011	)
Add (Less):
Interest expense, net of interest income	22,299			10,870			390
Income tax provision	6,587			18,244			12,503
Depreciation, amortization and accretion	28,500			22,880			4,291
Share-based compensation	225			224			112
Acquisition-related transaction costs (1)	56			2,271			212
Selling, general and administrative (2)	—			—			6,372
Loss on cash flow hedges related to Quinto interest rate swaps	—			—			5,448
Loss on termination of residential financing obligations	—			—			6,477
Unrealized loss (gain) on derivatives (3)	(706		)	(1,508		)	611
Add proportionate share from equity method investments (4)
Interest expense, net of interest income	89			(524		)	(165		)
Depreciation, amortization and accretion	25,007			10,825			5,212
Adjusted EBITDA	$	121,302		$	76,192		$	17,452
Less:
Equity in earnings of unconsolidated affiliates, net with (4) above (5)	(68,475		)	(28,642		)	(14,102		)
Cash interest paid (6)	(22,195		)	(12,176		)	(4,502		)
Maintenance capital expenditures	(202		)	(50		)	—
Cash distributions to non-controlling interests	(9,453		)	(6,142		)	—
Short-Term Note (9)	(1,964		)	—			—
Add:
Cash distributions from unconsolidated affiliates (7)	80,287			30,129			10,902
Indemnity payment from Sponsors (8)	183			10,316			3,900
Short-Term Note (9)	—			—			1,964
Test electricity generation (10)	33			421			5,576
Cash proceeds from sales-type residential leases, net (11)	2,877			2,548			2,730
State and local rebates (12)	—			299			—
Cash proceeds for reimbursable network upgrade costs (13)	9,504			222			—
Cash available for distribution	$	111,897		$	73,117		$	23,920

(1) Represents acquisition-related financial advisory, legal and accounting fees associated with ROFO Project interests purchased and expected to be purchased by us in the future.

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(2) Represents the allocation of the Predecessor’s corporate overhead in selling, general and administrative expenses. Costs incurred by the Partnership as a result of the strategic evaluation of the proposed Mergers with Capital Dynamics performed by our Conflicts Committee totaling $2.1 million in fiscal 2017 was not excluded to calculate Adjusted EBITDA and cash available for distribution.

(3) Represents the changes in fair value of interest rate swaps that were not designated as cash flow hedges.

(4) Represents our proportionate share of net interest expense, depreciation, amortization and accretion from our unconsolidated affiliates that are accounted for under the equity method.

(5) Equity in earnings of unconsolidated affiliates represents the earnings from the Solar Gen 2 Project, the North Star Project, the Lost Hills Blackwell Project, the Henrietta Project, and the Stateline Project and is included on our consolidated statements of operations.

(6) Represents cash interest payments related to OpCo’s senior secured credit facility and the Stateline Promissory Note. The interest payments for the Quinto Credit Facility on the Predecessor’s combined carve-out financial statements were excluded as they were funded by one of our Sponsors.

(7) Cash distributions from unconsolidated affiliates represent the cash received by OpCo with respect to its 49% interest in the Solar Gen 2 Project, the North Star Project, the Lost Hills Blackwell Project, and the Henrietta Project and its 34% interest in the Stateline Project.

(8) Represents indemnity payments from the Sponsors owed to OpCo in accordance with the Omnibus Agreement. Please read Part II, Item 8. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 14—Related Parties.”

(9) Represents the Short-Term Note, a promissory note from First Solar. Please read Part II, Item 8. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 14—Related Parties.”

(10) For fiscal 2017, test electricity generation represents the sale of electricity that was generated prior to COD by the Macy's Maryland Project. For fiscal 2016, test electricity generation represents the sale of electricity that was generated prior to COD by the Kingbird Project. For fiscal 2015, test electricity generation represents the sale of electricity that was generated prior to COD by the Quinto Project, the RPU Project, the UC Davis Project and the Macy’s California Project. Solar power systems may begin generating electricity prior to COD as a result of the installation and interconnection of individual solar modules, which occurs over time during the construction and commission period. The sale of test electricity generation is accounted for as a reduction in the asset carrying value rather than operating revenue prior to COD, even though it generates cash for the related Project Entity.

(11) Cash proceeds from sales-type residential leases, net, represent gross rental cash receipts for sales-type leases, less sales-type revenue and lease interest income that is already reflected in net income (loss) during the period. The corresponding revenue for such leases was recognized in the period in which such lease was placed in service, rather than in the period in which the rental payment was received, due to the characterization of these leases under U.S. GAAP.

(12) State and local rebates represent cash received from state or local governments for owning certain solar power systems. The receipt of state and local rebates is accounted for as a reduction in the asset carrying value rather than operating revenue.

(13) Cash proceeds from a utility company related to reimbursable network upgrade costs associated with the Quinto Project and the Kingbird Project.

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Significant Factors and Trends Affecting Our Business

We expect the following factors will affect our results of operations:

Future Acquisitions

Our business could be impacted by a number of factors and trends that affect our industry generally and our Sponsors sepcificaclly, including our ability to acquire projects in the future. The evolving nature of the solar industry has enabled our Sponsors’ strategies of recycling capital faster and more efficiently by selling projects at a stage of construction and development which is earlier than best suited for us. Due to our higher cost of capital and inability to access the capital markets on a consistent basis, commencing in fiscal 2016, we and our Sponsors agreed to make several adjustments to the projects subject to the ROFO Agreements, replacing interests in certain projects with alternatives. Later, when certain projects were ultimately offered to us under the ROFO Agreement, we were unable to transact due to these same fiscal constraints. The offered projects were subsequently acquired by third party buyers at purchase prices higher than those offered to us. As a result of such adjustments, we no longer have a right of first offer on any projects developed by First Solar. The SunPower ROFO Agreement currently includes assets that represent interests in 304 MW capacity as of November 30, 2017. However, due to the limitations on our ability to acquire projects under the Merger Agreement, in connection with the Conflicts Committee’s and the Board’s approval of the Merger Agreement, we agreed to enter into the Waiver Agreement with SunPower which waives our right of first offer on all the projects subject to the SunPower ROFO Agreement during the pendency of the Merger Agreement. In the event that the Merger Agreement terminates without the closing of the Mergers, the waiver would terminate with respect to all projects subject to the SunPower ROFO Agreement, except, with respect to individual projects still owned by SunPower at the termination of such waiver, such project is either under an exclusivity agreement with a third party or has an offer for purchase from a third party pursuant to which SunPower is in negotiations.

In addition, the development of solar energy projects by project developers, including our Sponsors, may be delayed or otherwise adversely affected by the recent imposition of safeguard tariffs on imported solar cells and modules. On November 13, 2017, the U.S. International Trade Commission (“USITC”) transmitted a report to the President on its investigation under Section 202 of the Trade Act of 1974 with respect to imports of CSPV cells, whether or not partially or fully assembled into other products (“CSPV products”), in which USITC reached an affirmative determination that CSPV products are being imported into the United States in such increased quantities as to be a substantial cause of serious injury to the relevant domestic industry. In response to the USITC report, on January 23, 2018, the President issued Proclamation 9693, “To Facilitate Positive Adjustment to Competition From Imports of Certain Crystalline Silicon Photovoltaic Cells (Whether or Not Partially or Fully Assembled Into Other Products) and for Other Purposes” (the “Proclamation”). With limited exception, the Proclamation mandates the application of safeguard tariffs for the next four years, beginning February 7, 2018, on imports of CSPV products from all countries, except for developing countries that are World Trade Organization members, with the following terms: a tariff of 30 percent in the first year, 25 percent in the second year, 20 percent in the third year, and 15 percent in the fourth year. (However, the first 2.5 gigawatts of imported solar cells are exempt from the safeguard tariff in each of those four years.). The uncertainty surrounding the potential effect of the safeguard tariffs on imported CSPV products may cause market volatility, price fluctuations, supply shortages and project delays, adversely affecting our ability to acquire such projects. Please read Part I, Item 1A. “Risk Factors-Risks Related to Our Business-SunPower’s failure to complete the development of the SunPower ROFO Projects or project developers’, including our Sponsors’, failure to develop other solar energy projects, including those opportunities that are part of our Sponsors’ development pipeline, could have a significant effect on our ability to grow.”

Power Purchase Agreements

Our revenues are a function of the volume of electricity generated and sold by our projects and rental payments under lease agreements. The assets in our Portfolio sell substantially all of their output or are leased under long-term, fixed price offtake agreements primarily with investment grade utility-scale and C&I offtakers, as well as high credit quality residential customers with an average FICO score of 765 at the time of initial contract. As of November 30, 2017, the weighted average remaining life of offtake agreements across our Portfolio was 19.1 years, with the offtake agreements of our Utility Project Entities having remaining terms ranging from 15.3 to 26.1 years and our C&I offtake agreements and residential offtake agreements having remaining terms ranging from 14.8 to 19.2 years. We believe long-term agreements with creditworthy customers substantially mitigate volatility in our cash flows. As of November 30, 2017, two offtake counterparties were placed on CreditWatch by Standard & Poor’s Ratings Services, increasing our credit risk associated with these customers. Please read Part I, Item 1A. “Risk Factors—Risks Related to Our Business—We rely on a limited number of offtake counterparties and we are exposed to the risk that they are unwilling or unable to fulfill their contractual obligations to us or that they otherwise terminate their offtake agreements with us.”

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Operation of Projects

Our revenues are a function of the volume of electricity generated by our projects during a particular period, which is impacted by the number of systems that have achieved commercial operations, as well as both scheduled and unexpected repair and maintenance required to keep our systems operational. Equipment performance represents the primary factor affecting our operating results because equipment downtime impacts the volume of the electricity that we are able to generate from our systems.

Demand for Solar Energy

United States energy demand is increasing due to economic development and population growth. With exposure to volatile fossil fuel costs, increasing concern about carbon emissions and a variety of other factors, customers are seeking alternatives to traditional sources of electricity generation. However, the demand for solar energy could change at any time, especially as a result of changes to government regulations and policies that may present technical, regulatory, and economic barriers to the purchase and use of solar power products, a decline in commodity prices, including the price of natural gas, or a change in the federal, state, or local policies regulating natural gas, coal, oil and other fossil fuels, which could lower prices for fuel sources used to produce energy from other technologies and reduce the demand for solar energy. For more information about the risks associated with changing demand for solar energy, please read Part I, Item 1A. “Risk Factors—If solar energy technology is not suitable for widespread adoption at economically attractive rates of return, or if sufficient additional demand for solar power systems does not develop or takes longer to develop than we anticipate, our ability to acquire accretive projects may decrease.”

Government Incentives

Our Portfolio benefits from certain federal, state and local incentives designed to promote the development and use of solar energy. These incentives include accelerated tax depreciation, ITCs, RPS programs and net metering policies. These incentives make the development of solar energy projects more competitive by providing tax credits and accelerated depreciation for a portion of the development and construction costs, decreasing the costs associated with developing and building such projects. In addition, these incentives create demand for renewable energy assets through RPS programs and the reduction or removal of these incentives may diminish the market for future solar energy offtake agreements and reduce the ability for solar developers to compete for future solar energy offtake agreements. A loss or reduction in such incentives could decrease the attractiveness of solar energy projects to developers, including our Sponsors, which could reduce our acquisition opportunities. For example, the ITC, a federal income tax credit for 30% of eligible basis, is scheduled to fall to 26% of eligible basis for solar projects that commence construction during 2020, 22% of eligible basis for solar projects that commence construction during 2021 and 10% of eligible basis for solar projects that commence construction during 2022 or thereafter or are placed into service on or after January 1, 2024.

Under the “Protecting Americans From Tax Hikes Act of 2015,” which was signed into law December 18, 2015, owners of eligible solar equipment can claim bonus depreciation for qualified property acquired and placed in service during 2015 through 2019. The bonus depreciation percentage is 50% of the tax depreciable basis for property placed in service during 2015 through September 27, 2017. On December 22, 2017, the 2017 Tax Act was signed into law, which increased the bonus depreciation percentage to 100% for qualified property acquired and placed in service after September 27, 2017 and before January 1, 2023, and phases down to 80% in 2023, 60% in 2024, 40% in 2025, 20% in 2026 and 0% for 2027 and thereafter. The competitive advantage provided by the change in bonus depreciation percentage under the 2017 Tax Act could be negatively impacted by both the permanent reduction in the U.S. federal corporate income tax rate effective January 1, 2018, as this reduction could diminish the capacity of potential investors to benefit from incentives and reduce the value of accelerated depreciation deductions, and the imposition of safeguard tariffs on CSPV products pursuant to the Proclamation, which could materially increasing the price of solar products in the future.

The current administration’s proposed environmental policies may create regulatory uncertainty in the clean energy sector, including the solar energy sector, and may lead to a reduction or removal of various clean energy programs and initiatives designed to curtail climate change. For more information about the risks associated with these government incentives, please read Part I, Item 1A. “Risk Factors—Risks Related to Our Business—Government regulations providing incentives and subsidies for solar energy could change at any time, including pursuant to the proposed environmental and tax policies of the current administration” and “Risk Factors—Risks Related to Our Business—Until we can effectively utilize tax benefits, we expect to be dependent on the availability of third-party tax equity financing arrangements, which may not be available in the future.”

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The projects in our Portfolio are generally unaffected by the trends discussed above, given that all of the electricity to be generated by our projects are sold under fixed-price offtake agreements, which, as of November 30, 2017, have a weighted average remaining life of approximately 19.1 years.

Items Affecting the Comparability of Our Financial Results

Change in Fiscal Year.    On June 24, 2015, in connection with the closing of the IPO, we amended our partnership agreement to include a change in the fiscal year to November 30. The Predecessor had a 52-to-53 week fiscal year that ended on the Sunday closest to December 31. The accompanying consolidated financial statements cover the period from December 1, 2016 through November 30, 2017, representing the entire twelve-month period of our 2017 fiscal year. The prior year’s comparable periods cover the period from December 1, 2015 to November 30, 2016, representing the entire twelve-month period of our 2016 fiscal year, and the period from December 29, 2014 through November 30, 2015, representing the eleven-month period of our adopted 2015 fiscal year.

As a result of the change in our fiscal year end, the annual and quarterly periods of our newly adopted fiscal year do not coincide with the historical quarterly periods previously reported by our Predecessor. Financial information for the period from December 1, 2014 to November 30, 2015 has not been included in this Form 10-K for the following reasons: (i) the eleven months ended November 30, 2015 provides as meaningful a comparison to the years ended November 30, 2017 and November 30, 2016 as would the year ended November 30, 2015; (ii) we believe that there are no significant factors, seasonal or other, that would impact the comparability of information if the results for the year ended November 30, 2015 was presented in lieu of results for the eleven months ended November 30, 2015; and (iii) it was not practicable or cost justified to prepare this information.

The Predecessor’s Combined Carve-Out Financial Statements. Our fiscal 2015 consolidated financial statements include the Predecessor’s historical combined carve-out financial statements for activity prior to our June 24, 2015 IPO. The Predecessor’s historical combined carve-out financial statements represent only the IPO SunPower Project Entities, as the IPO First Solar Project Entities were acquired at the closing of our IPO. Results of operations of the Predecessor mainly relate to our Residential Portfolio, which represents less than 5% of the assets in our Portfolio. Prior to the IPO on June 24, 2015, none of the Predecessor’s utility-scale and C&I solar energy projects had commenced operation. The Predecessor’s historical combined carve-out financial statements additionally differ from those subsequent to the IPO in that they include (i) SG&A overhead costs, estimated and allocated by SunPower, which were subsequently replaced by fixed annual fees under MSAs with our Sponsors in connection with our IPO; (ii) indebtedness for the Quinto Project, which was paid off in connection with the closing of our IPO, and two residential financing agreements with third-party investors, both of which have been terminated; and (iii) the effect of the federal Section 1603 cash grant program, an expired program which we no longer benefit from.

Critical Accounting Policies & Estimates

We prepare our consolidated financial statements in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the amounts of assets, liabilities, revenues and expenses recorded in our financial statements. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the 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 and conditions. In addition to our most critical estimates discussed below, we also have other key accounting policies that are less subjective and, therefore, judgments involved in their application would not have a material impact on our reported results of operations. Please read Part II, Item 8. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 2—Summary of Significant Accounting Policies.”

Revenue Recognition

Operating revenues to date are comprised of revenues generated from PPAs, solar power systems leased to residential customers, lease revenue from the Maryland Solar Project and net revenue from the sale and delivery of SRECs. Under our lease arrangements, we are the lessor while the PPA offtaker, residential customers and an affiliate of First Solar are the lessees.

Operating leases:    Under long-term PPAs, revenue is generated from the sale of energy to various non-affiliated parties. Amounts are recognized as revenue based on rates stipulated in the respective PPAs when energy and any related renewable energy attributes are delivered. All PPAs, except for those associated with the Macy’s Maryland Project, are accounted for as operating leases. In addition, we also recognize lease revenue for the Maryland Solar Project, which is subject to a solar lease agreement that expires on December 31, 2019, with an affiliate of First Solar as the lessee.

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Certain residential leased solar power systems are classified as operating leases; therefore, revenue associated with renting the solar power system and executory costs is recognized on a straight-line basis over the 20-year lease term. State or local rebates defined in the minimum lease payments under the lease that are deemed fixed and determinable are recorded as deferred revenue in the consolidated balance sheets when the lease is placed in service and amortized to revenue on a straight-line basis over the 20-year lease term. PBI Rebates representing contingent revenue are recognized upon cash receipt.

Sales-type leases:    For residential systems classified as sales-type leases, the NPV of the minimum lease payments, net of executory costs, was recognized as revenue when the lease was placed in service. This NPV, as well as the systems residual value, is recorded as financing receivables in the consolidated balance sheets. The difference between the initial net and gross amounts is amortized to revenue over the lease term using the effective interest method. Revenue representing executory costs to operate and maintain the leased solar power system is recognized on a straight-line basis over the 20-year lease term. All of the leases in our Residential Portfolio were placed into service before fiscal 2015. Accordingly, only interest revenue and related O&M revenue associated with sales-type leases was recognized in fiscal 2017, fiscal 2016, and fiscal 2015.

Accounts Receivable and Financing Receivable

Accounts receivable:    Accounts receivable are reported on the consolidated balance sheets at the outstanding invoiced amounts, adjusted for any write-offs and estimated allowance for doubtful accounts. We maintain an allowance for doubtful accounts based on the expected collectability of all accounts receivable, which takes into consideration an analysis of historical bad debts, specific customer creditworthiness and current economic trends. Qualified customers under the residential lease program are required to have a minimum “fair” FICO credit score at the time of initial contract. We believe that its concentration of credit risk is limited because of its large number of residential customers, high credit quality of the residential customer base with high average FICO credit scores at the time of initial contract, small account balances for most of these residential customers and customer geographic diversification. As of both November 30, 2017 and November 30, 2016, less than $0.1 million allowance for doubtful accounts related to operating leases had been recorded.

Financing receivables:    Leases are classified as either operating or sales-type leases in accordance with the relevant accounting guidance. Financing receivables are generated by solar power systems leased to residential customers under sales-type leases. Financing receivables represent gross minimum lease payments to be received from customers and the systems’ estimated residual value, net of executory costs, unearned income and allowance for estimated losses.

We recognize an allowance for losses on financing receivables in an amount equal to the probable losses, net of recoveries, and base such reserves on several factors, including consideration of historical credit losses. As of both November 30, 2017 and November 30, 2016, $0.7 million had been recorded as allowance for losses on financing receivables.

Long-Lived Assets

We evaluate our long-lived assets, including property and equipment and projects for impairment whenever events or changes in circumstances indicate the carrying value of such assets may not be recoverable. Factors considered important that could result in an impairment review of leased solar power systems include credit rating downgrades below investment grade, reports of substantial uncertainty as to ability to continue as a going concern, lease asset depreciation expense greater than associated operating revenue, decrease in the estimated residual value of the leased solar power system and inability to collect lease payments due from lessees whether through aging receivables, lease contract amendments or terminations. The impairment evaluation of leased solar power systems includes an analysis of estimated future undiscounted net cash flows expected to be generated by the assets over their remaining estimated useful lives. If the estimate of future undiscounted net cash flows is insufficient to recover the carrying value of the assets over the remaining estimated useful lives, we record an impairment loss in the amount by which the carrying value of the assets exceeds the fair value. Fair value is generally measured based on discounted cash flow analysis.

With respect to solar energy projects, we consider the project commercially viable if it is anticipated to be operated for a profit once it is fully operating. We examine a number of factors to determine if the project will be profitable, including the pricing of the offtake agreement and whether there are any environmental, ecological, permitting, or regulatory conditions that have changed for the project since the start of development. Such changes could cause the cost of the project to increase.

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Fair Value of Financial Instruments

Fair value is estimated by applying the following hierarchy, which prioritizes the inputs used to measure fair value into three levels and bases the categorization within the hierarchy upon the lowest level of input that is available and significant to the fair value measurement (observable inputs are the preferred basis of valuation):

• Level 1—Valuations based on quoted prices in active markets for identical assets or liabilities that we have the ability to access. Since valuations are based on quoted prices that are readily and regularly available in an active market, valuation of these products does not entail a significant degree of judgment.

• Level 2—Measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. Financial assets utilizing Level 2 inputs include our derivative financial instruments. The selection of a particular technique to value a derivative depends upon the contractual term of, and specific risks inherent with, the instrument as well as the availability of pricing information in the market. We generally use similar techniques to value similar instruments. Valuation techniques utilize a variety of inputs, including contractual terms, market prices, yield curves, credit curves and measures of volatility.

• Level 3—Prices or valuations that require management inputs that are both significant to the fair value measurement and unobservable. We did not have any assets and liabilities measured at fair value on a recurring basis requiring Level 3 inputs.

Asset Retirement Obligations

In some cases we operate certain projects under power purchase and other agreements that include a requirement for the removal of the solar power systems at the end of the term of the agreement. We account for such legal obligations or AROs in accordance with U.S. GAAP, which requires that a liability for the fair value of an ARO be recognized in the period in which it is incurred if it can be reasonably estimated with the offsetting, associated asset retirement cost capitalized as part of the carrying amount of the property and equipment. The asset retirement cost is subsequently allocated to expense using a systematic and rational method over the asset’s estimated useful life. We have accrued AROs of $15.0 million and $13.4 million as of November 30, 2017 and November 30, 2016, respectively.

Noncontrolling Interests

Noncontrolling interests represent the portion of net assets in consolidated subsidiaries that are not attributable, directly or indirectly, to us. The largest portion of noncontrolling interest in us relates to the Sponsors’ ownership in OpCo. In addition, we have entered into certain tax equity transactions with third-party investors under which the investors are determined to hold noncontrolling interests in entities fully consolidated by OpCo. The net assets of the shared entities are attributed to the controlling and noncontrolling interests based on the terms of the governing contractual arrangements. Therefore, for the tax equity transactions, we further determined the HLBV Method to be the appropriate method for attributing net assets to the controlling and noncontrolling interests as this method most closely mirrors the economics of the governing contractual arrangements. Under the HLBV Method, we allocate recorded income (loss) to each investor based on the change, during the reporting period, of the amount of net assets each investor is entitled to under the governing contractual arrangements in a liquidation scenario. We account for the portion of net assets using the HLBV Method in the consolidated entities attributable to the investors as “Redeemable noncontrolling interests” and “Noncontrolling interests” in our consolidated financial statements. Noncontrolling interests in subsidiaries that are redeemable at the option of the noncontrolling interest holder are classified as “Redeemable noncontrolling interests in subsidiaries” between liabilities and equity on the consolidated balance sheets and the balance is the greater of the carrying value calculated under the HLBV Method or the redemption value. 

Business Combinations

We record all assets and liabilities acquired in a business combination at fair value. The judgments made in the context of the purchase price allocation can materially impact our future results of operations. Accordingly, for significant acquisitions, we obtain assistance from third-party valuation specialists. The valuations calculated from estimates are based on information available at the acquisition date. We charge acquisition-related transaction costs that are not part of the consideration to operating costs and expenses as they are incurred. These costs typically include financial advisory, legal and accounting fees.

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Income Taxes

We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of the differences between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. Valuation allowances are provided against deferred tax assets when management cannot conclude that it is more likely than not that some portion or all deferred tax assets will be realized. On December 22, 2017, the 2017 Tax Act was signed into law, which enacted major changes to the U.S. federal income tax laws, including a permanent reduction in the U.S. federal corporate income tax rate. Please read Part II, Item 8. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 17—Subsequent Events” for further details.

The calculation of tax liabilities involves dealing with uncertainties in the application of complex tax regulations. We have elected to be treated as a corporation for federal income tax purposes, and we recognize potential liabilities for anticipated tax audit issues in the United States based on our estimate of whether, and the extent to which, additional taxes will be due. If payment of these amounts ultimately proves to be unnecessary, the reversal of the liabilities would result in tax benefits being recognized in the period in which we determine the liabilities are no longer necessary. If the estimate of tax liabilities proves to be less than the ultimate tax assessment, a further charge to expense would result. We accrue interest and penalties on tax contingencies, which are not considered material.

We recognize deferred tax assets to the extent that we believe these assets are more likely than not to be realized. In making such a determination, we consider all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning strategies and results of recent operations. If we determine that we would be able to realize our deferred tax assets in the future in excess of their net recorded amount, we would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.

We record uncertain tax positions on the basis of a two-step process whereby (1) we determine whether we are more likely than not that the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions that meet the more-likely-than-not recognition threshold, we recognize the largest amount of tax benefit that is more than 50 percent likely to be realized upon ultimate settlement with the related tax authority.

Recent Accounting Pronouncements

Please read Part II, Item 8. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 2—Summary of Significant Accounting Policies” in this Annual Report on Form 10-K for a description of recently issued accounting pronouncements, including the expected dates of adoption and estimated effects on our results of operations, financial positions and cash flows.

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Results of Operations

	Year Ended						Eleven Months Ended
	November 30, 2017			November 30, 2016			November 30, 2015
Revenues:
Operating revenues	$	70,089		$	61,198		$	10,660
Total revenues	70,089			61,198			10,660
Operating costs and expenses:
Cost of operations	8,450			6,959			2,624
Cost of operations—SunPower, prior to IPO	—			—			468
Selling, general and administrative	9,732			7,003			10,702
Depreciation and accretion	28,070			22,792			4,291
Acquisition-related transaction costs	56			2,271			212
Total operating costs and expenses	46,308			39,025			18,297
Operating income (loss)	23,781			22,173			(7,637		)
Other expense (income):
Interest expense	23,497			12,081			1,860
Interest income	(1,198		)	(1,203		)	(1,470		)
Other expense (income)	(971		)	(1,518		)	12,536
Total other expense, net	21,328			9,360			12,926
Income (loss) before income taxes and equity in earnings of unconsolidated investees	2,453			12,813			(20,563		)
Income tax provision	(6,587		)	(18,244		)	(12,503		)
Equity in earnings of unconsolidated investees	43,379			18,341			9,055
Net income (loss)	39,245			12,910			(24,011		)
Less: Predecessor loss prior to IPO on June 24, 2015	—			—			(20,095		)
Net income (loss) subsequent to IPO	39,245			12,910			(3,916		)
Less: Net income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests	27,838			(14,191		)	(22,642		)
Net income attributable to 8point3 Energy Partners LP Class A shares	$	11,407		$	27,101		$	18,726

Twelve Months Ended November 30, 2017 Compared to the Twelve Months Ended November 30, 2016 and Eleven Months Ended November 30, 2015

Revenues

	Year Ended				Eleven Months Ended
(in thousands)	November 30, 2017		November 30, 2016		November 30, 2015
Operating revenues	$	70,089	$	61,198	$	10,660
Total revenues	$	70,089	$	61,198	$	10,660

Over 90% of our operating revenues were comprised of lease revenue from our utility-scale solar energy projects, C&I solar energy projects and Residential Portfolio. Our only revenue streams not from the leasing of solar power systems are from the PPA and SREC Sales Agreement entered into by the Macy's Maryland Project Entity and contracted counterparties and PBI Rebates. Revenue generated from our Residential Portfolio represents (i) revenue associated with renting solar power systems classified as operating leases, including related state or local rebates and PBI Rebates, and (ii) interest revenue and related O&M revenue associated with solar power systems classified as sales-type leases. All revenues for the periods presented were generated in the United States.

Total revenues increased by $8.9 million, or 15%, during fiscal 2017 as compared to fiscal 2016 due to (i) revenue generated from the Macy’s Maryland Project, the Kern Phase 2(a) Assets, the Kern Phase 2(b) Assets and the Kern 2(c) Assets, which commenced operations in fiscal 2017 and (ii) net revenue recognized under the SREC Sales Agreement. Total revenues

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increased by $50.5 million, or 474%, for fiscal 2016 as compared to fiscal 2015, due to the commencement of operations of the IPO Project Entities as of the fourth quarter of fiscal 2015 and revenues generated from the Kern Phase 1(a) Assets, the Kern Phase 1(b) Assets, the Kingbird Project and the Hooper Project which were acquired and operational in fiscal 2016.

Operating Costs and Expenses

	Year Ended						Eleven Months Ended
(in thousands)	November 30, 2017			November 30, 2016			November 30, 2015
Cost of operations	$	8,450		$	6,959		$	2,624
Cost of operations—SunPower, prior to IPO	—			—			468
Selling, general and administrative	9,732			7,003			10,702
Depreciation and accretion	28,070			22,792			4,291
Acquisition-related transaction costs	56			2,271			212
Total operating costs and expenses	$	46,308		$	39,025		$	18,297
Total operating costs and expenses as a percentage of revenues	66.1		%	63.8		%	171.6		%

Cost of Operations: Cost of operations primarily includes expenses related to O&M agreements and land lease expenses post IPO. The Predecessor’s cost of operations includes costs related to system output performance warranty and residential lease system repairs accrual and reserves for upfront rebate receivables.

The increase of $1.5 million, or 21%, for fiscal 2017 as compared to fiscal 2016 was primarily driven by: (i) increased expenses associated with operating the solar power systems due to the Macy's Maryland Project, the Kern Phase 2(a) Assets, Kern Phase 2(b) Assets and Kern Phase 2(c) Assets, which commenced operations in fiscal 2017, and (ii) costs associated with the purchase and delivery of SRECs.

The increase of $4.3 million, or 165%, for fiscal 2016 as compared to fiscal 2015 is primarily driven by: (i) $5.4 million of increased expenses associated with operating the solar power systems due to the commencement of operations of the IPO Project Entities in the fourth quarter of fiscal 2015 and the Kern Phase 1(a) Assets, the Kern Phase 1(b) Assets, the Kingbird Project and the Hooper Project acquired in fiscal 2016; and (ii) the reclassification of Quinto land lease expense of $0.9 million from SG&A expense by the Predecessor prior to IPO to cost of operations post-IPO. These increases were partially offset by the Predecessor’s expenses during the first quarter of 2015 that were not recorded in 2016, relating to: (i) a $1.3 million reserve for aged rebates receivable; (ii) a $0.5 million accrual for system output performance warranty and residential lease system repairs; and (iii) a $0.2 million accrual for a performance guarantee settlement.

Cost of Operations—SunPower, prior to IPO: Cost of operations—SunPower, prior to IPO, represents executory costs that were allocated to the Predecessor by SunPower. Costs incurred for these services were $0.5 million for fiscal 2015.

Selling, General and Administrative:SG&A expense includes (i) post-IPO operating expenses such as audit, legal, insurance, independent board of directors and fees under the AMAs and MSAs with our Sponsors; (ii) charges that were incurred by SunPower that were specifically identified as attributable to the Predecessor pre-IPO; and (iii) an allocation of SunPower operating expenses based on the proportional level of effort attributable to the operation of the Predecessor’s portfolio of solar power systems leased to residential homeowners and solar energy projects under construction. The allocated SunPower operating expenses include asset management, legal, accounting, tax, treasury, information technology, insurance, employee benefit costs, human resources, procurement and other corporate services and infrastructure costs.

The increase of $2.7 million, or 39%, for fiscal 2017 as compared to fiscal 2016 was driven by $2.1 million of expenses incurred by the Partnership as a result of the strategic evaluation of the proposed Mergers with Capital Dynamics performed by our Conflicts Committee and $0.6 million additional expenses associated with operating the solar power systems for the Macy's Maryland Project, the Kern Phase 2(a) Assets, the Kern Phase 2(b) Assets and the Kern Phase 2(c) Assets, which commenced operations in fiscal 2017.

The decrease of $3.7 million, or 35%, for fiscal 2016 as compared to fiscal 2015 was due to higher SG&A expenses in fiscal 2015 primarily driven by: (i) $4.8 million allocated SunPower operating expenses based on the proportional level of effort attributable to the Quinto Project, the RPU Project, the UC Davis Project and the Macy’s California Project under construction; (ii) $1.6 million of allocated costs incurred by SunPower related to our IPO; and (iii) $0.9 million of Quinto land lease expenses; partially offset by $3.6 million higher SG&A expenses in fiscal 2016 comprised of normal operating

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expenditures including fees associated with the MSAs and AMAs as well as audit, consulting, legal, insurance and independent board of director services.

Depreciation and Accretion: Depreciation expense reflects costs associated with depreciation of our solar power system assets that have been placed in service.The Predecessor received federal cash grants for the construction of the residential leased solar power systems. The benefit of the cash grants is recorded as a reduction to the carrying value of the operating lease assets and is subsequently amortized as a reduction to depreciation expense.

The increase of $5.3 million, or 23%, for fiscal 2017 as compared to fiscal 2016 was primarily driven by the commencement of operations, and related depreciation, of the Macy’s Maryland Project, the Kern Phase 2(a) Assets, the Kern Phase 2(b) Assets and the Kern Phase 2(c) Assets, which commenced operations in fiscal 2017.

The increase of $18.5 million, or 431%, for fiscal 2016 as compared to fiscal 2015 is a result of the commencement of operations, and related depreciation, of the IPO Project Entities in the fourth quarter of fiscal 2015 and the Kern Phase 1(a) Assets, the Kern Phase 1(b) Assets, the Kingbird Project and the Hooper Project in fiscal 2016.

Acquisition-Related Transaction Costs: Acquisition-related transaction costs represent financial advisory, legal and accounting fees incurred in connection with our acquisitions. The decrease of $2.2 million, or 98%, for fiscal 2017 as compared to fiscal 2016 was primarily driven by fewer acquisitions in fiscal 2017 as compared to fiscal 2016. In fiscal 2017, acquisition-related transaction costs included fees in connection with the Kern Phase 2(b) Acquisition in February 2017 and Kern Phase 2(c) Acquisition in June 2017. In fiscal 2016, acquisition-related transaction costs included fees in connection with the Kern Phase 1(a) Acquisition in January 2016, the Kingbird Acquisition (as defined below) in March 2016, the Hooper Acquisition in April 2016, the Macy's Maryland Acquisition in July 2016, the Kern Phase 1(b) Acquisition in September 2016 and the Kern Phase 2(a) Acquisition in November 2016. Transaction costs associated with acquiring all phases of the Kern Project were primarily incurred in connection with the Kern Purchase Agreement dated as of January 26, 2016. The increase of $2.1 million, or 971%, for fiscal 2016 as compared to fiscal 2015 was primarily driven by increased acquisition activity in 2016 as summarized above. In fiscal 2015, acquisition-related transaction costs included fees in connection with the anticipated acquisition of the Kern Project.

Other Expense, net

	Year Ended						Eleven Months Ended
(in thousands)	November 30, 2017			November 30, 2016			November 30, 2015
Interest expense	$	23,497		$	12,081		$	1,860
Interest income	(1,198		)	(1,203		)	(1,470		)
Other expense (income)	(971		)	(1,518		)	12,536
Total other expense, net	$	21,328		$	9,360		$	12,926
Total other expense, net as a percentage of revenues	30.4		%	15.3		%	121.3		%

Interest Expense: Loans and letters of credit outstanding under the senior secured credit facility bear interest and the unused portion of the credit facility bear commitment fees which are cash interest expenses. Please read Part II, Item 8. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 8—Debt and Financing Obligations” for rates and borrowing activity. The interest incurred related to our projects while under construction is not reflected as an expense in the consolidated statements of operations, as it is capitalized to construction-in-progress until the solar power system is ready for its intended use.

Cash interest expense for fiscal 2017 relates to fees associated with outstanding borrowings and letters of credit under OpCo’s $775.0 million senior secured credit facility and the Stateline Promissory Note. Cash interest expense for fiscal 2016 relates to fees associated with outstanding borrowings and letters of credit under OpCo’s $775.0 million senior secured credit facility. Cash interest expense for fiscal 2015 relates to fees associated with the $300.0 million term loan facility, letters of credit, as well as financing fees due to two third-party investors for undrawn commitment of the financing arrangements described below.

Interest expense for fiscal 2017, fiscal 2016 and fiscal 2015 included cash interest expense of $22.5 million, $11.5 million and $0.5 million, respectively. Cash interest expense increased$11.1 million, or 97% in fiscal 2017 compared to fiscal 2016, due to the Stateline Promissory Note issued on December 1, 2016, as well as fees associated with the drawdown of our $250.0 million incremental term loan facility and additional drawdowns under our $200.0 million revolving credit facility. Cash

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interest expense increased $11.0 million in fiscal 2016 compared to fiscal 2015, due to additional borrowings under OpCo's senior secured credit facility to fund project acquisitions, as well as the debt being outstanding for the full year in fiscal 2016 compared to half the year in fiscal 2015.

Non-cash interest expense for fiscal 2017 and fiscal 2016 relates to debt issuance costs associated with OpCo’s senior secured credit facility. Non-cash interest expense for fiscal 2015 relates to debt issuance costs associated with OpCo’s senior secured credit facility and two financing arrangements under which leased solar power systems were financed by two third-party investors.

The Predecessor terminated one residential lease financing obligation in January 2015 and the remaining obligation in May 2015. Under the terms of these financing arrangements, the investors provided upfront payments to the Predecessor, for which the Predecessor recognized as a financing obligation that was reduced over the specified term of the arrangement as customer receivables and federal cash grants were received by the third-party investors. Non-cash interest expense was recognized on the consolidated statement of operations using the effective interest rate method calculated at a rate of approximately 14-15% during the first half of fiscal 2015.

Interest expense for fiscal 2017, fiscal 2016 and fiscal 2015 included non-cash interest expense of $1.0 million, $0.6 million and $1.3 million, respectively. Non-cash interest expense increased$0.4 million, or 57%, in fiscal 2017 as compared fiscal 2016, due to the debt issuance costs associated with the Joinder Agreement under OpCo’s existing senior secured credit facility in September 2016. Non-cash interest expense decreased $0.7 million, or 54%, in fiscal 2016 as compared to fiscal 2015, due to the Predecessor terminating one residential lease financing obligation in January 2015 and the remaining obligation in May 2015.

Interest Income:  Interest income represents the accrued interest on reimbursable network upgrade costs related to the Quinto Project and the Kingbird Project. These costs plus accrued interest are reimbursable by the applicable utility company over five years from when the project achieves commercial operation. Interest income was $1.2 million, $1.2 million and $1.5 million for fiscal 2017, fiscal 2016 and fiscal 2015, respectively.

Other Expense (Income): Other income for fiscal 2017 of $1.0 million primarily relates to (i) a $0.7 million mark-to-market valuation adjustment of interest rate swaps associated with our term loan facility; (ii) $0.2 million energy performance test bonus received for one of our equity method investments; and (iii) $0.1 million for performance guarantees under our O&M agreements with Sponsors. Other income for fiscal 2016 relates to the mark-to-market valuation adjustment of interest rate swaps associated with our term loan facility. Other expense for fiscal 2015 included: (i) a $6.5 million loss on termination of the residential lease financing obligation (further described below); (ii) a $5.4 million loss on cash flow hedges associated with the Predecessor (further described below); and (iii) a $0.6 million mark-to-market valuation adjustment of interest rate swaps associated with our term loan facility.

Loss on termination of financing obligation: In January 2015, the Predecessor entered into an agreement with one of the residential lease financing third-party investors that terminated the financing obligation arrangement. In conjunction with the termination of the arrangement, the Predecessor paid $10.8 million to terminate the $10.1 million outstanding financing obligation. In May 2015, the Predecessor entered into a termination agreement with the remaining third-party investor, paying $29.0 million to terminate the $21.1 million outstanding financing obligation and $1.9 million accrued financing fee. During fiscal 2015, $6.5 million was recognized as a loss on termination within other expense, net in the consolidated statements of operations.

Loss on cash flow hedges associated with Predecessor: The Predecessor entered into interest rate swap agreements, designated as cash flow hedges, in the fourth quarter of fiscal 2014 on the outstanding and forecasted future borrowings under the Quinto Credit Facility to reduce the impact of changes in interest rates. The Predecessor assessed the effectiveness of these cash flow hedges at inception and on a quarterly basis. If it was determined that a derivative instrument was not highly effective or the transaction was no longer deemed probable of occurring, the Predecessor discontinued hedge accounting and recognized the ineffective portion in current period earnings. The hedge became ineffective in the first half of fiscal 2015 and the ineffective portion was recognized in earnings at that time. The interest swap was terminated upon the IPO and the remaining ineffective portion was recognized in earnings. During fiscal 2015, $5.4 million was reclassified into loss on cash flow hedges within other expense, net in the consolidated statements of operations.

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Income Tax Provision

	Year Ended						Eleven Months Ended
(in thousands)	November 30, 2017			November 30, 2016			November 30, 2015
Income tax provision	$	6,587		$	18,244		$	12,503
Income tax provision as a percentage of revenues	9.4		%	29.8		%	117.3		%

Our tax rate is primarily affected by the tax impact of equity in earnings, the tax impact of noncontrolling interest and state tax rates (net of federal benefit) in various jurisdictions, most significantly California. We include the income tax provision related to our equity in earnings of unconsolidated investees in the income tax provision line of the consolidated statements of operations.

Our income tax provision post IPO primarily represents deferred federal and state taxes on the net income of OpCo, a non-taxable partnership, that is allocated to us (exclusive of income tax but after noncontrolling interest).

The decrease in income tax provision as a percentage of revenues for fiscal 2017 of 9.4%, compared to 29.8% for fiscal 2016, is the result of (i) recognition of deferred tax assets for ITCs allocated to us under tax equity financing facilities; and (ii) lower income before income taxes for fiscal 2017 of $2.5 million compared to income before income taxes of $12.8 million for fiscal 2016.

The decrease in income tax provision as a percentage of revenues for fiscal 2016 of 29.8%, compared to 117.3% for fiscal 2015, is the result of an increase in revenue of $50.5 million, partially offset by income before income taxes for fiscal 2016 of $12.8 million compared to losses before income taxes of $20.6 million for fiscal 2015.

Equity in Earnings of Unconsolidated Investees

	Year Ended						Eleven Months Ended
(in thousands)	November 30, 2017			November 30, 2016			November 30, 2015
Equity in earnings of unconsolidated investees	$	43,379		$	18,341		$	9,055
Equity in earnings of unconsolidated investees as a percentage of revenues	61.9		%	30.0		%	84.9		%

Equity in earnings of unconsolidated investees represents our proportionate share of the earnings and losses from our minority membership interests accounted for as equity method investments, including SG2 Holdings, North Star Holdings, Lost Hills Blackwell Holdings, Henrietta Holdings and Stateline Holdings. We own a 49% ownership interest in each of SG2 Holdings, North Star Holdings, Lost Hills Blackwell Holdings and Henrietta Holdings and a 34% ownership interest in Stateline Holdings.

The increase of $25.0 million, or 137%, in fiscal 2017 as compared to fiscal 2016 is primarily due to the acquisition of Henrietta Holdings and Stateline Holdings in September 2016 and December 2016, respectively. The increase of $9.3 million, or 103% in fiscal 2016 as compared to fiscal 2015 is due to the acquisition of SG2 Holdings, North Star Holdings and Lost Hills Blackwell Holdings on June 24, 2015.

Net Income (loss) Attributable to Noncontrolling Interests and Redeemable Noncontrolling Interests

	Year Ended						Eleven Months Ended
(in thousands)	November 30, 2017			November 30, 2016			November 30, 2015
Net income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests	$	27,838		$	(14,191	)	$	(22,642	)
Net income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests as a percentage of net revenues	39.7		%	(23.2		)%	(212.4		)%

We apply the HLBV Method in allocating recorded net income (loss) to each tax equity investor based on the change during the reporting period of the amount of net assets of the entity to which each tax equity investor would be entitled to under the governing contractual arrangements in a liquidation scenario. If the redemption value of our redeemable noncontrolling interests exceeds their carrying value after attribution of income (loss) under the HLBV Method in any period, we will make an

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additional attribution of income to our redeemable noncontrolling interests such that their carrying value will at least equal the redemption value.

Net income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests for fiscal 2017, 2016 and 2015 included a net loss of $6.5 million, $126.4 million and $102.2 million, respectively, attributable to noncontrolling interests and redeemable noncontrolling interests related to our tax equity financing facilities with third-party investors under which the parties invest in entities that hold the solar power systems, offset by net income of $34.3 million, $112.2 million and $79.6 million, respectively, attributable to our Sponsors as a result of their economic ownership in OpCo.

Liquidity and Capital Resources

Our liquidity as of November 30, 2017 was $88.9 million, consisting of $13.5 million cash on hand and $75.4 million of available capacity under our five-year revolving credit facility.

Sources of Liquidity

We expect our ongoing sources of liquidity to include cash on hand, cash generated from operations (excluding cash distributions to minority investors), distributions from the operations of our equity investments, borrowings under new and existing financing arrangements (the aggregate amount of which may be lower because of our reduced ownership in projects subject to tax equity financing) and the issuance of additional equity securities as appropriate given market conditions. We may also incur debt at the project level, which may be limited by the rights of our tax equity investors and current debt covenants. We expect that these sources of funds will be adequate to provide for our short-term and long-term liquidity needs. Our ability to meet our debt service obligations and other capital requirements, including capital expenditures, as well as make 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.

We believe that we will have sufficient borrowings available under our revolving credit facility, liquid assets and cash flows from operations to meet our financial commitments, debt service obligations, contingencies and anticipated required capital expenditures for at least the next 12 months. Additionally, we have an active shelf registration statement filed with the Securities and Exchange Commission for the issuance of additional equity securities as appropriate given market conditions.

Term Loans, Delayed Draw Term Loan, Revolving Credit Facility and Stateline Promissory Note

On June 5, 2015, OpCo entered into a $525.0 million credit facility, consisting of a $300.0 million term loan facility, a $25.0 million delayed draw term loan facility and a $200.0 million revolving credit facility. OpCo borrowed $300.0 million under the term loan facility on June 5, 2015, which indebtedness will mature on June 5, 2020, at which point all amounts outstanding under the credit facility will become due and payable. On April 6, 2016, the parties thereto amended the credit facility (i) to provide for the lenders’ consent to the Omnibus Agreement, (ii) to expand OpCo’s ability to further amend the Omnibus Agreement without lender consent in the future, subject to certain conditions, (iii) to permit certain customary restrictions on transfers of the equity interests of certain Project Entities, which are jointly owned, indirectly, by OpCo and SunPower, (iv) to supplement the Pledge and Security Agreement between the parties in light of the foregoing amendment and (v) to make certain clarifying modifications to definitions and cross references. On September 30, 2016, OpCo entered into the Joinder Agreement under its existing senior secured credit facility, pursuant to which OpCo obtained a new $250.0 million incremental term loan facility, increasing the maximum borrowing capacity under the credit facility to $775.0 million.

Loans outstanding under the credit facility bear interest at either (i) a base rate, which is the highest of (x) the federal funds rate plus 0.50%, (y) the administrative agent’s prime rate and (z) one-month LIBOR, in each case, plus an applicable margin; or (ii) one-, two-, three- or six-month LIBOR plus an applicable margin. There will be no principal amortization over the term of the credit facility. The unused portion of the revolving credit facility and delayed draw term loan facility is subject to a commitment fee of 0.30% per annum. OpCo may prepay the borrowings under the term loan facility and the delayed draw term loan facility at any time. OpCo has entered into interest rate swap agreements to hedge the interest rate on a portion of the borrowings under the term loan facility. For more details, please read “Please Part II, Item 8. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 9—Fair Value.”

In general, the credit facility contains representations, warranties, covenants (including financial covenants) and defaults that are customary for this type of financing; provided, however, that OpCo is permitted to pay distributions to its unitholders and we are permitted to pay distributions to our shareholders out of available cash so long as no default or event of default under the credit facility has occurred or is continuing at the time of such distribution, or would result therefrom, and OpCo is otherwise in compliance, on a pro forma basis, with the facility’s covenants requiring it to maintain its debt to cash flow ratio

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and debt service coverage ratio (as such financial ratios are described below). Among other things, events of defaults that could result in restrictions on our ability to make such distributions include certain failures to make payments when due under the credit facility, certain defaults under other agreements, breaches of certain covenants and representations under the credit facility, commencement of certain insolvency proceedings, the existence of certain judgments or attachments, certain orders of dissolution of loan parties, certain events relating to employee benefit plans, the occurrence of a change of control (as more fully described below), certain events relating to the effectiveness and validity of the guaranties and collateral documents in support of the credit facility (as described below) and other credit documents and, under certain circumstances, the termination of the Omnibus Agreement or the Quinto PPA. In the future, we may increase our debt to fund our operations or future acquisitions.

OpCo’s credit facility also contains covenants requiring us to maintain the following financial ratios: (i) a debt to cash flow ratio of not more than (a) 6.00 to 1.00 for the fiscal quarters ending November 30, 2016 through November 30, 2017, and (b) 5.50 to 1.00 for each fiscal quarter ending thereafter; and (ii) a debt service coverage ratio (as more fully described in the credit facility) of not less than 1.75 to 1.00. In addition, an event of default occurs under the credit facility upon a change of control. The credit facility defines a change of control as occurring when, among other things, (i) the Sponsors (or either of them) cease to direct the management, directly or indirectly, of us or OpCo, or (ii) the Sponsors collectively cease to own 35% of the economic interest in OpCo. On February 5, 2018, we, our general partner, OpCo, Holdings and the other parties thereto entered into the Merger Agreement. Upon the terms and subject to the conditions set forth in the Merger Agreement, immediately after the consummation of OpCo Merger 1, the credit facility will be repaid in full and extinguished. In addition, the credit facility contains customary non-financial covenants and certain restrictions that will limit our, OpCo’s and certain of our domestic subsidiaries’ ability to, among other things, incur or guarantee additional debt and to make distributions on or redeem or repurchase OpCo common units. The Joinder Agreement amended OpCo’s credit facility to permit OpCo to incur up to $50.0 million in subordinated indebtedness from First Solar or its affiliate to pay a portion of the purchase price for the Stateline Project. As of November 30, 2017, we were in compliance with our debt covenants.

OpCo’s credit facility is collateralized by a pledge over the equity of OpCo and certain of its subsidiaries. We and each of OpCo’s subsidiaries, other than certain non-guarantor subsidiaries, have guaranteed the obligations of OpCo under the credit facility.

On December 1, 2016, in connection with the Stateline Acquisition, OpCo issued the Stateline Promissory Note to First Solar in the principal amount of $50.0 million. The Stateline Promissory Note is unsecured and matures on the date that is six months after the maturity date under OpCo’s credit facility. Interest will accrue at a rate of 4.00% per annum, except it will accrue at a rate of 6.00% per annum (i) upon the occurrence and during the continuation of a specified event of default and (ii) in respect of amounts accrued as payments-in-kind pursuant to the terms of the Stateline Promissory Note.

As of November 30, 2017, OpCo had outstanding borrowings of $300.0 million under the term loan facility, $250.0 million under the incremental term loan facility, $25.0 million under the delayed draw term loan facility, $70.0 million under the revolving credit facility, approximately $54.6 million of letters of credit outstanding under the revolving credit facility and $49.6 million principal amount of the Stateline Promissory Note. The $75.4 million remaining portion of the revolving credit facility is undrawn as of November 30, 2017.

ATM Program

On January 30, 2017, we established the ATM Program, under which we may sell our Class A shares from time to time through the ATM Agents up to an aggregate sales price of $125.0 million. We may also sell our Class A shares to any ATM Agent, as principal for its own account, at a price agreed upon at the time of the sale. We will use the net proceeds from sales under the ATM Program to purchase a number of common units in OpCo equal to the number of Class A shares issued under the ATM Program. OpCo may use the proceeds for general corporate purposes, which may include, among other things, repaying borrowings under the Stateline Promissory Note and OpCo’s credit facilities and funding working capital or acquisitions. No shares were issued under the ATM Program during fiscal 2017.

Tax Equity

Our projects are, and our future acquisitions are expected to be, subject to two types of tax equity financing. In the first type of tax equity financing, the governing agreements provide, and the governing agreements of our future acquisitions may provide, our tax equity investors with a number of minority investor protection rights with respect to the applicable asset or assets that have been financed with tax equity, including restricting the ability of the entity that owns such asset or assets to incur debt. To the extent we want to incur project-level debt at a project in which we co-invest with a tax equity investor, we may be required to obtain the tax equity investor’s consent prior to such incurrence. In addition, the amount of debt that could

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be incurred by an entity in which we have a tax equity co-investor may be further constrained because even if the tax equity investor consents to the incurrence of the debt at the entity or project level, the tax equity investor may not agree to pledge its interest in the project which could reduce the amount that can be borrowed and raise the cost of borrowing by the entity.

In the second type of tax equity financing, the governing agreements provide, and the governing agreements of our future acquisitions may provide, our tax equity investors with a majority interest in the project. In such agreements, we will only have a number of minority investor protection rights with respect to the applicable asset or assets that have been financed with tax equity, including restricting the ability of the entity that owns such asset or assets to incur debt. In most cases, since we are not the majority owner, we will not be able to direct the actions of the entity that owns such asset. As such, we may not be able to incur debt at the entity or project level, without the consent of the majority owner.

Uses of Liquidity

Our principal requirements for liquidity and capital resources, other than for operating our business, can generally be categorized into the following: (i) debt service obligations; (ii) funding acquisitions, if any; and (iii) cash distributions to shareholders. Generally, once COD is reached, solar power generation assets do not require significant capital expenditures to maintain operating performance.

Cash Flows

A summary of the sources and uses of cash and cash equivalents is as follows:

	Year Ended						Eleven Months Ended
(in thousands)	November 30, 2017			November 30, 2016			November 30, 2015
Net cash provided by operating activities	$	88,668		$	54,636		$	1,836
Net cash used in investing activities	(280,996		)	(272,001		)	(219,016		)
Net cash provided by financing activities	191,595			174,845			273,961

Operating Activities

Net cash provided by operating activities for fiscal 2017 was $88.7 million and was primarily the result of: (i) net income of $39.2 million; (ii) $43.4 million in cash distributions received from equity method investees that were classified in operating activities as returns on the investments; (iii) adjustment for non-cash charges of $36.4 million, including $28.5 million depreciation of operating lease assets and solar power systems and amortization of intangible assets, $6.6 million deferred income taxes, $1.0 million amortization of debt issuance costs and $0.2 million share-based compensation; (iv) $3.8 million decrease in accounts receivable and financing receivable, net; (v) $7.8 million decrease in prepaid expenses and other current assets; and (vi) $2.1 million increase in accounts payable and other accrued liabilities. These inflows were partially offset by adjustments for non-cash income of $44.1 million, including $43.4 million equity in earnings of unconsolidated investees and $0.7 million mark-to-market gain on interest rate swaps.

Net cash provided by operating activities for fiscal 2016 was $54.6 million and was primarily the result of: (i) $18.1 million in cash distributions received from equity method investees that were classified in operating activities as returns on the investments; (ii) net income of $12.9 million; (iii) adjustments for non-cash charges of $42.3 million, including $22.9 million depreciation of operating lease assets and solar power systems, $18.2 million deferred income taxes expense, $0.2 million share-based compensation, $0.6 million amortization of debt issuance costs and $0.4 million bad debt expense related to residential lease customers; (iv) $1.2 million increase in accounts payable and other accrued liabilities; and (v) $1.5 million decrease in accounts receivable and short-term financing receivables, net. These inflows were partially offset by: (i) adjustments for non-cash income of $19.8 million, including $18.3 million equity in earnings of unconsolidated investees and $1.5 million mark-to-market gain on interest rate swaps; (ii) $0.1 million decrease in deferred revenue from the Maryland Solar Project; and (iii) $1.4 million increase in prepaid expenses and other current assets.

Net cash provided by operating activities for fiscal 2015 was $1.8 million and was primarily the result of: (i) $6.8 million of cash distributions from unconsolidated investees; (ii) adjustments for non-cash charges of $26.8 million, including a $12.5 million charge for deferred income taxes, $6.5 million loss upon termination of residential financing arrangement, $4.3 million depreciation of operating lease assets and solar power systems, $1.3 million reserve for rebates receivable, $1.2 million interest expense for the financing arrangement of residential leased solar power systems prior to termination, $0.6 million mark-to-market loss on interest rate swaps, $0.1 million of share-based compensation expense and $0.3 million bad debt expense related to residential lease customers; (iii) a $5.4 million increase in accounts payable and other accrued liabilities; (iv)

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a $0.1 million decrease in accounts receivable and financing receivables, cash grants and rebates receivable; and (v) a $0.2 million decrease in solar power systems to be leased. This was partially offset by: (i) a net loss of $24.0 million; (ii) a $9.1 million non-cash adjustment for equity in earnings of unconsolidated investees; (iii) a $4.3 million increase in prepaid and other current assets, related to capitalized expenses incurred by the Predecessor for our initial public offering; and (iv) a $0.1 million decrease in deferred revenue.

Investing Activities

Net cash used in investing activities for fiscal 2017 was $281.0 million and was primarily the result of: (i) $317.6 million net cash paid for the acquisitions of the Stateline Project, the Kern 2(b) Assets and the Kern 2(c) Assets (including $0.4 million repayment of the Stateline Promissory Note and $28.4 million net cash for the purchase price payable to SunPower for Macy's Maryland Project and all phases of the Kern Project, which were funded by tax equity investors); and (ii) capital expenditures of $0.3 million, which were primarily due to the purchases of property and equipment associated with the Kingbird Project. These outflows were offset by $36.9 million in distributions from unconsolidated investees classified in investing activities as returns of the investments.

Net cash used in investing activities for fiscal 2016 was $272.0 million and was primarily the result of $284.8 million net cash paid for the acquisitions of the Kern Phase 1(a) Assets, the Kern Phase 1(b) Assets, the Kern Phase 2(a) Assets, the Kingbird Project, the Hooper Project, the Macy’s Maryland Project and the Henrietta Project. These outflows were partially offset by $11.6 million of cash distributions from unconsolidated investees classified in investing activities as returns of the investments and $1.2 million of net cash provided by purchases of property and equipment, which primarily consists of collections of test energy billings.

Net cash used in investing activities for fiscal 2015 was $219.0 million, and was the result of $223.7 million related to cash payments for interest expenses on our $300.0 million term loan facility as well as costs incurred by the Predecessor associated with solar energy projects under construction, net with cash proceeds from sale of electricity that is generated prior to COD by the Quinto Project, the RPU Project, the UC Davis Project and the Macy’s California Project, partially offset by $4.7 million of cash distributions from unconsolidated investees.

Financing Activities

Net cash provided by financing activities for fiscal 2017 was $191.6 million due to: (i) a $250.0 million draw down under the incremental term loan facility in connection with the Stateline Acquisition; (ii) a $34.0 million draw down under the revolving credit facility; and (iii) $28.4 million of cash contributions from tax equity investors. These cash inflows were partially offset by: (i) $53.1 million of cash distributions to our Sponsors as OpCo’s common and subordinated unitholders; (ii) $29.3 million of cash distributions to our Class A shareholders; (iii) $9.5 million of cash distributions to tax equity investors; (iv) $27.0 million in repayments of outstanding amounts under our revolving credit facility; and (v) the repayment of $2.0 million for the Short-Term Note to First Solar.

Net cash provided by financing activities for fiscal 2016 was $174.8 million and was primarily the result of: (i) $113.3 million in proceeds from issuance of Class A shares, net of issuance costs; (ii) $86.6 million in proceeds from issuance of bank loans, net of issuance costs, including $63.0 million from the revolving credit facility and $25.0 million from the delayed draw term loan facility; (iii) $10.0 million in capital contributions from SunPower as an indemnity per the Omnibus Agreement for a short-fall associated with reimbursable costs for the Quinto Project network upgrade; and (iv) $3.7 million of cash contributions from tax equity investors. These cash inflows were partially offset by: (i) $20.2 million of cash distributions to our Class A shareholders; (ii) $12.3 million of cash distributions to our Sponsors as OpCo’s common and subordinated unitholders; and (iii) $6.2 million of cash distributions to tax equity investors.

Net cash provided by financing activities for fiscal 2015 was $274.0 million due to: (i) $393.8 million in proceeds from issuance of Class A shares, net of issuance costs; (ii) $461.2 million in proceeds from issuance of bank loans, net of issuance costs from our term loan facility as well as a financing arrangement for the Quinto Solar Project; (iii) $341.7 million in capital contributions from SunPower to fund the IPO SunPower Project Entities before the IPO; (iv) $203.7 million in cash contributions from noncontrolling interests associated with our tax equity financing arrangements; and (v) $2.0 million in proceeds received from the issuance of the Short-Term Note to First Solar. These cash inflows were partially offset by: (i) $371.5 million of cash distribution to SunPower as a Sponsor in connection with the IPO; (ii) $283.7 million of cash distribution to First Solar as a Sponsor in connection with the IPO; (iii) $264.1 million repayment of bank loans to terminate two residential lease financing arrangements prior to the IPO; (iv) $3.2 million of capital distributions to SunPower; (v) $202.7 million of cash distribution to SunPower for the remaining purchase price payments of initial projects; and (vi) $3.1 million of cash distributions to shareholders.

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Contractual Obligations

The following table summarizes our contractual obligations as of November 30, 2017:

			Payments Due by Period
(in thousands)	Total		2018		2019-2020		2021-2022		Beyond 2022
Land use commitments (1)	$	62,951	$	1,329	$	3,428	$	3,604	$	54,590
Term loan (2)	325,345		9,210		316,135		—		—
Incremental term loan (3)	271,774		8,491		263,283		—		—
Delayed draw term loan facility (4)	27,177		849		26,328		—		—
Revolving credit facility (4)	76,096		2,377		73,719		—		—
Stateline Promissory Note (5)	55,768		4,192		8,383		43,193		—
Total contractual obligations	$	819,111	$	26,448	$	691,276	$	46,797	$	54,590

(1) Land use commitments primarily relate to a non-cancellable operating lease for the Quinto Project and two operating leases for the Kingbird Project, and are equal to the minimum lease and easement payments to landowners for the right to use the land upon which solar power systems are located.

(2) Includes $300.0 million of borrowings outstanding under the term loan facility entered into by OpCo on June 5, 2015 (in connection with our IPO) which will mature on or about June 5, 2020, at which point all amounts outstanding under the term loan facility will become due. From December 1, 2017 to August 31, 2018, which is the remaining term of the interest rate swaps, the interest payments for the notional amount of $250.0 million and $40.0 million are calculated based on the fixed swap rate of 0.85% plus the 2% margin and 1.16% plus the 2% margin, respectively. The interest payments for the remaining $10.0 million notional amount through August 31, 2018, and the full amount of $300.0 million outstanding thereafter through the maturity date, are estimated based on the floating cash interest rate of approximately 3.35% per annum effective as of November 30, 2017.

(3) Includes $250.0 million of borrowings outstanding under the incremental term loan facility entered into by OpCo on September 30, 2016 (in connection with the Joinder Agreement under its existing senior secured credit facility) which will mature on or about June 5, 2020, at which point all amounts outstanding under the incremental term loan facility will become due. The interest payments for the $250.0 million notional amount through the maturity date are estimated based on the floating cash interest rate of approximately 3.35% per annum effective as of November 30, 2017.

(4) Includes $25.0 million of borrowings outstanding under the delayed draw term loan facility and $70.0 million of borrowings outstanding under the revolving credit facility entered into by OpCo on June 5, 2015, which will mature on or about June 5, 2020, at which point all amounts outstanding under the delayed draw term loan facility and the revolving credit facility will become due. The interest payments for the $95.0 million notional amount through the maturity date are estimated based on the floating cash interest rate of approximately 3.35% per annum effective as of November 30, 2017.

(5) Includes $49.6 million of borrowings outstanding under the Stateline Promissory Note by OpCo to First Solar which will mature on December 5, 2020. Interest payments are estimated based on a rate of 4.00% per annum.

Off-Balance-Sheet Arrangements

As of November 30, 2017, we did not have any significant off-balance-sheet arrangements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

We are exposed to several market risks in our normal business activities. Market risk is the potential loss that may result from market changes associated with our business or with an existing or forecasted financial or commodity transaction. The types of market risks to which we are exposed include credit risk and interest rate risk. Any market risk sensitive instruments that we have entered into are for hedging purposes, rather than for speculative trading.

91

Credit Risk

Credit risk relates to the risk of loss resulting from non-performance or non-payment by offtake counterparties under the terms of their contractual obligations, thereby impacting the amount and timing of expected cash flows. We monitor and manage credit risk through credit policies that include the use of credit mitigation measures such as having a diversified portfolio of offtake counterparties. However, there are a limited number of offtake counterparties under our offtake agreements, which offtake counterparties are entities engaged in the energy industry, and this concentration may impact the overall exposure to credit risk, either positively or negatively, in that the offtake counterparties may be similarly affected by changes in economic, industry or other conditions. If any of these offtake agreement customers’ receivable balances in the future should be deemed uncollectible, it could have a material adverse effect on our forecasted cash flows. As of November 30, 2017 and November 30, 2016, two offtake counterparties were placed on CreditWatch by Standard & Poor’s Ratings Services, increasing our credit risk associated with these customers. Please read Part I, Item 1A. “Risk Factors—We rely on a limited number of offtake counterparties and we are exposed to the risk that they are unwilling or unable to fulfill their contractual obligations to us or that they otherwise terminate their offtake agreements with us” and “Please Part II, Item 8. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 14—Related Parties—Maryland Solar Lease Arrangement.”

Credit risk under the residential lease program is limited because customers are required to have a minimum FICO credit score at the time of initial contract, the existing customer base is of high credit quality with an average FICO credit score of 765 at the time of initial contract, the program has a large number of customers with small account balances for each, and the customers are diversified geographically within the United States. As of November 30, 2017, we do not believe we had significant credit risk under the residential lease program.

Credit risk also relates to the risk of loss resulting from non-performance or non-payment by our Sponsors under the terms of their contractual obligations, including indemnity, reimbursement and other payment obligations under the Omnibus Agreement, thereby impacting the amount and timing of expected cash flows. Our ability to mitigate such risk with respect to the Sponsors is limited. Please read Part I, Item 1A. “Risk Factors—Risks Related to Our Business—We are exposed to the credit risk of our Sponsors, and any deterioration of our Sponsors’ creditworthiness could adversely affect our business, our credit ratings and our overall risk profile.”

Interest Rate Risk

We are exposed to interest rate risk because we depend on debt financing to purchase our projects. An increase in interest rates could make it difficult for us to obtain the financing necessary to purchase our projects on favorable terms, or at all, and thus reduce revenue and adversely impact our operating results. An increase in interest rates could lower our return on investment in a project and adversely impact our operating results. This risk is significant to our business because our financial condition is highly sensitive to interest rate fluctuations and the availability of credit, and would be adversely affected by increases in interest rates or liquidity constraints.

Our interest expense would increase to the extent interest rates rise in connection with our variable interest rate borrowings. As of November 30, 2017, the outstanding principal balance of our variable interest borrowings was $645.0 million of which $355.0 million is unhedged. An immediate 10% increase in interest rates would have an increase of approximately $0.5 million of annualized interest expense on our consolidated financial statements. This increase was mitigated by interest rate swaps that we entered into on August 31, 2016 and January 5, 2017 in connection with our term loan facility, which covered $250.0 million and $40.0 million, respectively, of the $645.0 million outstanding principal balance. Our interest rate swaps will expire on August 31, 2018. As of November 30, 2017, our investment portfolio consisted of 100% in demand deposits.

In addition, increases in interest rates could adversely impact the price of our Class A shares, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels. As with other yield-oriented securities, our share price is impacted by our level of cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on the price of our Class A shares, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

92

Item 8. Financial Statements and Supplementary Data.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	94
Consolidated Balance Sheets as of November 30, 2017 and November 30, 2016	95
Consolidated Statements of Operations for the Year Ended November 30, 2017, the Year Ended November 30, 2016 and the Eleven Months Ended November 30, 2015	96
Consolidated Statements of Comprehensive Income (Loss) for the Year Ended November 30, 2017, the Year Ended November 30, 2016 and the Eleven Months Ended November 30, 2015	97
Consolidated Statements of Redeemable Noncontrolling Interests and Equity for the Year Ended November 30, 2017, the Year Ended November 30, 2016 and the Eleven Months Ended November 30, 2015	98
Consolidated Statements of Cash Flows for the Year Ended November 30, 2017, the Year Ended November 30, 2016 and the Eleven Months Ended November 30, 2015	99
Notes to Consolidated Financial Statements	100

93

Report of Independent Registered Public Accounting Firm

To the General Partner and Shareholders of 8point3 Energy Partners LP:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, comprehensive income (loss), redeemable noncontrolling interests and equity and cash flows present fairly, in all material respects, the financial position of 8point3 Energy Partners LP and its subsidiaries as of November 30, 2017 and November 30, 2016, and the results of their operations and their cash flows for each of the years ended November 30, 2017 and November 30, 2016 and the eleven months ended November 30, 2015 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

San Jose, California

February 5, 2018

94

8point3 Energy Partners LP

Consolidated Balance Sheets

(In thousands, except share data)

	November 30, 2017		November 30, 2016
Assets
Current assets:
Cash and cash equivalents	$	13,528	$	14,261
Accounts receivable and short-term financing receivables, net	5,572		5,401
Prepaid and other current assets1	16,990		15,745
Total current assets	36,090		35,407
Property and equipment, net	713,284		720,132
Long-term financing receivables, net	76,201		80,014
Investments in unconsolidated affiliates	768,258		475,078
Other long-term assets	15,372		24,432
Total assets	$	1,609,205	$	1,335,063
Liabilities and Equity
Current liabilities:
Accounts payable and other current liabilities1	$	4,394	$	23,771
Short-term debt and financing obligations1	2,229		1,964
Deferred revenue, current portion	1,025		870
Total current liabilities	7,648		26,605
Long-term debt and financing obligations1	689,847		384,436
Deferred revenue, net of current portion	123		308
Deferred tax liabilities	37,318		30,733
Asset retirement obligations	14,970		13,448
Other long-term liabilities	1,945		—
Total liabilities	751,851		455,530
Redeemable noncontrolling interests	17,346		17,624
Commitments and contingencies (Note 6)
Equity:
Class A shares, 28,088,673 and 28,072,680 issued and outstanding as of November 30, 2017 and November 30, 2016, respectively	249,363		249,138
Class B shares, 51,000,000 issued and outstanding as of November 30, 2017 and November 30, 2016	—		—
Accumulated earnings	4,595		22,440
Total shareholders' equity attributable to 8point3 Energy Partners LP	253,958		271,578
Noncontrolling interests	586,050		590,331
Total equity	840,008		861,909
Total liabilities and equity	$	1,609,205	$	1,335,063

¹The Partnership has related-party balances for transactions made with the Sponsors and tax equity investors. Related-party balances recorded within “Prepaid and other current assets” in the consolidated balance sheets were $0.7 million and $0.9 million as of November 30, 2017 and November 30, 2016, respectively. Related-party balances recorded within “Accounts payable and other current liabilities” in the consolidated balance sheets were $0.1 million and $19.7 million due to Sponsors as of November 30, 2017 and November 30, 2016, respectively, and $0.9 million and $1.0 million due to tax equity investors as of November 30, 2017 and November 30, 2016, respectively. Related-party balances recorded within “Short-term debt and financing obligations” and “Long-term debt and financing obligations” in the consolidated balance sheets were $2.2 million and $47.4 million, respectively, as of November 30, 2017, and $2.0 million and zero, respectively, as of November 30, 2016.

The accompanying notes are an integral part of these consolidated financial statements.

95

8point3 Energy Partners LP

Consolidated Statements of Operations

(In thousands, except per share data)

	Year Ended						Eleven Months Ended
	November 30, 2017			November 30, 2016			November 30, 2015
Revenues:
Operating revenues1	$	70,089		$	61,198		$	10,660
Total revenues	70,089			61,198			10,660
Operating costs and expenses1:
Cost of operations	8,450			6,959			2,624
Cost of operations—SunPower, prior to IPO	—			—			468
Selling, general and administrative	9,732			7,003			10,702
Depreciation and accretion	28,070			22,792			4,291
Acquisition-related transaction costs	56			2,271			212
Total operating costs and expenses	46,308			39,025			18,297
Operating income (loss)	23,781			22,173			(7,637		)
Other expense (income):
Interest expense	23,497			12,081			1,860
Interest income	(1,198		)	(1,203		)	(1,470		)
Other expense (income)	(971		)	(1,518		)	12,536
Total other expense, net	21,328			9,360			12,926
Income (loss) before income taxes and equity in earnings of unconsolidated investees	2,453			12,813			(20,563		)
Income tax provision	(6,587		)	(18,244		)	(12,503		)
Equity in earnings of unconsolidated investees	43,379			18,341			9,055
Net income (loss)	39,245			12,910			(24,011		)
Less: Predecessor loss prior to IPO on June 24, 2015	—			—			(20,095		)
Net income (loss) subsequent to IPO	39,245			12,910			(3,916		)
Less: Net income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests	27,838			(14,191		)	(22,642		)
Net income attributable to 8point3 Energy Partners LP Class A shares	$	11,407		$	27,101		$	18,726
Net income per Class A share:
Basic	$	0.41		$	1.27		$	0.94
Diluted	$	0.41		$	1.27		$	0.94
Distributions per Class A share:	$	1.04		$	0.91		$	0.16
Weighted average number of Class A shares:
Basic	28,079			21,420			20,002
Diluted	43,579			36,920			35,034

¹The Partnership has related-party activities for transactions made with the Sponsors. Related party transactions recorded within “Operating revenues” in the consolidated statement of operations were $5.2 million, $5.2 million and $2.3 million in fiscal 2017, 2016 and 2015, respectively. Related party transactions recorded within “Operating costs and expenses” in the consolidated statement of operations were $8.4 million, $7.0 million and $1.4 million in fiscal 2017, 2016 and 2015, respectively. Related party transactions recorded within “Other expense (income)” in the consolidated statement of operations were $0.3 million in fiscal 2017, and zero in both fiscal 2016 and 2015.

The accompanying notes are an integral part of these consolidated financial statements.

96

8point3 Energy Partners LP

Consolidated Statements of Comprehensive Income (Loss)

(In thousands, except share data)

	Year Ended					Eleven Months Ended
	November 30, 2017		November 30, 2016			November 30, 2015
Net income (loss)	$	39,245	$	12,910		$	(24,011	)
Other comprehensive income (loss):
Realized loss on cash flow hedges1	—		—			3,156
Total comprehensive income (loss)	39,245		12,910			(20,855		)
Less: Predecessor comprehensive loss prior to IPO on June 24, 2015	—		—			(16,939		)
Comprehensive income (loss) subsequent to IPO	39,245		12,910			(3,916		)
Less: comprehensive income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests	27,838		(14,191		)	(22,642		)
Comprehensive income attributable to 8point3 Energy Partners LP Class A shares	$	11,407	$	27,101		$	18,726

¹The realized loss on cash flow hedge relates to the Predecessor’s interest swap that was terminated upon closing of the IPO and the remaining ineffective portion was recognized in earnings during fiscal 2015.

The accompanying notes are an integral part of these consolidated financial statements.

97

8point3 Energy Partners LP

Consolidated Statements of Redeemable Noncontrolling Interests and Equity

(In thousands, except share data)

														Accumulated
	Redeemable			SunPower										Other						Total
	Noncontrolling			Investment			Class A Shares				Class B Shares			Comprehensive			Accumulated			Shareholders'			Noncontrolling			Total
	Interests			prior to IPO			Shares	Amount			Shares	Amount		Income (Loss)			Earnings			Equity			Interest			Equity
Balance as of December 28, 2014	$	—		$	130,666		—	$	—		—	$	—	$	(3,156	)	$	—		$	—		$	—		$	127,510
Predecessor loss prior to IPO	—			(20,095		)	—	—			—	—		—			—			—			—			(20,095		)
Contributions from SunPower	—			337,794			—	—			—	—		—			—			—			—			337,794
Distributions to SunPower	—			(3,163		)	—	—			—	—		—			—			—			—			(3,163		)
Net change in unrealized loss on cash flow hedges	—			—			—	—			—	—		3,156			—			—			—			3,156
Balance as of Balance as of June 24, 2015	—			445,202			—	—			—	—		—			—			—			—			445,202
Issuance by OpCo of OpCo common units, subordinated units and IDRs for contribution of SunPower Project Entities	—			(493,790		)	—	—			—	—		—			—			—			493,790			—
Predecessor's liabilities assumed by SunPower	—			48,588			—	—			—	—		—			—			—			—			48,588
Issuance by OpCo of OpCo common units, subordinated units and IDRs for acquisition of interests in First Solar Project Entities	—			—			—	—			—	—		—			—			—			408,820			408,820
Contributions from noncontrolling interests - tax equity investors	178,079			—			—	—			—	—		—			—			—			25,638			25,638
Distribution to Sponsors	—			—			—	—			—	—		—			—			—			(857,904		)	(857,904		)
Issuance of Class A shares at IPO, net of issuance costs	—			—			20,000,000	392,636			—	—		—			—			392,636			—			392,636
Issuance of Class B shares to First Solar	—			—			—	—			22,116,925	—		—			—			—			—			—
Issuance of Class B shares to SunPower	—			—			—	—			28,883,075	—		—			—			—			—			—
Share-based compensation	—			—			7,281	112			—	—		—			—			112			—			112
Contributions from SunPower	—			—			—	—			—	—		—			—			—			58,026			58,026
Cash distributions to Class A shareholders	—			—			—	—			—	—		—			(3,146		)	(3,146		)	—			(3,146		)
Net income (loss) subsequent to IPO	(88,332		)	—			—	—			—	—		—			18,726			18,726			65,688			84,414
Balance as of November 30, 2015	89,747			—			20,007,281	392,748			51,000,000	—		—			15,580			408,328			194,058			602,386
Noncontrolling interests obtained through acquisition	—			—			—	—			—	—		—			—			—			40,128			40,128
Cash and accrued distributions to noncontrolling interests - tax equity investors	(3,580		)	—			—	—			—	—		—			—			—			(3,574		)	(3,574		)
Issuance of Class A shares, net of issuance costs	—			—			8,050,000	113,325			—	—		—			—			113,325			—			113,325
Reclassification of noncontrolling interests due to issuance of Class A shares	—			—			—	(257,159		)	—	—		—			—			(257,159		)	257,159			—
Share-based compensation	—			—			15,399	224			—	—		—			—			224			—			224
Contributions from SunPower	—			—			—	—			—	—		—			—			—			9,973			9,973
Contributions from tax equity investors	—			—			—	—			—	—		—			—			—			50,507			50,507
Cash distributions to Class A shareholders	—			—			—	—			—	—		—			(20,241		)	(20,241		)	—			(20,241		)
Cash distributions to Sponsors as OpCo unitholders	—			—			—	—			—	—		—			—			—			(12,271		)	(12,271		)
Net income (loss)	(68,543		)	—			—	—			—	—		—			27,101			27,101			54,351			81,452
Balance as of November 30, 2016	17,624			—			28,072,680	249,138			51,000,000	—		—			22,440			271,578			590,331			861,909
Noncontrolling interests obtained through acquisition	—			—			—	—			—	—		—			—			—			1,736			1,736
Cash and accrued distributions to noncontrolling interests - tax equity investors	(3,561		)	—			—	—			—	—		—			—			—			(5,828		)	(5,828		)
Share-based compensation	—			—			15,993	225			—	—		—			—			225			—			225
Contributions from tax equity investors	—			—			—	—			—	—		—			—			—			28,388			28,388
Cash distributions to Class A shareholders	—			—			—	—			—	—		—			(29,252		)	(29,252		)	—			(29,252		)
Cash distributions to Sponsors as OpCo unitholders	—			—			—	—			—	—		—			—			—			(53,132		)	(53,132		)
Net income	3,283			—			—	—			—	—		—			11,407			11,407			24,555			35,962
Balance as of November 30, 2017	$	17,346		$	—		28,088,673	$	249,363		51,000,000	$	—	$	—		$	4,595		$	253,958		$	586,050		$	840,008

The accompanying notes are an integral part of these consolidated financial statements.

98

8point3 Energy Partners LP

Consolidated Statements of Cash Flows

(In thousands)

	Year Ended						Eleven Months Ended
	November 30, 2017			November 30, 2016			November 30, 2015
Cash flows from operating activities:
Net income (loss)	$	39,245		$	12,910		$	(24,011	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion	28,500			22,880			4,291
Unrealized loss (gain) on interest rate swap	(706		)	(1,508		)	611
Interest expense on financing obligation	—			—			1,193
Loss on termination of financing obligation	—			—			6,477
Reserve for rebates receivable	—			—			1,338
Distributions from unconsolidated investees	43,379			18,075			6,766
Equity in earnings of unconsolidated investees	(43,379		)	(18,341		)	(9,055		)
Deferred income taxes	6,585			18,242			12,491
Share-based compensation	225			224			112
Amortization of debt issuance costs	983			626			—
Other, net	131			370			328
Changes in operating assets and liabilities:
Accounts receivable and financing receivable, net	3,801			1,481			46
Cash grants receivable	—			—			146
Rebates receivable	—			—			(121		)
Solar power systems to be leased under sales type leases	—			—			197
Prepaid and other assets	7,827			(1,435		)	(4,258		)
Deferred revenue	(21		)	(59		)	(118		)
Accounts payable and other liabilities	2,098			1,171			5,403
Net cash provided by operating activities	88,668			54,636			1,836
Cash flows from investing activities:
Cash provided by (used in) purchases of property and equipment, net	(346		)	1,167			(223,688		)
Cash paid for acquisitions	(317,558		)	(284,797		)	—
Distributions from unconsolidated investees	36,908			11,629			4,672
Net cash used in investing activities	(280,996		)	(272,001		)	(219,016		)
Cash flows from financing activities:
Proceeds from issuance of Class A shares, net of issuance costs	—			113,325			393,750
Proceeds from issuance of bank loans, net of issuance costs	284,008			86,567			461,192
Proceeds from issuance of Short-Term Note to First Solar	—			—			1,964
Repayment of bank loans	(27,000		)	—			(264,143		)
Repayment of Short-Term Note to First Solar	(1,964		)	—			—
Capital contributions from SunPower	—			9,973			341,694
Capital distributions to SunPower	—			—			(3,163		)
Cash distribution to First Solar at IPO	—			—			(283,697		)
Cash distribution to SunPower at IPO	—			—			(371,527		)
Cash distribution to SunPower for the remaining purchase price payments of initial projects	—			—			(202,680		)
Cash distribution to Class A shareholders	(29,252		)	(20,241		)	(3,146		)
Cash distributions to Sponsors as OpCo unitholders	(53,132		)	(12,271		)	—
Cash contributions from noncontrolling interests and redeemable noncontrolling interests - tax equity investors	28,388			3,671			203,717
Cash distributions to noncontrolling interests and redeemable noncontrolling interests - tax equity investors	(9,453		)	(6,179		)	—
Net cash provided by financing activities	191,595			174,845			273,961
Net increase (decrease) in cash and cash equivalents	(733		)	(42,520		)	56,781
Cash and cash equivalents, beginning of period	14,261			56,781			—
Cash and cash equivalents, end of period	$	13,528		$	14,261		$	56,781
Non-cash transactions:
Assignment of financing receivables to a third-party financial institution	$	—		$	—		$	1,279
Property and equipment acquisitions funded by liabilities	—			19,538			—
Property and equipment additions funded by SunPower post-IPO	—			—			50,683
Settlement of related party payable by capital contribution from tax equity investor	—			46,837			—
Predecessor liabilities assumed by SunPower	—			—			48,588
Accrued distributions to noncontrolling interests and redeemable noncontrolling interests - tax equity investors	909			975			—
Issuance by OpCo of OpCo common units, subordinated units and IDRs for acquisition of interests in First Solar Project Entities	—			—			408,820
Issuance by OpCo of promissory note to First Solar in connection with the Stateline Acquisition	49,631			—			—
Supplemental disclosures:
Cash paid for interest, net of amounts capitalized	22,000			11,525			437

The accompanying notes are an integral part of these consolidated financial statements.

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements

Note 1. Description of Business

The Partnership

8point3 Energy Partners LP (together with its subsidiaries, the “Partnership”) is a limited partnership formed on March 3, 2015 under a master formation agreement by SunPower Corporation (“SunPower”) and First Solar, Inc. (“First Solar” and, together with SunPower, the “Sponsors”) to own, operate and acquire solar energy generation systems. The Partnership’s IPO was completed on June 24, 2015. 8point3 General Partner, LLC (the “General Partner”), the Partnership’s general partner, is a wholly owned subsidiary of 8point3 Holding Company, LLC, an entity owned by SunPower and First Solar (“Holdings”). As of November 30, 2017, 8point3 Energy Partners LP owned a controlling non-economic managing member interest in 8point3 Operating Company, LLC (“OpCo”) and a 35.5% limited liability company interest in OpCo and the Sponsors collectively owned a noncontrolling 64.5% limited liability company interest in OpCo.

On February 5, 2018, the Partnership, its general partner, OpCo and Holdings entered into the Merger Agreement with certain affiliates of Capital Dynamics. Please read “—Note 17—Subsequent Events” for further details.

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements— Continued

The following table provides an overview of the assets that comprise the Portfolio as of November 30, 2017:

Project	Location	Commercial Operation Date(1)	MW(ac) (2)	Counterparty	Remaining Term of Offtake Agreement (in years)(3)
Utility
Maryland Solar	Maryland	February 2014	20	FirstEnergy Solutions	15.3
Solar Gen 2	California	November 2014	150	San Diego Gas & Electric	22.0
Lost Hills Blackwell	California	April 2015	32	City of Roseville/Pacific Gas and Electric	26.1	(4)
North Star	California	June 2015	60	Pacific Gas and Electric	17.6
RPU	California	September 2015	7	City of Riverside	22.8
Quinto	California	November 2015	108	Southern California Edison	18.0
Hooper	Colorado	December 2015	50	Public Service Company of Colorado	18.1
Kingbird	California	April 2016	40	Southern California Public Power Authority(5)	18.4
Henrietta	California	October 2016	102	Pacific Gas and Electric	18.8
Stateline	California	August 2016	300	Southern California Edison	18.8
Commercial & Industrial
UC Davis	California	September 2015	13	University of California	17.8
Macy's California	California	October 2015	3	Macy's Corporate Services	17.9
Macy’s Maryland	Maryland	December 2016	5	Macy's Corporate Services	19.1
Kern(6)	California	September 2017	18	Kern High School District	19.2	(7)
Residential Portfolio	U.S. – Various	June 2014	38	Approx. 5,800 homeowners(8)	14.8	(9)
Total			946

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements— Continued

(1) For the Macy’s California Project, the Macy’s Maryland Project and the Kern Project, COD represents the first date on which all of the solar generation systems within each of the Macy’s California Project, the Macy’s Maryland Project and the Kern Project, respectively, achieved COD. For the Residential Portfolio, COD represents the first date on which all of the residential systems within the Residential Portfolio achieved COD.

(2) The MW for the projects in which the Partnership owns less than a 100% interest or in which the Partnership is the lessor under any sale-leaseback financing are shown on a gross basis.

(3) Remaining term of offtake agreement is measured from November 30, 2017.

(4) Remaining term comprised of 1.1 years on a PPA with the City of Roseville, California, followed by a 25-year PPA with PG&E starting in 2019.

(5) The Kingbird Project is subject to two separate PPAs with member cities of the Southern California Public Power Authority.

(6) OpCo’s acquisition of the Kern Project was effectuated in phases, with the closing of the first phase, reflecting a nameplate capacity of approximately 3 MW, having occurred on January 26, 2016, the closing of the second phase, reflecting a nameplate capacity of approximately 5 MW, having occurred on September 9, 2016, the closing of the third phase, reflecting a nameplate capacity of approximately 5 MW, having occurred on November 30, 2016, the closing of the fourth phase, reflecting a nameplate capacity of approximately 3 MW, having closed on February 24, 2017, and the closing of the fifth phase, reflecting a nameplate capacity of approximately 2 MW, having closed on June 9, 2017.

(7) Remaining term is the weighted average duration of the five phases of the Kern Project.

(8) Comprised of the approximately 5,800 solar installations located at homes in Arizona, California, Colorado, Hawaii, Massachusetts, New Jersey, New York, Pennsylvania and Vermont, that are held by the Residential Portfolio Project Entity and have an aggregate nameplate capacity of 38 MW.

(9) Remaining term is the weighted average duration of all of the residential leases, in each case measured from November 30, 2017.

Basis of Presentation and Preparation

The direct and indirect contributions of the IPO Project Entities by the Sponsors to OpCo in connection with the IPO resulted in a business combination for accounting purposes with the IPO SunPower Project Entities being considered the acquirer of the interests contributed by First Solar in the IPO First Solar Project Entities. Therefore, the IPO SunPower Project Entities constitute the “Predecessor.” As used herein, the term “IPO Project Entities” refers to:

• the IPO SunPower Project Entities, including:

• the Macy’s California Project Entities, which hold the Macy’s California Project;

• the Quinto Project Entity, which holds the Quinto Project;

• the RPU Project Entity, which holds the RPU Project;

• the UC Davis Project Entity, which holds the UC Davis Project; and

• the Residential Portfolio Project Entity, which holds the Residential Portfolio Project; and

• the IPO First Solar Project Entities, including:

• the Lost Hills Blackwell Project, which holds the Lost Hills Project and the Blackwell Project;

• the Maryland Solar Project Entity, which holds the Maryland Solar Project;

• the North Star Project Entity, which holds the North Star Project; and

• the Solar Gen 2 Project Entity, which holds the Solar Gen 2 Project.

In connection with the IPO, SunPower contributed a nearly 100% interest in each of the IPO SunPower Project Entities to OpCo, subject, in the case of the Quinto Project, the RPU Project, the UC Davis Project and the Macy’s California Project, to the tax equity investor’s right to a varying portion of the cash flows from the projects. In connection with the IPO, First Solar directly contributed to OpCo a 100% interest in the Maryland Solar Project Entity and indirectly contributed to OpCo a 49% economic interest in each of the Lost Hills Blackwell Project, the North Star Project and the Solar Gen 2 Project.

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements— Continued

Since November 30, 2015, the partnership completed six acquisitions from its Sponsors, four from SunPower and two from First Solar.

Four of the acquisitions are treated as business combinations:

• the Kern Project Entity, which holds the Kern Project;

• the Kingbird Project Entities, which holds the Kingbird Project;

• the Hooper Project Entity, which holds the Hooper Project; and

• the Macy’s Maryland Project Entity, which holds the Macy’s Maryland Project.

Two of the acquisitions are accounted for as equity method investments:

• the Henrietta Project Entity, which holds the Henrietta Project. OpCo owns a 49% economic interest in the Henrietta Project Entity; and

• the Stateline Project Entity, which holds the Stateline Project. OpCo owns a 34% economic interest in the Stateline Project Entity.

Principles of Consolidation

The consolidated financial statements are prepared in accordance with U.S. GAAP, and include the accounts of the Partnership, and all of its subsidiaries, as appropriate under consolidation accounting guidelines. Investments in unconsolidated affiliates in which the Partnership has less than a controlling interest are accounted for using the equity method of accounting. Inter-entity accounts and transactions have been eliminated in consolidation. In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal, recurring items) necessary to state fairly its financial position, results of operations and cash flows for the periods presented.

For all periods prior to the IPO, the accompanying consolidated financial statements and the notes thereto represent the results of the combined carve-out statements of the Predecessor and were prepared using SunPower’s historical basis in assets and liabilities. For all periods subsequent to the IPO, the accompanying consolidated financial statements and the notes thereto represent the results of 8point3 Energy Partners LP which consolidates OpCo through its controlling interest.

Throughout the periods presented in the Predecessor’s combined carve-out financial statements, the Predecessor did not exist as a separate, legally constituted entity. The Predecessor’s combined carve-out financial statements were therefore derived from SunPower’s consolidated financial statements to represent the financial position and performance of the Predecessor on a stand-alone basis during those periods in accordance with U.S. GAAP. The Predecessor’s management made allocations to approximate operating activities and cash flows as well as allocations of certain corporate expenses and believes the assumptions and methodology underlying the allocations are reasonable.

Out-of-Period Adjustments

During the fourth quarter of 2017, the Partnership corrected certain errors related to prior period income taxes that understated net income by $1.7 million, understated income attributable to noncontrolling interests and redeemable noncontrolling interests by $2.8 million and overstated net income attributable to 8Point3 Energy Partners LP Class A shares by $1.1 million. The Partnership determined that the errors and correction did not have a material effect on current or prior periods.

Fiscal Years

On June 24, 2015, in connection with the closing of the IPO, the Partnership amended its partnership agreement to include a change in the fiscal year to November 30. The Predecessor had a 52-to-53 week fiscal year that ended on the Sunday closest to December 31. The accompanying consolidated financial statements cover the period from December 1, 2016 through November 30, 2017 (“fiscal 2017”), representing the entire twelve-month period of the Partnership’s 2017 fiscal year. The prior year’s comparable periods cover the period from December 1, 2015 to November 30, 2016 (“fiscal 2016”), representing the entire twelve-month period of the Partnership’s 2016 fiscal year, and the period from December 29, 2014 through November 30, 2015 (“fiscal 2015”), representing the eleven-month period of the Partnership’s adopted 2015 fiscal year.

As a result of the change in the Partnership’s fiscal year end, the annual and quarterly periods of its newly adopted fiscal year do not coincide with the historical quarterly periods previously reported by its Predecessor. Financial information for the

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements— Continued

period from December 1, 2014 to November 30, 2015 has not been included in this Form 10-K for the following reasons: (i) the eleven months ended November 30, 2015 provides as meaningful a comparison to the years ended November 30, 2017 and November 30, 2016 as would the year ended November 30, 2015; (ii) the Partnership believes that there are no significant factors, seasonal or other, that would impact the comparability of information if the results for the year ended November 30, 2015 was presented in lieu of results for the eleven months ended November 30, 2015; and (iii) it was not practicable or cost justified to prepare this information.

Management Estimates

The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Significant estimates in these consolidated financial statements include the assumptions and methodology underlying the allocations of expenses incurred on the Predecessor’s behalf that were recorded in the Predecessor’s carve-out financial statements, as well as: allowances for doubtful accounts related to accounts receivable and financing receivables; estimates of future cash flows and economic useful lives of property and equipment; the fair value and residual value of leased solar power systems; fair value of financial instruments; fair value of acquired assets and liabilities; valuation of certain accrued liabilities such as accrued system output performance warranty and AROs; and income taxes including the related valuation allowance. Actual results could materially differ from those estimates.

Costs Related to IPO

Direct costs related to the IPO that were incurred by the Predecessor were deferred and capitalized as part of prepaid expense and other assets on the consolidated balance sheets prior to June 24, 2015. These costs include legal and accounting fees as well as other costs directly related to the IPO. These deferred costs have subsequently been accounted for as a reduction in the proceeds of the IPO and a reduction in the balance under the Partnership’s term loan entered into in connection with the IPO as capitalized financing costs. Other formation and offering related fees that were not directly related to the IPO were expensed as incurred in the Predecessor’s financial statements. For fiscal 2015, $2.5 million costs has been capitalized and $1.6 million costs has been expensed as part of SG&A expenses.

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements— Continued

Note 2. Summary of Significant Accounting Policies

Fair Value of Financial Instruments

The fair value of a financial instrument is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The carrying values of cash and cash equivalents, accounts receivable, accounts payable and accrued expenses approximate their respective fair values due to their short-term maturities. Derivative financial instruments are carried at fair value based on quoted market prices for financial instruments with similar characteristics. The Partnership has interest rate swap agreements that economically hedge the cash flows for the term loan facility, which are not designated as cash flow hedges. Therefore, the changes in fair value are recorded in other expense in the consolidated statement of operations as these hedges are not accounted for under hedge accounting. In addition, the Predecessor entered into interest rate swap agreements, designated as cash flow hedges, in the fourth quarter of fiscal 2014 on the outstanding and forecasted future borrowings under the Quinto Credit Facility (as defined below) to reduce the impact of changes in interest rates; unrealized gains and losses of the effective portion of derivative financial instruments were excluded from earnings and reported as a component of accumulated other comprehensive loss in the consolidated balance sheets. The ineffective portion of derivatives financial instruments were included in other expense in the consolidated statements of operations.

Comprehensive Income (Loss)

Comprehensive income (loss) is defined as the change in equity during a period from non-owner sources. The Partnership’s comprehensive income (loss) for each period presented is comprised of (i) its net income (loss); and (ii) changes in unrealized gains or losses for the effective portion of derivatives designated as cash flow hedges.

Equity Method Investments

The Partnership uses the equity method of accounting for equity investments where it has the ability to significantly influence the operations or financial decisions of the investee but does not own a majority interest. It considers the participating and protective rights it has as well as the legal form of the investee when evaluating whether it has the ability to exercise significant influence. Equity method investments are included in “Investment in unconsolidated affiliates” in the accompanying consolidated balance sheets. The Partnership monitors investments in equity affiliates for impairment and records reductions in carrying values if the carrying amount of the investment exceeds its fair value. An impairment charge is recorded when an impairment is deemed to be other-than-temporary. Circumstances that indicate an other-than-temporary decline include factors such as decreases in quoted market prices or declines in operations. The evaluation of an investment for potential impairment requires management to exercise significant judgment and to make certain assumptions. The use of different judgments and assumptions could result in different conclusions. During fiscal 2017, 2016 and 2015, no impairment losses were recorded related to the Partnership’s equity method investments.

On the consolidated statements of cash flows, the Partnership classifies distributions received from unconsolidated investees accounted for under the equity method using the cumulative earnings approach. Under the cumulative earnings approach, the Partnership compares cumulative distributions received, less distributions received in the prior year that were determined to be returns of investment, to its share of cumulative equity in earnings (as adjusted for basis differences) for each unconsolidated investee on an inception-to-date basis. If the Partnership’s inception-to-date distributions are greater than its inception-to-date equity in earnings for an unconsolidated investee, the distributions up to its inception-to-date equity in earnings are considered a return on investment and are therefore classified as cash flows from operating activities, while the distributions of that unconsolidated investee in excess of its inception-to-date equity in earnings are considered to be a return of investment and are classified as cash flows from investing activities. If the Partnership’s inception-to-date distributions are less than its inception-to-date equity in earnings for an unconsolidated investee, such distributions are considered to be a return on investment and are classified as cash flows from operating activities.

Cash and Cash Equivalents

The Partnership considers unrestricted cash on hand and demand deposits in banks to be cash and cash equivalents; such balances approximate fair value at November 30, 2017 and November 30, 2016. Highly liquid investments with original or remaining maturities of 90 days or less at the time of purchase are considered cash equivalents.

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements— Continued

Accounts Receivable and Financing Receivable

Accounts receivable:    Accounts receivable are reported on the consolidated balance sheets at the outstanding invoiced amounts, adjusted for any write-offs and estimated allowance for doubtful accounts. The Partnership maintains an allowance for doubtful accounts based on the expected collectability of all accounts receivable, which takes into consideration an analysis of historical bad debts, specific customer creditworthiness and current economic trends. Qualified customers under the residential lease program are required to have a minimum “fair” FICO credit score at the time of initial contract. The Partnership believes that its concentration of credit risk is limited because of its large number of residential customers, high credit quality of the residential customer base with high average FICO credit scores at the time of initial contract, small account balances for most of these residential customers, and customer geographic diversification. As of both November 30, 2017 and November 30, 2016, less than $0.1 million allowance for doubtful accounts related to residential operating leases had been recorded.

Financing receivables:    Leases are classified as either operating or sales-type leases in accordance with the relevant accounting guidance. Financing receivables are generated by solar power systems leased to residential customers under sales-type leases. Financing receivables represent gross minimum lease payments to be received from customers and the systems’ estimated residual value, net of executory costs, unearned income and allowance for estimated losses.

The Partnership recognizes an allowance for losses on financing receivables in an amount equal to the probable losses, net of recoveries, and base such reserves on several factors, including consideration of historical credit losses. As of both November 30, 2017 and November 30, 2016, $0.7 million had been recorded as allowance for losses on financing receivables.

Property and Equipment

Property and equipment, including solar power systems, are stated at cost, less accumulated depreciation. Any energy generated by solar power systems prior to being placed into service or investment tax credit to which a Sponsor is entitled reduces the carrying value of the asset by the related amount. Residential leased solar power systems are depreciated to their estimated residual value using the straight-line method over the lease term of 20 years. Depreciation expense for utility solar power systems is computed using the straight-line method over the shorter of the term of the estimated useful life or the lease on the land. The estimated useful life of a system is reassessed whenever applicable facts and circumstances indicate a change in the estimated useful life of such system has occurred. The estimated useful life of all solar power systems is 30 years and all systems are physically located in the United States. Depreciation expense for fiscal 2017, 2016 and 2015 was $28.1 million, $22.8 million, and $4.3 million, respectively. Repairs and maintenance costs are expensed as incurred.

Construction-in-Progress

Project assets that are still under construction are construction-in-progress and are not depreciated until they are placed in service.

Long-Lived Assets

The Partnership evaluates its long-lived assets, including property and equipment, construction-in-progress and projects for impairment whenever events or changes in circumstances indicate the carrying value of such assets may not be recoverable. Factors considered important that could result in an impairment review of leased solar power systems include credit rating downgrades below investment grade, reports of substantial uncertainty as to ability to continue as a going concern, lease asset depreciation expense greater than associated operating revenue, decrease in the estimated residual value of the leased solar power system and inability to collect lease payments due from lessees whether through aging receivables, lease contract amendments or terminations. The impairment evaluation of leased solar power systems includes an analysis of estimated future undiscounted net cash flows expected to be generated by the assets over their remaining estimated useful lives. If the estimate of future undiscounted net cash flows is insufficient to recover the carrying value of the assets over the remaining estimated useful lives, the Partnership records an impairment loss in the amount by which the carrying value of the assets exceeds the fair value. Fair value is generally measured based on discounted cash flow analysis.

With respect to solar energy projects, the Partnership considers the project commercially viable if it is anticipated to be operated for a profit once it is fully operating. The Partnership examines a number of factors to determine if the project will be profitable, including the pricing of the offtake agreement and whether there are any environmental, ecological, permitting, or regulatory conditions that have changed for the project since the start of development. Such changes could cause the cost of the project to increase.

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements— Continued

Interest Capitalization

Interest incurred on funds borrowed to finance construction of projects is capitalized to construction-in-progress until the system is ready for its intended use. When no debt is specifically identified as being incurred in connection with a construction project, the Partnership capitalizes interest on amounts expended on the project at the Partnership’s weighted average cost of borrowed money. The amount of interest capitalized for fiscal 2017, 2016 and 2015 was $0.2 million, $0.7 million and $6.5 million, respectively.

Asset Retirement Obligations

In some cases the Partnership operates certain projects under power purchase and other agreements that include a requirement for the removal of the solar power systems at the end of the term of the agreement. The Partnership accounts for such legal obligations or AROs in accordance with U.S. GAAP, which requires that a liability for the fair value of an ARO be recognized in the period in which it is incurred if it can be reasonably estimated with the offsetting, associated asset retirement cost capitalized as part of the carrying amount of the property and equipment. The asset retirement cost is subsequently allocated to expense using a systematic and rational method over the asset’s estimated useful life. The Partnership has accrued AROs of $15.0 million and $13.4 million as of November 30, 2017 and November 30, 2016, respectively.

Contingencies

The Partnership is involved in conditions, situations or circumstances in the ordinary course of business with possible loss contingencies, such as system output performance warranty and residential lease system repairs, that will ultimately be resolved when one or more future events occur or fail to occur. In certain circumstances, the Partnership has hired service providers to mitigate the potential risk of loss. For example, the Partnership provides system output performance warranties under residential lease agreements with homeowners. The O&M provider, currently a subsidiary of SunPower, also provides system output performance warranties to the Partnership equivalent to those offered by the Partnership to homeowners.  As a result, the Partnership records liabilities in connection with these items offset by a corresponding amount in other assets as due from the O&M provider on its consolidated financial statements. As of November 30, 2017 and November 30, 2016, the Partnership recorded $0.2 million and $0.5 million, respectively, in other current liabilities related to system output performance warranties and system repairs and a corresponding amount due from SunPower in other current assets.

If some amount within a range of loss appears at the time to be a better estimate than any other amount within the range, that amount will be accrued. When no amount within the range is a better estimate than any other amount, however, the minimum amount in the range will be accrued. The Partnership continually evaluates uncertainties associated with loss contingencies and records a charge equal to at least the minimum estimated liability for a loss contingency when both of the following conditions are met: (i) information available prior to issuance of the financial statements indicates that it is probable that an asset had been impaired or a liability had been incurred at the date of the financial statements; and (ii) the loss or range of loss can be reasonably estimated.

Revenue Recognition

Operating revenues to date are comprised of revenues generated from PPAs, solar power systems leased to residential customers, lease revenue from the Maryland Solar Project and net revenue from the sale and delivery of SRECs. The Partnership is the lessor while the PPA offtaker, residential customers and an affiliate of First Solar are the lessees.

Operating leases:    Under long-term PPAs, revenue is generated from the sale of energy to various non-affiliated parties. Amounts are recognized as revenue based on rates stipulated in the respective PPAs when energy and any related renewable energy attributes are delivered. All PPAs, except for those associated with the Macy’s Maryland Project, are accounted for as operating leases. In addition, the Partnership also recognizes lease revenue for the Maryland Solar Project, which is subject to a solar lease agreement that expires on December 31, 2019, with an affiliate of First Solar as the lessee.

Certain residential leased solar power systems are classified as operating leases; therefore, revenue associated with renting the solar power system and executory costs is recognized on a straight-line basis over the 20-year lease term. State or local rebates defined in the minimum lease payments under the lease that are deemed fixed and determinable are recorded as deferred revenue in the consolidated balance sheets when the lease is placed in service and amortized to revenue on a straight-line basis over the 20-year lease term. PBI Rebates representing contingent revenue are recognized upon cash receipt.

Sales-type leases:    For residential systems classified as sales-type leases, the NPV of the minimum lease payments, net of executory costs, was recognized as revenue when the lease was placed in service. This NPV, as well as the residual value, is

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements— Continued

recorded as financing receivables in the consolidated balance sheets. The difference between the initial net and gross amounts is amortized to revenue over the lease term using the effective interest method. Revenue representing executory costs to operate and maintain the leased solar power system is recognized on a straight-line basis over the 20-year lease term. All of the leases in the Residential Portfolio were placed into service before fiscal 2015. Accordingly, only interest revenue and related O&M revenue associated with sales-type leases was recognized in fiscal 2017, fiscal 2016 and fiscal 2015.

Noncontrolling Interests

Noncontrolling interests represent the portion of net assets in consolidated subsidiaries that are not attributable, directly or indirectly, to the Partnership. The largest portion of noncontrolling interest in the Partnership relates to the Sponsors’ ownership in OpCo. In addition, the Partnership has entered into certain tax equity transactions with third-party investors under which the investors are determined to hold noncontrolling interests in entities fully consolidated by OpCo. The net assets of the shared entities are attributed to the controlling and noncontrolling interests based on the terms of the governing contractual arrangements. Therefore, for the tax equity transactions, the Partnership further determined the HLBV Method to be the appropriate method for attributing net assets to the controlling and noncontrolling interests as this method most closely mirrors the economics of the governing contractual arrangements. Under the HLBV Method, the Partnership allocates recorded income (loss) to each investor based on the change, during the reporting period, of the amount of net assets each investor is entitled to under the governing contractual arrangements in a liquidation scenario. The Partnership accounts for the portion of net assets using the HLBV Method in the consolidated entities attributable to the investors as “Redeemable noncontrolling interests” and “Noncontrolling interests” in its consolidated financial statements. Noncontrolling interests in subsidiaries that are redeemable at the option of the noncontrolling interest holder are classified as “Redeemable noncontrolling interests in subsidiaries” between liabilities and equity on the consolidated balance sheets and the balance is the greater of the carrying value calculated under the HLBV Method or the redemption value. 

Cost of Operations

Cost of operations includes O&M costs related to the operating projects as well as cost recognized on sales-type leases and is recognized when the leased solar power system is placed in service or sold. Cost recognized on sales-type leases includes initial direct costs to complete a leased solar power system, such as costs for constructing a solar power system inclusive of dealer payments, freight charges and direct lease costs.

Income Taxes

The Partnership accounts for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of the differences between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. Valuation allowances are provided against deferred tax assets when management cannot conclude that it is more likely than not that some portion or all deferred tax assets will be realized. On December 22, 2017, the 2017 Tax Act was signed into law, which enacted major changes to the U.S. federal income tax laws, including a permanent reduction in the U.S. federal corporate income tax rate. Please read “—Note 17—Subsequent Events” for further details.

The calculation of tax liabilities involves dealing with uncertainties in the application of complex tax regulations. The Partnership, which has elected to be treated as a corporation for federal income tax purposes, recognizes potential liabilities for anticipated tax audit issues in the United States based on its estimate of whether, and the extent to which, additional taxes will be due. If payment of these amounts ultimately proves to be unnecessary, the reversal of the liabilities would result in tax benefits being recognized in the period in which the Partnership determines the liabilities are no longer necessary. If the estimate of tax liabilities proves to be less than the ultimate tax assessment, a further charge to expense would result. The Partnership accrues interest and penalties on tax contingencies, which are not considered material.

The Partnership recognizes deferred tax assets to the extent that it believes these assets are more likely than not to be realized. In making such a determination, the Partnership considers all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning strategies and results of recent operations. If the Partnership determines that it would be able to realize its deferred tax assets in the future in excess of their net recorded amount, it would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements— Continued

The Partnership records uncertain tax positions on the basis of a two-step process whereby (1) it determines whether it is more likely than not that the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions that meet the more-likely-than-not recognition threshold, the Partnership recognizes the largest amount of tax benefit that is more than 50 percent likely to be realized upon ultimate settlement with the related tax authority.

Business Combinations

The Partnership records all assets and liabilities acquired in a business combination at fair value. The judgments made in the context of the purchase price allocation can materially impact the Partnership’s future results of operations. Accordingly, for significant acquisitions, the Partnership obtains assistance from third-party valuation specialists. The valuations calculated from estimates are based on information available at the acquisition date. The Partnership charges acquisition related transaction costs that are not part of the consideration to operating costs and expenses as they are incurred. These costs typically include financial advisory, legal and accounting fees. 

Solar Renewable Energy Credits

The Partnership applies for and receives SRECs for power generated by certain of its solar power systems. The Partnership has entered into a sales agreement with a non-affiliated party (the “SREC Sales Agreement”) to assist it in meeting its own emissions reduction or conservation requirements. Under the terms of the SREC Sales Agreement, the contracted counterparty is obligated to purchase an annual number of SRECs from the Partnership at stipulated prices over a defined period of time. The Partnership recognizes revenue and associated costs upon delivery of the SRECs to the counterparty.

Share-Based Compensation Expense

The Partnership measures compensation expense for all share-based payment awards based on grant-date fair values of Class A shares, and accounts for share-based compensation expense by amortizing the fair value on a straight-line basis over the requisite vesting period. Share-based compensation expense for fiscal 2017, 2016 and 2015 was $0.2 million, $0.2 million and $0.1 million, respectively, and was included in SG&A expense.

Recent Accounting Pronouncements Not Yet Adopted

In January 2017, the FASB issued an update to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions of assets or businesses. This new guidance becomes effective for the Partnership in the first quarter of fiscal 2019 and is applied prospectively. The Partnership is evaluating the impact of this standard on its consolidated financial statements and disclosures.

In October 2016, the FASB issued an update which amends the guidance on related parties that are under common control. Specifically, this update requires that a single decision maker consider indirect interests held by related parties under common control on a proportionate basis in a manner consistent with its evaluation of indirect interests held through other related parties. That is, the single decision maker does not consider indirect interests held through related parties as equivalent to direct interests in determining whether it meets the economics criterion to be a primary beneficiary. This new guidance becomes effective for the Partnership in the first quarter of fiscal 2018. The adoption of this standard is not expected to have a material impact on its consolidated financial statements and disclosures.

In October 2016, the FASB issued an update which eliminates a prior exception and now requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory, such as property and equipment, when such transfer occurs. This new guidance becomes effective for the Partnership in the first quarter of fiscal 2020 and shall be applied on a modified retrospective basis through a cumulative–effect adjustment directly to retained earnings as of the beginning of the period of adoption. Early adoption is permitted. The Partnership is evaluating the impact of this standard on its consolidated financial statements and disclosures.

In August 2016, the FASB issued an update to the statement of cash flows guidance, which addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. One identified cash flow issue relates to distributions received from equity method investees whereby the reporting entity should make an accounting policy election to classify distributions received from equity method investees using either the cumulative earnings approach or the nature of the distribution approach. This new guidance becomes effective for the Partnership in the first quarter of fiscal 2018 and is applied retrospectively. The Partnership expects to continue to apply the cumulative earnings approach which will not have an impact on its consolidated financial statements and disclosures.

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In March 2016, the FASB issued an update to the equity method investments guidance, which eliminates the requirement that an entity retroactively adopt the equity method of accounting if an investment qualifies for use of the equity method as a result of an increase in the level of ownership or degree of influence. The update requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for equity method accounting. This new guidance becomes effective for the Partnership in the first quarter of 2018 on a prospective basis. The adoption of this standard is not expected to have a material impact on its consolidated financial statements and disclosures.

In February 2016, the FASB issued an update to the lease accounting guidance, which requires entities to begin recording assets and liabilities arising from substantially all leases on the balance sheet. The new guidance will also require significant additional disclosures about the amount, timing and uncertainty of cash flows from leases. This new guidance will be effective for the Partnership in the first quarter of fiscal 2020 using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. The Partnership is evaluating the impact of this standard on its consolidated financial statements and disclosures.

In May 2014, the FASB issued a new revenue recognition standard based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The FASB has issued several updates to the standard which (i) clarify the application of the principal versus agent guidance, (ii) clarify the guidance relating to performance obligations and licensing and (iii) clarify assessment of the collectability criterion, presentation of sales taxes, measurement date for non-cash consideration and completed contracts at transaction. The new revenue recognition standard, amended by the updates, becomes effective for the Partnership in the first quarter of fiscal 2019 and is to be applied retrospectively using one of two prescribed methods. Early adoption is permitted. While the Partnership is continuing to assess all potential impacts of the standard, it currently believes the impact on its consolidated financial statements is not material because over 90% of the Partnership’s total revenue for all periods is comprised of lease revenue, which is substantially unchanged under the new standard.

Other than as described above, there has been no issued accounting guidance not yet adopted by the Partnership that it believes is material or potentially material to its consolidated financial statements. 

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Note 3. Business Combinations

Acquisition accounting is dependent upon certain valuations and other studies that must be completed as of the acquisition date. The judgments made in the context of the purchase price allocation can materially impact the Partnership’s future results of operations. The Partnership’s purchase price allocations for acquisitions completed through November 30, 2017 are final and not subject to revision.

2017 Acquisitions

Kern Acquisition:

On January 26, 2016, OpCo and SunPower entered into the Kern Purchase Agreement, which was amended on September 28, 2016, November 30, 2016, February 24, 2017 and June 9, 2017, pursuant to which OpCo agreed to purchase an interest in the Kern Project. OpCo’s acquisition of the Kern Project was effectuated in phases as summarized below:

(i) Phase 1(a): On January 26, 2016, 8point3 OpCo Holdings, LLC, a wholly owned subsidiary of OpCo (“OpCo Holdings”), acquired from SunPower all of the class B limited liability company interests of the Kern Class B Partnership. Prior to the date of the execution of the Kern Purchase Agreement and in connection with the closing of the tax equity financing for the Kern Project, described below, the Kern Project Entity, an indirect subsidiary of the Kern Class B Partnership, acquired the Kern Phase 1(a) Assets. The initial phase of the acquisition of the Kern Project is referred to herein as the “Kern Phase 1(a) Acquisition.”

(ii) Phase 1(b): On September 9, 2016, the Kern Project Entity acquired the assets included in the Kern Phase 1(b) Assets from SunPower. The second phase of the acquisition of the Kern Project is referred to herein as the “Kern Phase 1(b) Acquisition.”

(iii) Phase 2(a): On November 30, 2016, the Kern Project Entity acquired the Kern Phase 2(a) Assets from SunPower. The third phase of the acquisition of the Kern Project is referred to herein as the “Kern Phase 2(a) Acquisition.”

(iv) Phase 2(b): On February 24, 2017, the Kern Project Entity acquired the Kern Phase 2(b) Assets from SunPower. The fourth phase of the acquisition of the Kern Project is referred to herein as the “Kern Phase 2(b) Acquisition.”

(v) Phase 2(c): On June 9, 2017, the Kern Project Entity acquired the Kern Phase 2(c) Assets from SunPower. The fifth phase of the acquisition of the Kern Project is referred to herein as the “Kern Phase 2(c) Acquisition.”

The aggregate purchase price for the acquisition was $31.7 million in cash, of which OpCo paid approximately $4.9 million on January 27, 2016 in connection with the closing of the first phase, approximately $9.2 million on September 9, 2016 in connection with the closing of the second phase, approximately $8.4 million on November 30, 2016 in connection with the closing of the third phase, approximately $6.0 million on February 24, 2017 in connection with the closing of the fourth phase and approximately $3.2 million on June 9, 2017 in connection with the closing of the fifth phase. The conditions precedent to the acquisition of the Kern Remaining Assets set forth in the Kern Letter Agreement were not met on or prior to September 30, 2017. On October 3, 2017, SunPower provided written notice to OpCo terminating the Kern Purchase Agreement, pursuant to Section 9.01(c) of the Kern Purchase Agreement. Pursuant to the terms of the Kern Letter Agreement, the Kern Remaining Assets are now considered SunPower ROFO Projects.

In addition, on January 22, 2016, a subsidiary of the Kern Class B Partnership entered into a tax equity financing facility with a third-party investor, which allocates to OpCo a certain share of cash flows from the Kern Project pursuant to a distribution waterfall. Pursuant to this distribution waterfall, the tax equity investor is entitled to a monthly amount of project cash flow until a specified “flip” point is achieved. After the “flip” point, the cash allocations to OpCo increase. In addition, upon reaching the flip point, OpCo has a right to purchase the tax equity investor’s interests in the project for an amount that is not less than its fair market value. The tax equity investor made capital contributions to fund purchase price payments of approximately $29.2 million, of which $0.9 million, $1.8 million, $1.3 million, $6.7 million, $8.2 million, $6.3 million and $4.0 million was paid on January 22, 2016, September 9, 2016, November 30, 2016, December 14, 2016, February 24, 2017, June 9, 2017 and September 28, 2017, respectively. The tax equity investor contributions were made when the Kern Project's phases met certain construction milestones and were subsequently transferred to SunPower as purchase price payments. All phases of the Kern Project attained COD prior to October 3, 2017.

The Kern Phase 1(a) Acquisition, the Kern Phase 1(b) Acquisition, the Kern Phase 2(a) Acquisition, the Kern Phase 2(b) Acquisition and the Kern Phase 2(c) Acquisition qualify as business combinations and the Partnership accounts for the

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transactions under the acquisition method. The purchase allocation of the identifiable assets acquired, liabilities assumed and noncontrolling interests of the Kern Phase 1(a) Assets, the Kern Phase 1(b) Assets, the Kern Phase 2(a) Assets, the Kern Phase 2(b) Assets and the Kern Phase 2(c) Assets are disclosed in the following table.

	Fair Value
	Kern Phase 1(a)			Kern Phase 1(b)			Kern Phase 2(a)			Kern Phase 2(b)			Kern Phase 2(c)
(in thousands)	Assets			Assets			Assets			Assets			Assets
Property and equipment	$	9,510		$	18,856		$	15,659		$	12,477		$	6,464
Related party payable (1)	(3,435		)	(7,123		)	(5,290		)	(4,892		)	(2,372		)
Asset retirement obligation	(322		)	(785		)	(623		)	(493		)	(279		)
Noncontrolling interest	(866		)	(1,794		)	(1,332		)	(1,078		)	(658		)
Net assets acquired	$	4,887		$	9,154		$	8,414		$	6,014		$	3,155

(1) Related party payable represents liabilities for amounts due to SunPower related to capital contributions to fund purchase price payments due from the tax equity investor after the acquisition date, all of which was subsequently settled.

Valuation methodology:

The Partnership utilized the discounted cash flow method under the income approach to value property and equipment for the Kern Phase 1(a) Assets, the Kern Phase 1(b) Assets, the Kern Phase 2(a) Assets, the Kern Phase 2(b) Assets and the Kern Phase 2(c) Assets. Key assumptions used in the discounted cash flow method included forecasted pre-tax cash flows, forecasted taxable income and discount rates. All estimates, key assumptions and forecasts were reviewed by the Partnership and the fair value analyses and related valuations represent the conclusions of management.

Supplementary Data:

The results of operations for each phase of the Kern Project acquisition have been included in the Partnership’s consolidated statements of operations since their respective dates of acquisition. The Kern Phase 2(b) Assets and the Kern Phase 2(c) Assets contributed approximately $0.7 million to the Partnership’s operating revenue and increased operating income by $0.2 million in fiscal 2017. Pro forma results of operations have not been presented as the impact of the acquisitions on February 24, 2017 and June 9, 2017 are not material to the Partnership’s results of operations for the current or prior periods. Additionally, the Kern Phase 2(b) Assets and the Kern Phase 2(c) Assets became operational after the acquisition date and therefore, would not have had any pro forma results in the prior period.

2016 Acquisitions

Kingbird Acquisition:

On March 31, 2016, OpCo entered into the Kingbird Purchase Agreement with First Solar, pursuant to which OpCo agreed to acquire an interest in the Kingbird Project for an aggregate consideration of $60.0 million in cash (the “Kingbird Acquisition”). Effective March 31, 2016, a subsidiary of OpCo acquired FSAM Kingbird Solar Holdings, LLC from First Solar. FSAM Kingbird Solar Holdings, LLC holds the class B limited liability company interests of Kingbird Solar, LLC. The Kingbird Project Entities are direct subsidiaries of Kingbird Solar, LLC, of which OpCo holds a controlling interest in effective March 31, 2016. Pursuant to the Kingbird Purchase Agreement, the purchase price of $60.0 million was paid by OpCo in installments, with $42.9 million in cash paid to First Solar on the closing date of March 31, 2016 and a $17.1 million contribution to FSAM Kingbird Solar Holdings, LLC, the acquired company, on May 31, 2016, which was subsequently paid to First Solar for the remaining balance due under the Kingbird Project’s EPC contract. The closing of the Kingbird Acquisition occurred simultaneously with the execution of the Kingbird Purchase Agreement and OpCo funded 100% of the payment for the Kingbird Project with a combination of cash on hand, and drawings under OpCo’s revolver and delayed draw facility.

Ownership and cash flows of the Kingbird Project are subject to a tax equity financing facility with a third-party investor, which allocates to OpCo a certain share of cash flows from the Kingbird Project pursuant to a distribution waterfall. Pursuant to this distribution waterfall, the tax equity investor is entitled to a quarterly amount of project cash flow until a specified “flip” point, based on the achievement of a targeted internal rate of return. After the “flip” point, the cash allocations to OpCo increase. In addition, upon reaching the flip point, OpCo has a right to purchase the tax equity investor’s interests in the project for an amount that is not less than its fair market value. The tax equity investor made capital contributions to fund purchase price payments of approximately $58.5 million, of which $11.7 million was paid on February 26, 2016 and $46.8

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million was paid on May 31, 2016. The tax equity investor contributions were made when the Kingbird Project's phases met certain construction milestones and were subsequently transferred to First Solar as purchase price payments.

The Kingbird Acquisition qualifies as a business combination and the Partnership accounts for the transaction under the acquisition method. The purchase allocation of the identifiable assets acquired, liabilities assumed and noncontrolling interests of the Kingbird Project is as follows:

(in thousands)	Fair Value
Property and equipment	$	117,473
Prepaid transmission services	1,982
Interest receivable	72
Related party payable (1)	(63,971		)
Asset retirement obligation	(981		)
Noncontrolling interest	(11,709		)
Net assets acquired	$	42,866

(1) Related party payable represents liabilities for amounts due to an affiliate of First Solar related to the construction of the project and consisted of: (i) a $17.1 million contribution to FSAM Kingbird Solar Holdings, LLC, the acquired company, by OpCo on May 31, 2016, which was subsequently paid by the acquired company and (ii) a $46.8 million payment made from the capital contribution by the tax equity investor on May 31, 2016.

Hooper Acquisition:

On March 31, 2016, OpCo entered into the Hooper Purchase Agreement with SunPower, pursuant to which OpCo agreed to acquire an interest in the Hooper Project for aggregate consideration of $53.5 million in cash. Effective April 1, 2016, a subsidiary of OpCo acquired from SunPower all of the class B limited liability company interests of the Hooper Class B Partnership. The Hooper Project Entity is an indirect subsidiary of the Hooper Class B Partnership, of which OpCo holds a controlling interest in effective April 1, 2016. The Hooper Acquisition closed on April 1, 2016 and OpCo funded 100% of the purchase price for the Hooper Project with a combination of cash on hand, and drawings under OpCo’s revolver and delayed draw facility.

Ownership and cash flows of the Hooper Project are subject to a tax equity financing facility with a third-party investor, which allocates to OpCo a certain share of cash flows from the Hooper Project pursuant to a distribution waterfall. Pursuant to this distribution waterfall, the tax equity investor is entitled to a monthly amount of project cash flow until a specified “flip” point is achieved. After the “flip” point, the cash allocations to OpCo increase. In addition, upon reaching the flip point, OpCo has a right to purchase the tax equity investor’s interests in the project for an amount that is not less than its fair market value.

The Hooper Acquisition qualifies as a business combination and the Partnership accounts for the transaction under the acquisition method. The purchase allocation of the identifiable assets acquired, liabilities assumed and noncontrolling interests of the Hooper Project is as follows: 

(in thousands)	Fair Value
Property and equipment	$	76,477
Prepaid expense	240
Accounts receivable (1)	568
Accrued liabilities (2)	(463		)
Noncontrolling interest	(23,737		)
Net assets acquired (3)	$	53,085

(1) Accounts receivable represent the fair value of the trade accounts receivable acquired, all of which was subsequently collected.

(2) Accrued liabilities includes $0.3 million of cash distributions payable that was paid to the tax equity investor on April 30, 2016.

(3) The net purchase price for the acquisition represents $53.5 million of cash paid by OpCo, offset by $0.4 million cash acquired in the Hooper Project Entity.

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Macy’s Maryland Acquisition:

On June 29, 2016, OpCo entered into the Macy’s Maryland Purchase Agreement with SunPower, pursuant to which OpCo agreed to acquire an interest in the Macy’s Maryland Project for aggregate consideration of $12.0 million in cash. Effective July 1, 2016, a subsidiary of OpCo acquired from SunPower all of the class B limited liability company interests of the Macy's Maryland Class B Partnership. The Macy's Maryland Class B Partnership holds the class B limited liability company interests of Macy's Maryland Holdings, the direct owner of the Macy's Maryland Project Entity. Consideration for the Macy’s Maryland Acquisition comprised a $12.0 million contribution to the Macy’s Maryland Class B Partnership, the acquired company, on July 1, 2016, of which $6.4 million was paid to SunPower on July 1, 2016 and the $5.6 million remaining balance due was paid to SunPower on September 21, 2016 when the Macy’s Maryland Project met certain construction milestones.

Ownership and cash flows of the Macy’s Maryland Project are subject to a tax equity financing facility with a third-party investor, which allocates to OpCo a certain share of cash flows from the Macy’s Maryland Project pursuant to a distribution waterfall.  Pursuant to this distribution waterfall, the tax equity investor is entitled to a quarterly amount of project cash flows until a specified “flip” point is achieved. After the “flip” point, the cash allocations to OpCo increase. In addition, upon reaching the flip point, OpCo has a right to purchase the tax equity investors’ interests in the project for an amount that is not less than its fair market value.

The Macy’s Maryland Acquisition qualifies as a business combination and the Partnership accounts for the transaction under the acquisition method. The purchase allocation of the identifiable assets acquired, liabilities assumed and noncontrolling interests of the Macy’s Maryland Project is as follows:

(in thousands)	Fair Value
Property and equipment	$	19,317
Customer contract intangible (1)	1,844
Related party payable (2)	(13,975		)
Asset retirement obligation	(278		)
Noncontrolling interest	(556		)
Net assets acquired (3)	$	6,352

(1) Customer contract intangible is amortized on a straight-line basis beginning on COD through the contract term end date of December 31, 2020, of which $0.4 million and $0.1 million reduced operating revenues in fiscal 2017 and fiscal 2016, respectively.

(2) Related party payable represents liabilities for amounts due to SunPower related to the construction of the project and consisted of: (i) $5.6 million paid to SunPower on September 21, 2016 when the Macy’s Maryland Project met certain construction milestones and (ii) $8.3 million of capital contributions due by the tax equity investor, of which $3.3 million and $4.8 million was paid on September 21, 2016 and December 28, 2016, respectively.

(3) The net purchase price for the acquisition represents $12.0 million of cash contributed by OpCo to the Macy’s Maryland Class B Partnership, the acquired company, of which $6.4 million was paid to SunPower on July 1, 2016 and the $5.6 million remaining balance due was paid to SunPower on September 21, 2016 when the Macy’s Maryland Project met certain construction milestones.

2015 Acquisition

On June 24, 2015, the Partnership acquired a 100% interest in the Maryland Solar Project Entity and a 49% indirect interest in each of the Solar Gen 2 Project, the North Star Project and the Lost Hills Blackwell Project.

The purchase allocation for the acquired assets and liabilities of the Maryland Solar Project, the Solar Gen 2 Project, the North Star Project and the Lost Hills Blackwell Project is based on a valuation from a third-party valuation specialist as follows and includes a $2.3 million deferred tax liability for the difference between the fair value and tax basis of acquired assets and liabilities, which is reversed upon acquisition due to utilization of existing net operating losses of the Predecessor.

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(in thousands)	Fair Value
Property and equipment	$	56,497
Equity method investment - Solar Gen 2	216,483
Equity method investment - North Star	103,849
Equity method investment - Lost Hills Blackwell	34,121
Asset retirement obligation	(2,130		)
Total purchase price	$	408,820

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Note 4. Investment in Unconsolidated Affiliates

On September 20, 2016, OpCo entered into a Contribution Agreement with SunPower and SunPower AssetCo to acquire a 49% interest in the Henrietta Project for $134.0 million in cash (the “Henrietta Acquisition”). The Henrietta Acquisition closed on September 29, 2016 and the Partnership recorded an investment of $134.5 million after consideration of acquisition related costs, working capital adjustments and noncontrolling interest.

On November 11, 2016, OpCo entered into the Stateline Purchase Agreement with First Solar and FSAM to acquire a 34% interest in the Stateline Project for $329.5 million (the “Stateline Acquisition”). The Stateline Acquisition closed on December 1, 2016 and the Partnership recorded an investment of $330.0 million after consideration of acquisition-related costs.

As of November 30, 2017, the Partnership owns a 49% ownership interest in each of SG2 Holdings, North Star Holdings, Lost Hills Blackwell Holdings and Henrietta Holdings and a 34% ownership interest in Stateline Holdings. The minority membership interests are accounted for as equity method investments, as the Partnership is able to exercise significant influence through its governing board, while the non-affiliated majority owner otherwise controls. The following table summarizes the activity of the Partnership’s investments in its unconsolidated affiliates:

	Year Ended
(in thousands)	November 30, 2017			November 30, 2016
Balance at the beginning of the period	$	475,078		$	352,070
Investments in its unconsolidated affiliates during the period	330,088			134,371
Equity in earnings in unconsolidated affiliates (1)	43,379			18,341
Distributions from unconsolidated affiliates	(80,287		)	(29,704		)
Balance at the end of the period	$	768,258		$	475,078

(1) The net income used to determine the Partnership’s equity in earnings of unconsolidated affiliates reflects adjustments pursuant to the equity method of accounting, including the amortization of basis differences resulting from the Partnership’s proportionate share of certain equity method investees’ net assets exceeding their carrying values.

The difference between the amounts at which the Partnership’s investments in unconsolidated affiliates are carried and the Partnership’s proportionate share of the equity method investee’s net assets for equity method investments was $136.4 million and $83.2 million as of November 30, 2017 and November 30, 2016, respectively. The Partnership accretes the basis difference over the life of the underlying assets and the accretion was $4.1 million, $1.7 million, $0.7 million for fiscal 2017, 2016 and 2015, respectively.

The following table presents summarized financial information of SG2 Holdings, North Star Holdings, Lost Hills Blackwell Holdings, Henrietta Holdings and Stateline Holdings as derived from the consolidated financial statements of such entities: 

	Year Ended				Eleven Months Ended
(in thousands)	November 30, 2017		November 30, 2016		November 30, 2015
Summary statement of operations information:
Revenue	$	178,425	$	72,099	$	55,227
Operating expenses	101,284		47,385		37,342
Net income	74,230		24,970		18,187
	As of
	November 30, 2017		November 30, 2016
Summary balance sheet information:
Current assets	$	76,866	$	45,086
Long-term assets	2,867,709		1,498,820
Current liabilities	11,303		6,250
Long-term liabilities	25,143		12,329

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Note 5. Balance Sheet Components

Financing Receivables

The Partnership’s net investment in sales-type leases presented in “Accounts receivable and short-term financing receivables, net” and “Long-term financing receivables, net” on the consolidated balance sheets is as follows: 

	As of
(in thousands)	November 30, 2017			November 30, 2016
Minimum lease payment receivable, net (1)	$	93,161		$	100,161
Unguaranteed residual value	12,774			12,926
Less: unearned income	(27,178		)	(30,557		)
Net financing receivables	$	78,757		$	82,530
Short-term financing receivables, net (2)	$	2,556		$	2,516
Long-term financing receivables, net	$	76,201		$	80,014

(1) Allowance for losses on financing receivables was $0.7 million as of both November 30, 2017 and November 30, 2016.

(2) Accounts receivable and short-term financing receivables, net on the consolidated balance sheets includes other trade accounts receivable of $3.0 million and $2.9 million as of November 30, 2017 and November 30, 2016, respectively.

The movement in the Partnership’s allowance for losses on financing receivables is as follows: 

	Balance at Beginning of Year			Releases (Charges) to Expenses			Deductions		Balance at End of Year
Fiscal 2017	$	(698	)	$	29		$	18	$	(651	)
Fiscal 2016	$	(328	)	$	(370	)	$	—	$	(698	)
Fiscal 2015	$	—		$	(328	)	$	—	$	(328	)

Current and Non-current Assets

	As of
(in thousands)	November 30, 2017			November 30, 2016
Prepaid expense and other current assets
Reimbursable network upgrade costs (1)	$	13,294		$	13,870
Derivative financial instruments	1,603			—
Other current assets (2)	2,093			1,875
Total	$	16,990		$	15,745
Property and equipment, net
Utility solar power systems	$	636,495		$	578,817
Leased solar power systems	137,052			137,475
Land	1,020			1,020
Construction-in-progress (3)	—			36,981
	774,567			754,293
Less: accumulated depreciation	(61,283		)	(34,161		)
Total	$	713,284		$	720,132
Other long-term assets
Reimbursable network upgrade costs (1)	$	14,047		$	21,781
Intangible assets (4)	1,325			1,754
Derivative financial instruments	—			897
	$	15,372		$	24,432

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(1) For the Kingbird Project and the Quinto Project, the construction costs related to the network upgrade of a transmission grid belonging to a utility company are reimbursable by that utility company over five years from the date the project reached commercial operation.

(2) Other current assets included $0.2 million due from SunPower related to system output performance warranties and system repairs in connection with less than $0.1 million of system output performance warranty accrual and $0.2 million of system repairs accrual recorded in the “Accounts payable and other current liabilities” line item on the consolidated balance sheet as of November 30, 2017. Similarly, other current assets included $0.5 million due from SunPower related to system output performance warranties and system repairs in connection with $0.2 million of system output performance warranty accrual and $0.3 million of system repairs accrual recorded in the “Accounts payable and other current liabilities” line item on the consolidated balance sheet as of November 30, 2016.

(3) Construction-in-progress as of November 30, 2016 is comprised of project assets related to the Kern Phase 1(a) Assets, the Kern Phase 2(a) Assets and the Macy’s Maryland Project which achieved commercial operations in fiscal 2017.

(4) Intangible assets represent a customer contract intangible that is amortized on a straight-line basis beginning on COD through the contract term end date of December 31, 2020. Operating revenues were reduced by $0.4 million, $0.1 million and zero in fiscal 2017, 2016 and 2015, respectively. As of November 30, 2017, the estimated future amortization expense related to the customer contract intangible is $0.4 million for each of fiscal years 2018, 2019 and 2020, and less than $0.1 million for fiscal year 2021.

Current Liabilities

	As of
(in thousands)	November 30, 2017		November 30, 2016
Accounts payable and other current liabilities
Trade and accrued accounts payable	$	2,044	$	1,089
Related party payable (1)	1,047		20,653
System output performance warranty	45		196
Residential lease system repairs accrual	158		331
Other short-term liabilities	1,100		1,502
	$	4,394	$	23,771

(1) Related party payable on the consolidated balance sheet as of November 30, 2017 consists of (i) $0.9 million related to accrued distributions to tax equity investors, and (ii) $0.1 million for accounts payable to related parties associated with O&M, AMA and MSA fees owed to the Sponsors. Related party payable on the consolidated balance sheet as of November 30, 2016 consists of (i) $19.5 million related to the purchase price payable to SunPower for the Kern Phase 1(a) Acquisition, the Kern Phase 1(b) Acquisition, the Kern Phase 2(a) Acquisition and the Macy’s Maryland Acquisition, which was funded by tax equity investors and subsequently transferred to SunPower in fiscal 2017, (ii) $1.0 million related to accrued distributions to tax equity investors and (iii) $0.1 million for accounts payable to related parties associated with O&M, AMA and MSA fees owed to the Sponsors.

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Note 6. Commitments and Contingencies

Land Use Commitments

The Partnership is a party to various agreements that provide for payments to landowners for the right to use the land upon which projects under PPAs are located.

Total lease and easement expense was $2.2 million, $2.1 million and $1.1 million in fiscal 2017, 2016 and 2015, respectively, and is classified as SG&A expenses by the Predecessor prior to IPO then reclassified to cost of operations post-IPO in the Partnership’s accompanying consolidated statements of operations.

The total minimum lease and easement commitments at November 30, 2017 under these land use agreements are as follows:

(in thousands)	2018		2019		2020		2021		2022	Thereafter		Total
Land use payments	$	1,329	$	1,686	$	1,742	$	1,782	$1,822	$	54,590	$	62,951

Solar Power System Performance Warranty

Lease agreements require the Partnership to undertake a system output performance warranty. The Partnership has recorded in “Accounts payable and other current liabilities” amounts related to these system output performance warranties totaling less than $0.1 million and $0.2 million as of November 30, 2017 and November 30, 2016, respectively. The Partnership has also recorded in “Other current assets” amounts of less than $0.1 million and $0.2 million as of November 30, 2017 and November 30, 2016, respectively, relating to anticipated performance warranty reimbursements from the O&M provider.

The following table summarizes accrued solar power systems performance warranty activities:

	Year Ended
(in thousands)	November 30, 2017			November 30, 2016
Balance at the beginning of the period	$	196		$	237
Settlements during the period	(85		)	(285		)
Adjustments during the period	(66		)	244
Balance at the end of the period	$	45		$	196

Asset Retirement Obligations

The Partnership’s AROs are based on estimated third-party costs associated with the decommissioning of the applicable project assets. Revisions to these costs may increase or decrease in the future as a result of changes in regulations, engineering designs and technology, permit modifications, inflation or other factors. Decommissioning activities generally occur over a period of time commencing at the end of the system’s life.

The following table summarizes ARO activities:

	Year Ended
(in thousands)	November 30, 2017			November 30, 2016
Balance at the beginning of the period	$	13,448		$	9,992
ARO assumed in acquisition	772			2,989
Accretion expense	762			539
Revisions to ARO during the period	(12		)	(72		)
Balance at the end of the period	$	14,970		$	13,448

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Legal Proceedings

In the normal course of business, the Partnership may be notified of possible claims or assessments. The Partnership will record a provision for these claims when it is both probable that a liability has been incurred and the amount of the loss, or a range of the potential loss, can be reasonably estimated. These provisions are reviewed regularly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel and other information or events pertaining to a particular case.

Although the Partnership may, from time to time, be involved in litigation and claims arising out of its operations in the ordinary course of business, the Partnership is not a party to any litigation or governmental or other proceeding that the Partnership believes will have a material adverse impact on its financial position, results of operations, or liquidity.

Environmental Contingencies

The Partnership reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. During fiscal 2017, 2016 and 2015, there were no known environmental contingencies that required the Partnership to recognize a liability.

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Note 7. Lease Agreements and Power Purchase Agreements

Lease Agreements

As of November 30, 2017, the Partnership’s consolidated financial statements include approximately 5,800 residential lease agreements which have original terms of 20 years and are classified as either operating or sales-type leases. In addition, the lease agreement for the Maryland Solar Project has a lease term that will expire on December 31, 2019, and the lessee, who is an affiliate of First Solar, is obligated to pay a fixed amount of rent that is set based on the expected operations of the plant.

The following table presents the Partnership’s minimum future rental receipts on operating leases (including the lease agreement for the Maryland Solar Project and the residential lease portfolio) placed in service as of November 30, 2017:

(in thousands)	2018		2019		2020		2021		2022		Thereafter		Total
Minimum future rentals on residential operating leases placed in service (1)	$	3,678	$	3,715	$	3,736	$	3,758	$	3,781	$	38,490	$	57,158
Maryland Solar lease	5,173		4,912		—		—		—		—		10,085
Total operating leases	$	8,851	$	8,627	$	3,736	$	3,758	$	3,781	$	38,490	$	67,243

(1) Minimum future rentals on operating leases placed in service do not include contingent rentals that may be received from customers under agreements that include performance-based incentives and executory costs.

As of November 30, 2017, future maturities of net financing receivables for sales-type leases are as follows:

(in thousands)	2018		2019		2020		2021		2022		Thereafter		Total
Scheduled maturities of minimum lease payments receivable (1)	$	5,724	$	5,663	$	5,752	$	5,845	$	5,940	$	64,237	$	93,161

(1) Minimum future rentals on sales-type leases placed in service do not include contingent rentals that may be received from customers under agreements that include performance-based incentives and executory costs.

Power Purchase Agreements

Under the terms of various PPAs, the Partnership’s contracted counterparties may be obligated to take all or part of the output from the system at stipulated prices over defined periods. All PPAs associated with solar generation systems operating as of November 30, 2017 have no minimum lease payments and all of the rental income under these agreements is recorded as revenue when the electricity is delivered.

SREC Sales Agreement

 Under the terms of the Partnership's SREC Sales Agreement, the contracted counterparty is obligated to purchase an annual number of SRECs from the Partnership at stipulated prices over a defined period of time. As of November 30, 2017, firm sales under the Partnership's SREC Sales Agreement are as follows:

(in thousands)	2018		2019		2020		2021		2022		Thereafter		Total
SREC sales	$	642	$	781	$	781	$	195	$	—	$	—	$	2,399

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Note 8. Debt and Financing Obligations

The following table summarizes the Partnership’s debt on its consolidated balance sheets:

	November 30, 2017					November 30, 2016
(in thousands)	Amount			Interest Rate		Amount			Interest Rate
Term loan due June 2020	$	300,000		3.35	%	$	300,000		2.61	%
Incremental term loan due June 2020	250,000			3.35	%	—			N/A
Delayed draw term loan facility due June 2020	25,000			3.35	%	25,000			2.61	%
Revolving credit facility due June 2020	70,000			3.35	%	63,000			2.61	%
Stateline Promissory Note due December 2020	49,631			4.00	%	—			N/A
Short-Term Note	—			N/A		1,964			N/A
Less: debt issuance costs	(2,555		)	N/A		(3,564		)	N/A
Total	$	692,076				$	386,400

OpCo's Credit Facility

On June 5, 2015, OpCo entered into a $525.0 million credit facility, consisting of a $300.0 million term loan facility, a $25.0 million delayed draw term loan facility and a $200.0 million revolving credit facility. On April 6, 2016, the parties thereto amended the credit facility (i) to provide for the lenders’ consent to the Omnibus Agreement, (ii) to expand OpCo’s ability to further amend the Omnibus Agreement without lender consent in the future, subject to certain conditions, (iii) to permit certain customary restrictions on transfers of the equity interests of certain Project Entities, which are jointly owned, indirectly, by OpCo and SunPower, (iv) to supplement the Pledge and Security Agreement between the parties in light of the foregoing amendment and (v) to make certain clarifying modifications to definitions and cross references. On September 30, 2016, OpCo entered into the Joinder Agreement, pursuant to which OpCo obtained a new $250.0 million incremental term loan facility, increasing the maximum borrowing capacity under the credit facility to $775.0 million.

Loans outstanding under the credit facility bear interest at either (i) a base rate, which is the highest of (x) the federal funds rate plus 0.50%, (y) the administrative agent’s prime rate and (z) one-month LIBOR, in each case, plus an applicable margin; or (ii) one-, two-, three- or six-month LIBOR plus an applicable margin. There will be no principal amortization over the term of the credit facility. The unused portion of the revolving credit facility and delayed draw term loan facility is subject to a commitment fee of 0.30% per annum. OpCo may prepay the borrowings under the term loan facility and the delayed draw term loan facility at any time. OpCo has entered into interest rate swap agreements to hedge the interest rate on a portion of the borrowings under the term loan facility. Please read “—Note 9—Fair Value” for further details.

OpCo’s credit facility contains covenants including, among others, requiring the Partnership to maintain the following financial ratios: (i) a debt to cash flow ratio of not more than (a) 6.00 to 1.00 for the fiscal quarters ending November 30, 2016 through November 30, 2017; and (b) 5.50 to 1.00 for each fiscal quarter ending thereafter; and (ii) a debt service coverage ratio of not less than 1.75 to 1.00. In addition, an event of default occurs under the credit facility upon a change of control. The credit facility defines a change of control as occurring when, among other things, (i) the Sponsors (or either of them) cease to direct the management, directly or indirectly, of the Partnership or OpCo, or (ii) the Sponsors collectively cease to own 35% of the economic interest in OpCo. On February 5, 2018, the Partnership, its general partner, OpCo, Holdings and the other parties thereto entered into the Merger Agreement. Upon the terms and subject to the conditions set forth in the Merger Agreement, immediately after the consummation of OpCo Merger 1, the credit facility will be repaid in full and extinguished. Please read “—Note 17—Subsequent Events” for further details. In addition, the credit facility contains customary non-financial covenants and certain restrictions that will limit the Partnership’s, OpCo’s and certain of the Partnership’s and its domestic subsidiaries’ ability to, among other things, incur or guarantee additional debt and to make distributions on or redeem or repurchase OpCo common units. The Joinder Agreement amended OpCo’s credit facility to permit OpCo to incur up to $50.0 million in subordinated indebtedness from First Solar or its affiliate to pay a portion of the purchase price for the Stateline Project. As of November 30, 2017, the Partnership was in compliance with its debt covenants.

OpCo’s credit facility is collateralized by a pledge of the equity of OpCo and certain of its subsidiaries. The Partnership and each of OpCo’s subsidiaries, other than certain non-guarantor subsidiaries, have guaranteed the obligations of OpCo under the credit facility.

As of November 30, 2017 and November 30, 2016, OpCo had approximately $54.6 million and $54.9 million, respectively, of letters of credit outstanding under the revolving credit facility.

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Stateline Promissory Note

On December 1, 2016, in connection with the Stateline Acquisition, OpCo issued a promissory note to First Solar in the principal amount of $50.0 million. The Stateline Promissory Note is unsecured and matures on the date that is six months after the maturity date under OpCo’s credit facility. Interest will accrue at a rate of 4.00% per annum, except it will accrue at a rate of 6.00% per annum (i) upon the occurrence and during the continuation of a specified event of default and (ii) in respect of amounts accrued as payments-in-kind pursuant to the terms of the Stateline Promissory Note. OpCo is not permitted to prepay the $50.0 million promissory note without the consent of certain lenders under its existing credit agreement (except for certain mandatory prepayments). Until OpCo has paid in full the principal and interest on the Stateline Promissory Note, OpCo is restricted in its ability to: (i) acquire interests in additional projects (other than the acquisition of the Kern Phase 2(a) Assets, the Kern Phase 2(b) Assets and the Kern Phase 2(c) Assets); (ii) use the net proceeds of equity issuances except as prescribed in the promissory note; (iii) incur additional indebtedness to which the promissory note would be subordinate; and (iv) extend the maturity date under OpCo’s existing credit facility.

Short-Term Note

On November 25, 2015, OpCo issued the Short-Term Note to First Solar in the principal amount of $2.0 million, in exchange for First Solar’s loan of such amount to OpCo. Upon the receipt of certain payments by the Solar Gen 2 Project Entity from SDG&E under the power purchase agreement between the Solar Gen 2 Project Entity and SDG&E, which had been previously withheld pending completion of an administrative requirement (each, a “Specified Payment”), OpCo was obligated to repay a portion of the principal amount of the Short-Term Note equal to such Specified Payment and the unpaid balance of all interest accrued under the Short-Term Note to and including the date of such repayment. Interest under the Short-Term Note accrued at a rate of 1% on the portion of the principal of the Short-Term Note equal to the amount of each Specified Payment from the date SDG&E remitted such payment to the Solar Gen 2 Project Entity through the date that OpCo repaid such amount to First Solar as described above. OpCo is permitted to prepay the Short-Term Note at any time without penalty or premium. On December 30, 2016, OpCo repaid the Short-Term Note to First Solar. On December 30, 2016, OpCo repaid the Short-Term Note to First Solar.

Quinto Solar Project Financing

In order to facilitate the construction of certain projects, the Predecessor obtained non-recourse project loans from third-party financial institutions. In October 2014, the Predecessor, through its wholly owned subsidiary, the Quinto Project Entity, entered into an approximately $377.0 million credit facility with Santander Bank, N.A., Mizuho Bank, Ltd. and Credit Agricole Corporate & Investment Bank (the “Quinto Credit Facility”) in connection with the construction of the Quinto Project.

On June 24, 2015, in connection with the closing of the IPO and the concurrent transfer of the Quinto Project to OpCo, the Quinto Project Entity repaid the full amount outstanding under the Quinto Credit Facility and terminated the agreement early. Immediately before termination, there were outstanding borrowings of $224.3 million under the Quinto Credit Facility. Termination of the Quinto Credit Facility became effective upon full repayment by the Quinto Project Entity on June 24, 2015. The Quinto Project Entity paid a $0.6 million fee for early repayment of the Quinto Credit Facility.

Residential Lease Financing

Prior to fiscal 2015, the Predecessor entered into two financing arrangements under which leased solar power systems were financed by two third-party investors. Under the terms of these financing arrangements, the investors provided upfront payments to the Predecessor, which the Predecessor recognized as a financing obligation that is reduced over the specified term of the arrangement as customer receivables and federal cash grants are received by the third-party investors. The Partnership recognized non-cash interest expense on its consolidated statements of operations using the effective interest rate method calculated at a rate of approximately 14%-15% in fiscal 2015.

On January 30, 2015, the Predecessor paid $10.8 million to terminate one of the financing arrangements with an outstanding principal balance of $10.1 million. On May 4, 2015. the Predecessor paid $29.0 million to terminate the remaining financing arrangement, which had an outstanding principal balance of $21.1 million and $1.9 million of accrued financing fees. The Partnership recognized a combined loss of $6.7 million within other expense (income) on its consolidated statements of operations related to the termination of the two financing arrangements in fiscal 2015.

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SunPower Credit Facility

In August 2011, the Predecessor’s parent, SunPower, entered into a letter of credit facility agreement with Deutsche Bank, as administrative agent, and certain financial institutions. Payment of obligations under the letter of credit facility is guaranteed by the majority shareholder of SunPower, Total S.A. As of November 30, 2017 and November 30, 2016, letters of credit issued and outstanding under the SunPower Credit Facility with Deutsche Bank which is available to SunPower for the Quinto Project and the RPU Project totaled $0.2 million and $11.5 million, respectively. Pursuant to the Omnibus Agreement, SunPower, as the Sponsor who contributed the Quinto Project, canceled one of its letter of credit facilities associated with the Quinto Project upon its achieving COD in November 2015. Since the RPU Project achieved COD in September 2015, SunPower, as the Sponsor who contributed the RPU Project, canceled the related letters of credit, and the Partnership has issued the required letters of credit under its revolving credit facility.

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Note 9. Fair Value

Fair value is estimated by applying the following hierarchy, which prioritizes the inputs used to measure fair value into three levels and bases the categorization within the hierarchy upon the lowest level of input that is available and significant to the fair value measurement (observable inputs are the preferred basis of valuation):

• Level 1—Quoted prices in active markets for identical assets or liabilities.

• Level 2—Measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1.

• Level 3—Prices or valuations that require management inputs that are both significant to the fair value measurement and unobservable.

The first two levels in the hierarchy are considered observable inputs and the last is considered unobservable.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table presents the Partnership’s assets and liabilities measured at estimated fair value on a recurring basis, categorized in accordance with the fair value hierarchy:

	November 30, 2017				November 30, 2016
	FAIR VALUE MEASUREMENTS				FAIR VALUE MEASUREMENTS
(in thousands)	Level 2		Total		Level 2		Total
Assets
Derivative financial instruments	$	1,603	$	1,603	$	897	$	897
Total assets	$	1,603	$	1,603	$	897	$	897

Derivative financial instruments: On July 17, 2015, OpCo entered into interest rate swap agreements intended to hedge the interest rate risk on the outstanding borrowings under the term loan with an aggregate notional value of $240.0 million. Under the interest rate swap agreements, OpCo paid a fixed swap rate of interest of 1.55% and the counterparties to the agreements paid a floating interest rate based on three-month LIBOR at quarterly intervals through the maturity date of August 31, 2018. OpCo had the right to cancel the interest rate swap agreements on August 31, 2016 and any quarterly fixed payment date thereafter with a minimum of five business days' notification. OpCo exercised its right to cancel the interest rate swap agreements on August 31, 2016 and entered into new interest rate swap agreements intended to hedge the interest rate risk on the outstanding borrowings under the term loan with an aggregate notional value of $250.0 million. Under the new interest rate swap agreements, OpCo will pay a fixed swap rate of interest of approximately 0.85% and the counterparties to the agreements will pay a floating interest rate based on one-month LIBOR at monthly intervals through the maturity date of August 31, 2018. On January 5, 2017, OpCo entered into another interest rate swap agreement intended to hedge the interest rate risk on the outstanding borrowings under the term loan with an aggregate notional value of $40.0 million. Under this interest rate swap agreement, OpCo will pay a fixed swap rate of interest of approximately 1.16% and the counterparty to the agreement will pay a floating interest rate based on one-month LIBOR at monthly intervals through the maturity date of August 31, 2018.

As of both November 30, 2017 and November 30, 2016, these interest rate swap agreements had not been designated as cash flow hedges and are reflected at fair value on the consolidated balance sheets. As of November 30, 2017, these interest rate swap agreements are presented in other current assets on the consolidated balance sheet since the maturity date is within one year after the balance sheet date. As of November 30, 2016, these interest rate swap agreements are presented in other long-term assets on the consolidated balance sheet since the maturity date is over one year after the balance sheet date. 

During fiscal 2017, 2016 and 2015, the Partnership recorded an unrealized gain of $0.7 million, an unrealized gain of $1.5 million, and an unrealized loss of $0.6 million, respectively, within other expense (income) in the consolidated statements of operations related to the change in fair value. The primary inputs into the valuation of interest rate swaps are interest yield curves, interest rate volatility and credit spreads. The Partnership's interest rate swaps are classified within Level 2 of the fair value hierarchy, since all significant inputs are corroborated by market observable data. There were no transfers in or out of Level 1, Level 2 and Level 3 during any period.

The Predecessor entered into interest rate swap agreements, designated as cash flow hedges, in the fourth quarter of fiscal 2014 on the outstanding and forecasted future borrowings under the Quinto Credit Facility to reduce the impact of changes in interest rates. These swap agreements allowed the Predecessor to effectively convert floating-rate payments into

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fixed-rate payments periodically over the life of the agreements. These derivatives had a maturity of more than 12 months. The Predecessor assessed the effectiveness of these cash flow hedges at inception and on a quarterly basis. If it was determined that a derivative instrument was not highly effective or the transaction was no longer deemed probable of occurring, the Predecessor discontinued hedge accounting and recognized the ineffective portion in current period earnings. The hedge became ineffective in the first half of fiscal 2015 and the ineffective portion was recognized in earnings at that time. The interest swap was terminated upon the IPO and the remaining ineffective portion was recognized in earnings. During fiscal 2015, $5.4 million was reclassified into loss on cash flow hedges within other expense, net in the consolidated statements of operations, as the transaction was terminated. 

Liabilities Measured at Fair Value on a Nonrecurring Basis

Long-term debt and financing obligations: The estimated fair value of the Partnership’s long-term debt was classified within Level 2 of the fair value hierarchy as of November 30, 2017 and November 30, 2016, and approximated its carrying value of $692.1 million and $384.4 million, respectively. Borrowings under the credit facility are variable rate debt with the interest rate indexed to the market and reset on a frequent and short-term basis. The Stateline Promissory Note is a fixed-rate debt and the fair value was estimated using the income approach based on observable market inputs.

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Note 10. Noncontrolling Interests

Noncontrolling interests represent the portion of net assets in consolidated subsidiaries that are not attributable, directly or indirectly, to the Partnership. For accounting purposes, the holders of noncontrolling interests of the Partnership include the Sponsors, which are SunPower and First Solar, as described in “—Note 1—Description of Business,” and third-party investors under the tax equity financing facilities. As of both November 30, 2017 and November 30, 2016, First Solar and SunPower had noncontrolling interests of 28.0% and 36.5%, respectively, in OpCo.

In addition, certain subsidiaries of OpCo have entered into tax equity financing facilities with third-party investors under which the parties invest in entities that hold the solar power systems. The Partnership, through OpCo, holds controlling interests in these less-than-wholly owned entities and has therefore fully consolidated these entities. The Partnership accounts for the portion of net assets in the consolidated entities attributable to the investors as “Redeemable noncontrolling interests” and “Noncontrolling interests” in its consolidated financial statements using the HLBV Method. Noncontrolling interests in subsidiaries that are redeemable at the option of the noncontrolling interest holder are classified as “Redeemable noncontrolling interests in subsidiaries” between liabilities and equity on the consolidated balance sheets and the balance is the greater of the carrying value calculated under the HLBV Method or the redemption value.

As of November 30, 2017 and November 30, 2016, redeemable noncontrolling interests attributable to tax equity investors after adjusting the carrying amount to the redemption value was $17.3 million and $17.6 million, respectively, and noncontrolling interests attributable to tax equity investors were $55.3 million and $40.8 million, respectively.

During fiscal 2017, 2016 and 2015, such indirect subsidiaries of OpCo attributed $6.5 million, $126.4 million, and $102.2 million, respectively, in losses to the third-party investors primarily as a result of allocating certain assets, including tax credits, if any, to the investors.

The following table presents the noncontrolling interest balances by entity, reported in shareholders’ equity in the consolidated balance sheets:

	As of
(in thousands)	November 30, 2017		November 30, 2016
First Solar	$	230,039	$	238,210
SunPower	300,670		311,327
Tax equity investors	55,341		40,794
Total	$	586,050	$	590,331

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Note 11. Shareholder’s Equity

The Partnership’s Class A shares and Class B shares represent limited partner interests in the Partnership. The Partnership’s partnership agreement authorizes the issuance of an unlimited number of Class A shares and Class B shares. The number of Class A shares issued by the Partnership will at all times equal the number of OpCo common units held by the Partnership. The number of Class B shares issued by the Partnership will at all times equal the aggregate number of OpCo common and subordinated units held by persons or entities other than the Partnership. The holders of Class A shares and Class B shares are entitled to exercise the rights or privileges available to limited partners under the partnership agreement, but only holders of Class A shares are entitled to participate in the Partnership’s distributions. Holders of Class B Shares, in their capacity as such, do not have any rights to profits or losses or any rights to receive distributions from operations or upon the liquidation or winding-up of the Partnership. Each Class B share is entitled to one vote on matters that are submitted to the Partnership’s Class B shareholders for a vote. Class A shares and the Class B shares are treated as a single class on all such matters submitted for a vote of the Partnership’s Class A and Class B shareholders other than votes requiring a share majority during the subordination period as described above. The Partnership is required to distribute its available cash (as defined in the Partnership’s partnership agreement) to the holders of Class A shares each quarter. The Partnership’s Class A shareholders and Class B shareholders have only limited voting rights and at times vote together or as separate classes. These voting rights include, but are not limited to, certain amendments to the Partnership’s partnership agreement, merger or dissolution of the Partnership or the sale of all or substantially all of the Partnership’s assets and removal of the General Partner. The Partnership’s shareholders are not entitled to elect the General Partner or its directors. If at any time the General Partner and its affiliates control more than 80% of the aggregate of (i) the number of Class A shares then outstanding and (ii) the number of Class B shares equal to the number of OpCo common units owned by the Sponsors and their affiliates, the General Partner will have the right to acquire all, but not less than all, of the shares of such class then outstanding held by unaffiliated persons as of a record date to be selected by the General Partner, on at least ten but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of (i) the highest cash price paid by either of the General Partner or any of its affiliates for any share of the class purchased within the 90 days preceding the date on which the General Partner first mails notice of its election to purchase those shares; and (ii) the current market price calculated in accordance with the Partnership’s partnership agreement as of the date three business days before the date the notice is mailed. The Partnership is a party to an Exchange Agreement whereby it has agreed in certain situations to issue Class A shares to the Sponsors in exchange for an equal number of Class B shares and OpCo common units. Under the terms of the Exchange Agreement, each Sponsor has the right to receive, at the election of OpCo and with the approval of the Conflicts Committee, either the number of the Class A shares equal to the number of Tendered Units or a cash payment equal to the number of Tendered Units multiplied by the then current trading price of Class A shares. Alternatively, each of OpCo and Partnership have the right, with the approval of the Conflicts Committee, to acquire such Class B shares and OpCo common units for cash.

OpCo’s equity consists of common units and subordinated units and incentive distribution rights (“IDRs”), which represent a variable interest in distributions after certain distribution thresholds are met. OpCo’s limited liability company agreement authorizes the issuance of an unlimited number of common units and subordinated units. OpCo is required to distribute its available cash (as defined in OpCo’s limited liability company agreement) to the holders of its common units, subordinated units and IDRs each quarter. Distributions, other than liquidating distributions, are made to such holders according to a predetermined waterfall. During the subordination period, OpCo’s common units have a preference on such distributions until each unit has received the minimum quarterly distribution for such quarter and any arrearages on the minimum quarterly distribution for previous quarters and OpCo’s common units and subordinated units have a preference on such distributions until each unit has received 150% of the minimum quarterly distribution for such quarter. Thereafter, the IDRs are entitled to an increasing amount of any excess distributed. After the subordination period, holders of OpCo units have a preference over the IDRs on such distributions until each unit has received 150% of the minimum quarterly distribution for such quarter. Liquidating distributions are made according to the balance in each holder’s capital account upon liquidation. Similar to the voting rights of Class A shareholders and Class B shareholders, OpCo’s common unitholders and subordinated unitholders have only limited voting rights and at times vote together or as separate classes. These voting rights include, but are not limited to, certain amendments to OpCo’s limited liability company agreement, merger or dissolution of OpCo or the sale of all or substantially all of OpCo’s assets. Holders of IDRs have no voting rights.

Initial Public Offering

On June 24, 2015, the Partnership completed its IPO by issuing 20,000,000 of its Class A shares representing limited partner interests in the Partnership at a price to the public of $21.00 per share for aggregate gross proceeds of $420.0 million. The underwriting discount of $23.1 million and the structuring fee of $3.2 million paid to the underwriters, for a total of $26.3 million, were deducted from the gross proceeds from the IPO. This amount excludes offering expenses, which were paid by the Sponsors. On June 18, 2015, the Partnership granted the underwriters a 30-day option to purchase up to an additional 3,000,000 Class A shares representing limited partner interests in the Partnership at the IPO price less underwriting discount and

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structuring fee. If the underwriter’s option to purchase additional shares was unexercised in full, OpCo would be required to issue in the aggregate to SunPower and First Solar an amount of common units equal to the amount of Class A shares subject to the underwriter’s option to purchase additional shares that remained unexercised. Additionally, under OpCo’s limited liability company agreement, in the event OpCo issues common units to any person or entity other than the Partnership, the Partnership agreed to issue the same number of Class B shares to such other person or entity. As a result of the expiration of the underwriter’s option to purchase additional shares without the exercise of any portion thereof, on July 19, 2015, the Partnership issued additional Class B shares of 1,300,995 and 1,699,005 to First Solar and SunPower, respectively.

As of November 30, 2015, the Partnership owned a 28.2% limited liability company interest in OpCo as well as a controlling noneconomic managing member interest in OpCo and the Sponsors collectively owned 51,000,000 Class B shares in the Partnership, with SunPower and First Solar having owned 28,883,075 and 22,116,925 Class B shares, respectively, and together, having owned a noncontrolling 71.8% limited liability company interest in OpCo.

The Partnership received net proceeds of $393.8 million from the sale of the Class A shares after deducting underwriting fees and structuring fees (exclusive of offering expenses paid by the Sponsors).

The Partnership used all of the net proceeds of the IPO to purchase 20,000,000 OpCo common units from OpCo. OpCo (i) used approximately $154.4 million of such net proceeds to make a cash distribution to First Solar and, approximately $201.6 million of such net proceeds to make a cash distribution to SunPower and (ii) retained approximately $37.8 million of such net proceeds for general purposes, including to fund future acquisition opportunities.

September 2016 Offering

On September 28, 2016, the Partnership sold 8,050,000 Class A shares at a price to the public of $14.65 per share, for aggregate gross proceeds of $117.9 million, in an underwritten registered public offering (“September 2016 Offering”). The underwriting discount of $3.5 million paid to the underwriters and associated expenses of $1.1 million, for a total of $4.6 million, were deducted from the gross proceeds from the September 2016 Offering. The Partnership received net proceeds of $113.3 million from the sale of the Class A shares after deducting underwriting fees and associated expenses. The Partnership used all of the net proceeds from the September 2016 Offering to purchase 8,050,000 OpCo common units from OpCo. OpCo used such net proceeds from the sale of common units to fund a portion of the purchase price for the 49% interest in the Henrietta Project.

ATM Program

On January 30, 2017, the Partnership established the ATM Program under which it may sell its Class A shares from time to time through the ATM Agents up to an aggregate sales price of $125.0 million. The Partnership may also sell its Class A shares to any ATM Agent, as principal for its own account, at a price agreed upon at the time of the sale. The Partnership will use the net proceeds from sales under the ATM Program to purchase a number of common units in OpCo equal to the number of Class A shares issued under the ATM Program. OpCo may use the proceeds for general corporate purposes, which may include, among other things, repaying borrowings under the Stateline Promissory Note and OpCo’s credit facilities, and funding working capital or acquisitions. No shares were issued under the ATM Program during fiscal 2017.

As of both November 30, 2017 and November 30, 2016, the Partnership owned a 35.5% limited liability company interest in OpCo as well as a controlling noneconomic managing member interest in OpCo, and the Sponsors collectively owned 51,000,000 Class B shares in the Partnership, with SunPower and First Solar having owned 28,883,075 and 22,116,925 Class B shares, respectively, and together, having owned a noncontrolling 64.5% limited liability company interest in OpCo. 

The following table presents the Partnership's number of shares outstanding: 

	As of
Shares	November 30, 2017	November 30, 2016	Shareholder
Class A shares	28,088,673	28,072,680	Public
Class B shares	22,116,925	22,116,925	First Solar
Class B shares	28,883,075	28,883,075	SunPower
Total shares outstanding	79,088,673	79,072,680

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Cash Distributions

The Partnership is required to distribute its available cash (as defined in the Partnership Agreement) to the holders of Class A shares each quarter effective the third quarter of 2015.

On April 14, 2017, the Partnership distributed $20.3 million on its Class A shares and OpCo’s common and subordinated units, or $0.2565 per share for the period from December 1, 2016 to February 28, 2017. On July 14, 2017, the Partnership distributed $20.9 million on its Class A shares and OpCo’s common and subordinated units, or $0.2642 per share for the period from March 1, 2017 to May 31, 2017. On October 13, 2017, the Partnership distributed $21.5 million on its Class A shares and OpCo’s common and subordinated units, or $0.2721 per share for the period from June 1, 2017 to August 31, 2017. On January 12, 2018, the Partnership distributed $22.2 million on its Class A shares and OpCo’s common and subordinated units, or $0.2802 per share for the period from September 1, 2017 to November 30, 2017.

On April 14, 2016, the Partnership distributed $4.5 million on its Class A shares, or $0.2246 per share for the period from December 1, 2015 to February 29, 2016. On July 15, 2016, the Partnership distributed $4.7 million on its Class A shares, or $0.2325 per share for the period from March 1, 2016 to May 31, 2016. On October 14, 2016, the Partnership distributed $19.0 million on its Class A shares and OpCo’s common and subordinated units, or $0.2406 per share or unit for the period from June 1, 2016 to August 31, 2016. On January 13, 2017, the Partnership distributed $19.7 million on its Class A shares and OpCo’s common and subordinated units, or $0.2490 per share or unit for the period from September 1, 2016 to November 30, 2016.

On October 15, 2015, the Partnership distributed $3.1 million on its Class A shares, or $0.157 per share. This amount represented the prorated minimum quarterly distribution of $0.2097 per OpCo unit, or $0.8388 per OpCo unit on an annualized basis for the post-IPO period from June 24, 2015 to August 31, 2015. On January 14, 2016, the Partnership distributed $4.3 million on its Class A shares, or $0.217 per share for the period from September 1, 2015 to November 30, 2015.

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Note 12. Share-based Compensation

The Partnership adopted the 8point3 General Partner, LLC Long-Term Incentive Plan (the “LTIP”) for employees, directors and consultants of the General Partner or its affiliates who perform services for the Partnership or its affiliates and filed a Form S-8 for its LTIP on July 14, 2015. Awards under the LTIP may consist of unrestricted shares, restricted shares, restricted share units, options, share appreciation rights and distribution equivalent rights. The LTIP limits the number of shares that may be delivered pursuant to awards to 2,000,000 Class A shares and provides that no director may receive awards in any calendar year with a grant date value in excess of $250,000. Shares that are withheld to satisfy exercise price or tax withholding obligations are available for delivery pursuant to other awards.

The LTIP will expire upon the earliest of the date established by the Board or a committee thereof, the tenth anniversary of its adoption or the date that no shares remain available under the LTIP for awards. Upon termination of the LTIP, awards then outstanding will continue pursuant to the terms of their grants. Class A shares to be delivered pursuant to awards under the LTIP may be Class A shares acquired in the open market, Class A shares already owned by the General Partner, Class A shares acquired by the General Partner from the Partnership or from any other person, or any combination thereof.

Participants will not pay any consideration for the Class A shares they receive, nor will the Partnership receive any remuneration for these shares as the Partnership intends these awards to serve as a means of incentive compensation for performance. The committee has the discretion to determine the employees, consultants and directors to whom equity awards shall be granted, the number of shares to be granted, and the vesting and other terms of the award as applicable (such as whether the award will be based on the achievement of specific financial or performance metrics).

During fiscal 2017, fiscal 2016 and fiscal 2015, the Partnership issued an aggregate of 15,993, 15,399 and 7,281 Class A shares, respectively, to the three independent members of the Board. These shares were unrestricted and had no vesting period. Share-based compensation expense included in SG&A for fiscal 2017, fiscal 2016 and fiscal 2015 was $0.2 million, $0.2 million and $0.1 million, respectively, with weighted-average grant-date fair values of $14.08, $14.62 and $15.45 per share, respectively.

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Note 13. Net Income Per Share

Basic net income per share is computed by dividing net income attributable to Class A shareholders by the weighted average number of Class A shares outstanding for the applicable period. Diluted net income per share is computed using basic weighted average Class A shares outstanding plus, if dilutive, any potentially dilutive securities outstanding during the period using the treasury-stock-type method. Pursuant to the Exchange Agreement entered into among the Partnership, the General Partner, OpCo, a wholly owned subsidiary of SunPower and a wholly owned subsidiary of First Solar, the Sponsors can tender OpCo common units and an equal number of such Sponsor’s Class B shares for redemption, and the Partnership has the right to directly purchase the tendered OpCo common units and Class B shares for, subject to the approval of its Conflicts Committee, cash or the issuance of Class A shares of the Partnership. If the Partnership elects to issue Class A shares, it would cancel the tendered Class B shares and hold the OpCo common units with the other OpCo common units it previously held, since the number of Class A shares issued must at all times equal the number of OpCo common units held by the Partnership. Since the Partnership would be holding additional OpCo common units, the net income attributable to Class A shares would proportionately increase, resulting in no change to net income per share for fiscal 2017, 2016 and 2015. In addition, there were no potentially dilutive securities (including any stock options, restricted stock and restricted stock units) for fiscal 2017, fiscal 2016 and fiscal 2015.

The following table presents the calculation of basic and diluted net income per share:

	Year Ended				Eleven Months Ended
(in thousands, except per share amounts)	November 30, 2017		November 30, 2016		November 30, 2015
Basic net income per share:
Numerator:
Net income attributable to Class A shareholders	$	11,407	$	27,101	$	18,726
Denominator:
Basic weighted-average shares	28,079		21,420		20,002
Basic net income per share	$	0.41	$	1.27	$	0.94
Diluted net income per share:
Numerator:
Net income attributable to Class A shareholders	$	11,407	$	27,101	$	18,726
Add: Additional net income attributable to Class A shares due to increased percentage ownership in OpCo, net of tax, from the conversion of Class B shares	6,866		20,466		14,474
	$	18,273	$	47,567	$	33,200
Denominator:
Basic weighted-average shares	28,079		21,420		20,002
Effect of dilutive securities:
Class B shares (1)	15,500		15,500		15,032
Diluted weighted-average shares	43,579		36,920		35,034
Diluted net income per share	$	0.41	$	1.27	$	0.94

(1) Up to the amount of OpCo common units held by Sponsors

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Note 14. Related Parties

Management Services Agreements

Immediately prior to the completion of the IPO on June 24, 2015, the Partnership, together with the General Partner, OpCo and Holdings, entered into similar but separate MSAs with affiliates of each of the Sponsors (each, a “Service Provider”). Under the MSAs, the Service Providers provide or arrange for the provision of certain administrative and management services for the Partnership and certain of its subsidiaries, including managing the Partnership’s day-to-day affairs, in addition to those services that are provided under existing O&M agreements and AMAs between affiliates of the Sponsors and certain of the subsidiaries of the Partnership. In August 2015, the First Solar MSA and the SunPower MSA were amended to adjust the annual management fee payable to each respective Service Provider. Under the First Solar MSA, OpCo pays an annual management fee of $0.6 million to the First Solar Service Provider. Under the SunPower MSA, OpCo pays an annual management fee of $1.1 million to the SunPower Service Provider. These payments are subject to annual adjustments for inflation. On January 20, 2017, the parties thereto amended the SunPower MSA to include Kingbird Solar, LLC and the Kingbird Project Entities under certain aspects of SunPower’s scope of managerial services effective April 30, 2016 in return for the associated AMA fee payable by FSAM.

Costs incurred for these services were $1.8 million, $1.7 million and $0.7 million for fiscal 2017, fiscal 2016 and fiscal 2015, respectively.

EPC Agreements

Various projects are designed, engineered, constructed and commissioned pursuant to EPC agreements with affiliates of the Sponsors, which may include a one-year to ten-year system warranty against defects in materials, construction, fabrication and workmanship, and in some cases, may include a 25-year power and product warranty on certain modules. As of November 30, 2017, all of the projects pursuant to the EPC agreements have achieved commercial operations.

O&M Agreements and Asset Management Agreements

The Project Entities and certain other subsidiaries have entered into O&M agreements and AMAs with affiliates of the Sponsors, as applicable (except where such persons are otherwise subject to O&M agreements or AMAs with unaffiliated third parties). Under the terms of the O&M agreements and the AMAs, such affiliates have agreed to provide a variety of operation, maintenance and asset management services, and certain performance warranties or availability guarantees, to the subsidiaries of the Partnership in exchange for annual fees, which are subject to certain adjustments.

O&M services to the leased solar power systems, also known as executory costs, were allocated to the Predecessor by SunPower and disclosed as Cost of Operations—SunPower in the combined carve-out statement of operations of the Predecessor. Costs incurred for O&M and AMA services were $6.6 million, $5.3 million, $0.7 million for fiscal 2017, fiscal 2016 and fiscal 2015, respectively. Other income received from Sponsors for performance guarantees associated with the O&M agreements were $0.1 million for fiscal 2017.

Omnibus Agreement

The Partnership has entered into the Omnibus Agreement with its Sponsors, the General Partner, OpCo and Holdings.

The material provisions of the Omnibus Agreement are as follows: (a) each Sponsor was granted an exclusive right to perform certain services not otherwise covered by an O&M agreement or an AMA on behalf of the Project Entities contributed by such Sponsor; (b) with respect to any project in the Portfolio that had not achieved commercial operation as of the date contributed to the Partnership, the Sponsor who contributed such project agreed to pay to OpCo all costs required to complete such project, as well as certain liquidated damages in the event such project fails to achieve operability pursuant to an agreed schedule (subject to certain adjustments); (c) with respect to the Quinto Project and the North Star Project, the Sponsor who contributed such project agreed to pay to OpCo the difference, if any, between the amount of network upgrade refunds projected to be received in respect of such Sponsor’s contributed project at the time of the IPO and the amount of network upgrade refunds projected to be received given the actual amount of upgrade costs incurred in respect of such project; (d) each Sponsor agreed to certain undertakings on the part of its affiliates who are members of the Project Entities or who provide asset management, construction, operating and maintenance and other services to the Project Entities contributed by such Sponsor; (e) to the extent a Sponsor continues to post credit support on behalf of a Project Entity after it has been contributed to OpCo, OpCo agreed to reimburse such Sponsor upon any demand or draw under such credit support, and the Sponsor agreed to maintain such support pursuant to the applicable underlying contractual or regulatory requirements; (f) each Sponsor agreed to

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indemnify OpCo for any costs it incurs with respect to certain tax-related events and events in connection with tax equity financing arrangements; and (g) the parties agreed to a mutual undertaking regarding confidentiality and use of names, trademarks, trade names and other insignias. The schedules of the Omnibus Agreement are amended in connection with each project acquisition to include the solar power systems acquired effective the closing date of such acquisition.

During fiscal 2017, the Partnership received $0.2 million in indemnity payments from Sponsors related to the delay in commercial operations of the Kern Phase 1(a) Assets and a $0.2 million energy performance test bonus for one of its equity method investments. During fiscal 2016, the Partnership received $10.3 million in indemnity payments from Sponsors, of which $10.0 million related to a shortfall associated with the network upgrade refunds projected to be received, and $0.3 million was for the delay in commercial operations with the Kern Phase 1(a) Assets. During fiscal 2015, the Partnership received $3.9 million in indemnity payments from Sponsors related to a test energy shortfall associated with the Quinto Project.

Promissory Notes

On November 25, 2015, OpCo issued the Short-Term Note to First Solar in the principal amount of $2.0 million, in exchange for First Solar’s loan of such amount to OpCo. On December 30, 2016, OpCo repaid the Short-Term Note to First Solar. Additionally, in connection with the closing of the Stateline Acquisition on December 1, 2016, OpCo issued the Stateline Promissory Note to First Solar in the principal amount of $50.0 million. Please read “—Note 8— Debt and Financing Obligations” for further details.

Purchase and Sale Agreements

Prior to the closing of the IPO, each of (i) Quinto Holdings, (ii) RPU Holdings and (iii) C&I Holdings, entered into purchase and sale agreements (collectively, the “SunPower IPO PSAs”) with affiliates of SunPower in connection with SunPower’s contribution of such entities to OpCo, and also entered into certain tax equity financing arrangements with third-party investors to finance the purchases of such entities. Pursuant to the SunPower IPO PSAs, the purchase prices were paid in installments, which were made when the projects met certain construction milestones, with final installment payments due upon COD. Since these projects have attained COD, there are no purchase price payments remaining.

In fiscal 2017 and fiscal 2016, OpCo entered into purchase and sale agreements with the Sponsors in connection with the acquisitions of entities of the Kern Project, the Kingbird Project, the Hooper Project and the Macy’s Maryland Project, which entities had previously entered into certain tax equity financing arrangements with third party investors. The tax equity investor made capital contributions to fund purchase price payments and is allocated a certain share of cash flows from the project entities pursuant to a specified distribution waterfall. As of November 30, 2017, there are no purchase price payments remaining. Please read “Note 3—Business Combinations” for further details.

In fiscal 2017 and fiscal 2016, OpCo entered into purchase and sale agreements with the Sponsors in connection with the acquisition of minority membership interests of entities in the Henrietta Project and Stateline Project. Please read “Note 4—Investments in Unconsolidated Affiliates” for further details.

First Solar ROFO Agreement

Pursuant to the First Solar ROFO Agreement, First Solar previously granted to OpCo a right of first offer to purchase certain solar energy generating facilities for a period of five years. Such solar power projects included the 179 MW Switch Station solar generation project in Nevada (“Switch Station”), the 40 MW Cuyama solar generation project in California (“Cuyama”), and the 280 MW California Flats solar generation project in California (“California Flats”). On February 13, 2017, OpCo waived the 45-day negotiation period under the First Solar ROFO Agreement with respect to Switch Station and on May 15, 2017, OpCo waived the 45-day negotiation period under the First Solar ROFO Agreement with respect to Cuyama and California Flats; following such waivers, First Solar had the right to offer and sell Switch Station, Cuyama and California Flats to a third party, in accordance with the terms of the First Solar ROFO Agreement. On July 13, 2017, August 17, 2017 and August 22, 2017, First Solar sold the interests subject to the First Solar ROFO Agreement in Switch Station, Cuyama, and California Flats, respectively, to third parties, eliminating OpCo's ability to acquire such interests or any related assets. With First Solar's sale of such interests in Switch Station, Cuyama and California Flats, no further projects remain subject to the First Solar ROFO Agreement.

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SunPower ROFO Agreement

Pursuant to the SunPower ROFO Agreement, SunPower previously granted to OpCo a right of first offer to purchase certain solar energy generating facilities for a period of 5 years. Such solar projects included the 100 MW El Pelicano solar generation project in Chile (“El Pelicano”) and the 100 MW Boulder Solar 1 solar generation project in Nevada (“Boulder Solar”). On February 13, 2017, OpCo entered into the Second Amendment and Waiver to Right of First Offer Agreement (the “Waiver”) with SunPower. Pursuant to the Waiver, OpCo waived its rights under the SunPower ROFO Agreement with respect to El Pelicano. The Waiver also contains customary representations, warranties and agreements of OpCo and SunPower. On August 11, 2017, OpCo waived the 45-day negotiation period under the SunPower ROFO Agreement with respect to Boulder Solar; following such waiver, SunPower has the right to offer and sell Boulder Solar to a third party, in accordance with the terms of the SunPower ROFO Agreement.

On June 9, 2017, OpCo entered into the Kern Letter Agreement with SunPower which set forth the conditions precedent to the acquisition of the Kern Remaining Assets under the Kern Purchase Agreement. On October 3, 2017, the Kern Purchase Agreement was terminated and such conditions precedent to the acquisition of the Kern Remaining Assets were not met. Pursuant to the terms of the Kern Letter Agreement, the Kern Remaining Assets were subsequently considered SunPower ROFO Projects subject to the SunPower ROFO Agreement. Please read “Note 3—Business Combinations—2017 Acquisitions.”

On February 5, 2018, the Partnership entered into the Waiver Agreement with SunPower of all the projects subject to the SunPower ROFO Agreement during the pendency of the Merger Agreement. Please read “—Note 17—Subsequent Events” for further details.

Maryland Solar Lease Arrangement

The Maryland Solar Project Entity has leased the Maryland Solar Project to an affiliate of First Solar. Under the arrangement, First Solar’s affiliate is obligated to pay a fixed amount of rent that is set based on the expected operations of the project. The lease agreement will expire on December 31, 2019 (unless terminated earlier pursuant to its terms).

FirstEnergy, the Partnership’s offtake counterparty with respect to the Maryland Solar Project, had its credit rating downgraded multiple times in 2016 and 2017. As of November 30, 2017, the credit rating of FirstEnergy was Caa1 and CCC- by Moody’s Investors Service and Standard & Poor’s Ratings Services, respectively, both of which are below investment grade. In addition, Standard & Poor’s Ratings Services placed FirstEnergy on CreditWatch with negative implications, based on a significant impairment charge that the company’s competitive business will incur from the deactivation of several coal units. In November 2016, FirstEnergy Corp., the parent of FirstEnergy, announced a strategic review of its competitive business, pursuant to which the company would seek to move away from competitive markets. FirstEnergy’s annual report on Form 10-K for the year ended December 31, 2016 reported a substantial uncertainty as to their ability to continue as a going concern.

The lease agreement between the Maryland Solar Project Entity and the First Solar affiliate will terminate upon any termination of the PPA or the site ground lease. Pursuant to the PPA for the Maryland Solar Project, a FirstEnergy bankruptcy would be an event of default under the PPA, permitting (subject to applicable law) the termination of the PPA although FirstEnergy may choose to renegotiate or maintain the PPA in its current form. Upon any such early termination of the lease agreement, First Solar’s affiliate is obligated to return the facility in its then-current condition and location to the Partnership, without any warranties, and no rent shall thereafter be payable by such First Solar affiliate. In the event that the PPA was terminated, the Maryland Solar Project would have no agreement through which to sell the energy that it produces, which equates to approximately $8.0 million in annual revenue, and the Partnership can enter into a replacement offtake agreement with a different counterparty. As of November 30, 2017, FirstEnergy is current with respect to the payments due under the PPA for the Maryland Solar Project.

The Partnership evaluates its long-lived assets, including property and equipment and projects, for impairment whenever events or changes in circumstances indicate the carrying value of such assets may not be recoverable. In consideration of the above events, the Partnership evaluated whether the carrying value of the project may no longer be recoverable using a probability-weighted assessment of potential outcomes and related undiscounted cash flows. As a result of such evaluation, the Partnership concluded the estimated future undiscounted net cash flows expected to be generated by the project over its estimated useful life exceeded the $51.5 million carrying value of the Maryland Solar Project's property and equipment as of November 30, 2017. Such assessment is subject to significant uncertainty and could change significantly as facts and circumstances change. In the event that the PPA for the Maryland Solar Project was terminated, if the Partnership is unable to enter into a replacement agreement or sell the energy it produces under similar terms, the carrying value of the project may not

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be recoverable, and the Partnership could record a material impairment loss in the amount by which the carrying value exceeds the fair value.

Operating Expense Allocations

The Predecessor’s carve-out financial statements include allocations of certain SunPower operating expenses. The allocations include: (i) charges that were incurred by SunPower that were specifically identified as attributable to the Predecessor; and (ii) an allocation of applicable SunPower operating expenses based on the proportional level of effort attributable to the operation of the Predecessor’s portfolio of solar power systems leased to residential homeowners and projects under construction. These expenses include legal, accounting, tax, treasury, information technology, insurance, employee benefit costs, human resources, procurement and other corporate services and infrastructure costs. The allocation of applicable SunPower operating expenses was principally based on management’s estimate of the proportional level of effort devoted by corporate resources. The amounts allocated to the Predecessor related to SunPower operating expenses were $7.7 million in fiscal 2015 and are disclosed as SG&A expenses on the consolidated statement of operations.

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Note 15. Income Taxes

The provision for income taxes differed from the amount computed by applying the statutory U.S. federal rate of 35% primarily due to the tax impact of equity in earnings, the tax impact of noncontrolling interest and state tax rates (net of federal benefit) in various jurisdictions, most significantly California. All tax expense, other than minimum state tax payments, after the IPO closing date is deferred tax expense and the Partnership has not paid any cash taxes in the period after the IPO closing date covered by these consolidated financial statements.

The Partnership’s financial reporting year-end is November 30 while its tax year-end is December 31. The Partnership has elected to base the tax provision on the financial reporting year; therefore, for example, since the 2017 financial reporting year is December 1, 2016 through November 30, 2017 the taxable income (loss) included in the 2017 tax provision is for the tax year ended December 31, 2016. The provision accrued at the financial reporting year-end will be a discrete period computation, and the tax credits and permanent differences recognized in that accrual will be those generated between the tax year-end date and the financial reporting year-end date. With the exception of minimum state income and franchise tax payments, amounts recorded for income tax provision (benefit) represent deferred income taxes being provided on the net income before taxes of OpCo, a non-taxable partnership, which is allocated to the Partnership.

Although organized as a limited partnership under state law, the Partnership elected to be treated as a corporation for U.S. federal income tax purposes. Accordingly, the Partnership is subject to U.S. federal income taxes at regular corporate rates on its net taxable income, and distributions it makes to holders of its Class A shares will be taxable as ordinary dividend income to the extent of its current and accumulated earnings and profits as computed for U.S. federal income tax purposes.

Income tax expense consists of the following: 

	Year Ended						Eleven Months Ended
(in thousands)	November 30, 2017			November 30, 2016			November 30, 2015
Income (loss) before income taxes	$	2,453		$	12,813		$	(20,563	)
Income tax expense:
Current tax expense
Federal	—			—			—
State	(2		)	(2		)	(12		)
Total current tax expense	$	(2	)	$	(2	)	$	(12	)
Deferred tax expense
Federal	$	(5,703	)	$	(18,242	)	$	(10,929	)
State	(882		)	—			(1,562		)
Total deferred tax expense	(6,585		)	(18,242		)	(12,491		)
Income tax expense	$	(6,587	)	$	(18,244	)	$	(12,503	)

For fiscal 2017 and fiscal 2016, the current tax expense is related to minimum state tax payments due and remitted for the tax year ended December 31, 2016 and December 31, 2015, respectively.

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The income tax expense differs from the amounts obtained by applying the statutory U.S. federal tax rate to income before taxes as shown below: 

	Year Ended						Eleven Months Ended
(in thousands)	November 30, 2017			November 30, 2016			November 30, 2015
Statutory rate (1)	35		%	35		%	35		%
Tax benefit (expense) at U.S. statutory rate	$	(858	)	$	(4,484	)	$	7,197
Noncontrolling interest	(48		)	(9,495		)	(10,201		)
Equity in earnings	(5,392		)	(1,892		)	(893		)
State income taxes	(921		)	(2,331		)	(1,574		)
Return to provision adjustments	132			—			—
Deferred adjustment	462			—			—
Other	38			(42		)	(3		)
Deferred taxes not benefited	—			—			(7,029		)
Total	$	(6,587	)	$	(18,244	)	$	(12,503	)
Effective tax rate	268.5		%	142.4		%	(60.8		)%

(1) On December 22, 2017, the 2017 Tax Act was signed into law, which enacted major changes to the U.S. federal income tax laws, including a permanent reduction in the U.S. federal corporate income tax rate. Please read “—Note 17—Subsequent Events” for further details.

The income tax effects of temporary differences giving rise to the Partnership's deferred income tax liabilities and assets are as follows: 

	Year Ended						Eleven Months Ended
(in thousands)	November 30, 2017			November 30, 2016			November 30, 2015
Deferred tax assets:
Net operating loss carryforwards	$	17,241		$	3,948		$	41
Tax Credits	621			—			—
Total deferred tax assets	17,862			3,948			41
Deferred tax liabilities:
Outside basis difference in partnership	(55,180		)	(34,681		)	(12,544		)
Total deferred tax liabilities	(55,180		)	(34,681		)	(12,544		)
Net deferred tax asset (liability)	$	(37,318	)	$	(30,733	)	$	(12,503	)

At November 30, 2017, the Partnership had federal and aggregate state net operating loss carryforwards of $15.1 million and $2.2 million, respectively. If not used, the federal net operating loss carryforwards will expire beginning in 2035, and the state net operating loss carryforwards will begin to expire in 2035, with the exception of Vermont’s net operating loss carryforwards which will begin expiring in 2025. No valuation allowance was established to offset the net operating loss carryforward since the Partnership expects to fully be able to realize the losses in future years before they expire, based on future projections, including the future reversal of existing taxable temporary differences. No uncertain tax positions have been identified for fiscal 2017, 2016, or 2015.

Note 16. Segment Information

The Partnership manages its Portfolio as one segment that operates a portfolio of solar energy generation systems. It operates as a single reportable segment based on the “management” approach.

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Long-lived assets consisting of property and equipment, net, were located in the United States. Similarly, all operating revenues for fiscal 2017, fiscal 2016 and fiscal 2015 were from customers located in the United States. The following customers each comprised 10% or more of the Partnership’s total revenue:

	Year Ended				Eleven Months Ended
Customers	November 30, 2017		November 30, 2016		November 30, 2015
Southern California Edison	48.3	%	54.9	%	*
Southern California Public Power Authority	11.1	%	*		*
First Solar	*		*		21.2	%

* Total revenue attributable to these customers was less than 10% of the Partnership's total revenue for the period.

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Note 17. Subsequent Events

Distributions

On December 20, 2017, the Board declared a cash distribution for its Class A shares of $0.2802 per share for the fourth quarter of 2017. The Board declared a corresponding cash distribution for OpCo’s common and subordinated units, which includes all common and subordinated units held by First Solar and SunPower. The fourth quarter distribution was paid on January 12, 2018 to shareholders and unitholders of record as of January 2, 2018.

The Tax Cuts and Jobs Act

On December 22, 2017, the 2017 Tax Act was signed into law, which enacted major changes to the U.S. federal income tax laws, including a permanent reduction in the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018. The Partnership expects the 2017 Tax Act will affect an approximately $12.3 million tax benefit, due to the re-measurement of deferred tax assets and liabilities; however, the Partnership is still currently evaluating the overall impact of the newly enacted legislation.

SunPower ROFO Agreement

Pursuant to the SunPower ROFO Agreement, SunPower previously granted to OpCo a right of first offer to purchase certain solar energy generating facilities for a period of five years. Due to the limitations on the Partnership's ability to acquire projects under the Merger Agreement, in connection with the Conflicts Committee’s and the Board’s approval of the Merger Agreement, the Partnership agreed to enter into the Waiver Agreement with SunPower which waives its right of first offer on all the projects subject to the SunPower ROFO Agreement during the pendency of the Merger Agreement. In the event that the Merger Agreement terminates without the closing of the Mergers, the waiver would terminate with respect to all projects subject to the SunPower ROFO Agreement, except, with respect to individual projects still owned by SunPower at the termination of such waiver, such project is either under an exclusivity agreement with a third party or has an offer for purchase from a third party pursuant to which SunPower is in negotiations. Due to these waivers, during the pendency of the Merger Agreement, the Partnership does not have a right of first offer on any or all such projects should SunPower decide to sell.

Merger Agreement with Capital Dynamics

On February 5, 2018, the Partnership, its general partner, OpCo and Holdings entered into the Merger Agreement with an affiliate of Capital Dynamics. Upon the terms and subject to the conditions set forth in the Merger Agreement, (i) OpCo Merger Sub 1 will merge with and into OpCo (“OpCo Merger 1”) and the separate existence of OpCo Merger Sub 1 will cease and OpCo will continue as the surviving limited liability company of OpCo Merger 1 (the “Initial Surviving LLC”), (ii) OpCo Merger Sub 2 will merge with and into the Initial Surviving LLC (“OpCo Merger 2” and, together with OpCo Merger 1, the “OpCo Mergers”) and the separate existence of OpCo Merger Sub 2 will cease and the Initial Surviving LLC will continue as the surviving limited liability company of OpCo Merger 2 (the “Surviving LLC”), (iii) Partnership Merger Sub will merge with and into the Partnership (the “Partnership Merger” and, together with the OpCo Mergers, the “Mergers”) and the separate existence of Partnership Merger Sub will cease and the Partnership shall continue as the surviving partnership of the Partnership Merger (the “Surviving Partnership” and, together with the Surviving LLC, the “Surviving Entities”), (iv) Holdings will transfer to 8point3 Solar or an affiliate thereof, and 8point3 Solar (or its designated affiliate) will accept, for no consideration, the transfer and delivery of, 100% of the issued and outstanding membership interests in the General Partner, including all rights and obligations relating thereto and all economic and capital interests therein, and 100% of the issued and outstanding Incentive Distribution Rights (as defined in the OpCo LLC Agreement).

The Merger Agreement was approved unanimously by the members of the Board voting on the matter, following the recommendation of the Conflicts Committee, and the Board agreed to submit the Merger Agreement to a vote of Partnership shareholders and to recommend that the Partnership’s shareholders adopt the Merger Agreement. Completion of the Mergers is expected to occur, subject to satisfaction of certain customary conditions, government approvals and vote by the Partnership’s shareholders, in the second or third quarter of 2018. Upon completion of the Mergers, the Partnership will no longer have publicly listed or traded shares, nor will it be a reporting company under the SEC’s rules and regulations.

At the effective time of OpCo Merger 1, the OpCo LLC Agreement shall be amended by Amendment No. 1 to permit a special distribution to the members of OpCo pro rata in accordance with their ownership of common and subordinated units of OpCo and the Initial Surviving LLC shall make a special distribution in an amount equal to the difference between $1.1 billion and the amount of debt then outstanding to the members of OpCo (the “Special Distribution”). At the effective time of OpCo Merger 2, each issued and outstanding common and subordinated unit of OpCo, other than the common units owned by the

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements— Continued

Partnership, will be converted into the right to receive an amount in cash equal to $12.35 per unit, less the amount received in the Special Distribution and as further adjusted pursuant to the Merger Agreement. At the effective time of the Partnership Merger, each issued and outstanding Class A Share will be converted into the right to receive an amount in cash equal to $12.35 per share, as adjusted pursuant to the Merger Agreement.

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements— Continued

Note 18. Quarterly Financial Information (Unaudited)

	For the Three Months Ended
	2017										2016
	November 30, 2017			August 31, 2017		May 31, 2017		February 28, 2017			November 30, 2016		August 31, 2016		May 31, 2016			February 29, 2016
Operating revenues	$	15,770		$	27,744	$	16,678	$	9,897		$	14,463	$	26,116	$	13,517		$	7,102
Operating income (loss)	2,677			16,391		5,716		(1,003		)	4,073		15,474		3,885			(1,259		)
Other expense, net	5,282			6,039		5,617		4,390			1,697		2,612		2,389			2,662
Net income (loss)	8,760			28,662		7,143		(5,320		)	4,250		15,874		(161		)	(7,053		)
Net income (loss) attributable to 8point3 Energy Partners LP Class A shares	(313		)	7,473		3,386		861			4,178		7,593		10,022			5,308
Net income (loss) per Class A share - basic	(0.01		)	0.27		0.12		0.03			0.16		0.38		0.50			0.27
Net income (loss) per Class A share - diluted	(0.01		)	0.27		0.12		0.03			0.16		0.38		0.50			0.27
Distributions per Class A share:	0.27			0.26		0.26		0.25			0.24		0.23		0.22			0.22
Weighted average number of Class A shares - basic	28,085			28,081		28,077		28,073			25,680		20,015		20,011			20,007
Weighted average number of Class A shares - diluted	43,585			43,581		43,577		43,573			41,180		35,515		35,511			35,507

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Annual Report on Form 10-K.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed under the supervision of our principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As of November 30, 2017, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework (2013). Based on this assessment, our management concluded that we maintained effective internal control over financial reporting as of November 30, 2017.

Attestation Report of the Independent Registered Public Accounting Firm

This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm on our internal control over financial reporting. Pursuant to the JOBS Act, management's report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management's report in this Annual Report on Form 10-K.

Section 103 of the JOBS Act provides that an emerging growth company is not required to provide an auditor’s report on internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act for as long as we qualify as an emerging growth company. We are an emerging growth company, and therefore we are not required to include an attestation report of our independent registered public accounting firm on our internal control over financial reporting in this report.

Changes in Internal Control over Financial Reporting

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities and migrating processes.

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

MANAGEMENT

Management of 8point3 Energy Partners LP

We are managed by the Board and executive officers of 8point3 General Partner, LLC, our general partner. Our general partner is not elected by our shareholders and may only be removed in certain limited circumstances. Our Sponsors, indirectly through Holdings, own all of the membership interests in our general partner. Shareholders are not entitled to elect the directors of our general partner, which are all appointed by our Sponsors, or to directly or indirectly participate in our management or operations. Our general partner owes certain contractual duties to our shareholders as well as a fiduciary duty to its owners, our Sponsors and their respective affiliates. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it.

The Board has delegated authority over certain other matters to its project operations committee and to the officers of our general partner. Our Board is composed of seven members. Our Sponsors appointed all members to our Board, including four Sponsor directors, two of whom were appointed by First Solar and two of whom were appointed by SunPower. As long as one Sponsor director appointed by First Solar and one Sponsor director appointed by SunPower are present, a majority of all directors present constitutes a quorum for meetings of the Board.

We have three directors who are independent as defined under the independence standards established by the NASDAQ.

We do not have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct operations, whether through directly hiring employees or by obtaining services of personnel employed by our Sponsors or third parties, but we sometimes refer to these individuals as our employees because they provide services directly to us.

All of our general partner’s officers are employees of our Sponsors and devote such portion of their time to our business and affairs as is required to manage and conduct our operations. We also rely on a significant number of employees of each Sponsor to assist in the operation of our projects pursuant to the AMAs.

Directors and Executive Officers of Our General Partner

The directors of our general partner are appointed for two-year terms and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the Board. There are no family relationships among any of our general partner’s directors or executive officers of our general partner.

The following sets forth information for our general partner’s directors and executive officers.

Name	Age	Position with 8point3 General Partner LLC
Charles D. Boynton	49	Chairman of the Board, Chief Executive Officer and Director
Bryan Schumaker	41	Chief Financial Officer and Interim Chief Accounting Officer
Jason E. Dymbort	40	General Counsel
Natalie F. Jackson	45	Director and Vice President of Operations
Max Gardner	36	Vice President of Operations
Alexander R. Bradley	36	Director
Thomas C. O’Connor	62	Director
Norman J. Szydlowski	66	Director
Mark R. Widmar	52	Director
Michael W. Yackira	66	Director

In connection with our IPO, each of the initial Chief Executive Officer and the initial Chief Financial Officer of our general partner was appointed to serve a two-year term. Upon the expiration of the initial terms for such officers on June 24,

2017, (i) First Solar had the right to select for appointment by the Board a new Chief Executive Officer, and (ii) SunPower had the right to select for appointment by the Board a new Chief Financial Officer. Neither First Solar nor SunPower exercised its right to select for appointment by the Board a new Chief Executive Officer and Chief Financial Officer. Pursuant to the limited liability company agreement of our general partner and Holdings, First Solar retains the right to select for appointment a new Chief Executive Officer, including by way of removal of the current Chief Executive Officer prior to the expiration of the current term, and SunPower retains the right to select for appointment a new Chief Financial Officer, including by way of removal of the current Chief Financial Officer prior to the expiration of the current term.

Mr. Charles D. Boynton was appointed as the chairman of the Board and chief executive officer of our general partner in March 2015. Mr. Boynton also serves as the Executive Vice President and Chief Financial Officer of SunPower since March 2012. In March 2012, Mr. Boynton also served as SunPower’s Acting Financial Officer. From June 2010 to March 2012, he served as SunPower’s Vice President, Finance and Corporate Development, where he drove strategic investments, joint ventures, mergers and acquisitions, field finance and finance, planning and analysis. Before joining SunPower in June 2010, Mr. Boynton was the Chief Financial Officer for ServiceSource, LLC from April 2008 to June 2010. From March 2004 to April 2008 he served as the Chief Financial Officer at Intelliden. Earlier in his career, Mr. Boynton held key financial positions at Commerce One, Inc., Kraft Foods, Inc. and Grant Thornton, LLP. He is a member of the board of trustees of the San Jose Technology Museum of Innovation. Mr. Boynton was a certified public accountant, State of Illinois, and a Member FEI, Silicon Valley Chapter. Mr. Boynton earned his master’s degree in business administration at Northwestern University and his Bachelor of Science degree in business from Indiana University. We believe that Mr. Boynton’s extensive experience in finance and mergers and acquisitions in the renewable energy industry makes him well qualified to serve as the chairman of the Board.

Mr. Bryan Schumaker was appointed as the chief financial officer of our general partner in June 2016 as well as the interim chief accounting officer of our general partner in February 2017. Mr. Schumaker joined First Solar in April 2008 as Assistant Corporate Controller, was appointed Vice President, Corporate Controller in December 2011, and was appointed Chief Accounting Officer in July 2015. Prior to joining First Solar, Mr. Schumaker held a number of positions with Swift Transportation Company from January 2003 to April 2008, including Vice President, Corporate Controller. Mr. Schumaker was also an auditor at KPMG LLP from December 2000 to January 2003. Mr. Schumaker holds a Bachelor’s degree in Business Administration with a major in Accounting from the University of New Mexico Anderson School of Management and is a Certified Public Accountant in Arizona.

Mr. Jason E. Dymbort was appointed as general counsel of our general partner in March 2015. Mr. Dymbort also serves as Deputy General Counsel – Americas of First Solar and has served in a variety of legal positions at First Solar since joining the company in March 2008, including serving as Assistant General Counsel – Project Finance & System Sales and overseeing legal work related to First Solar’s activities in a variety of international markets. Prior to joining First Solar, Mr. Dymbort was a corporate attorney at Cravath, Swaine & Moore LLP. Mr. Dymbort holds a juris doctor degree from the University of Pennsylvania Law School and a bachelor’s degree from Brandeis University.

Ms. Natalie F. Jackson was appointed as a vice president of operations of our general partner in June 2015 and as a member of the Board in March 2017. Ms. Jackson also serves as a Vice President for Project & Structured Finance at SunPower in Richmond, California where Ms. Jackson is responsible for SunPower’s Global Utility project and structured debt and equity financings as well as asset sales, including tax equity financing in the United States. Ms. Jackson’s professional experience includes more than 20 years in both project finance and business development in the United States and internationally in the independent power industry. Prior to joining SunPower, Ms. Jackson was Vice President of Project & Structured Finance at BrightSource Energy where she led the $2.2 billion project financing of the Ivanpah solar projects. Before that, Ms. Jackson served as Vice President of Project Finance for Invenergy, financing both wind and natural gas fired plants in the United States and Canada. Ms. Jackson also served as Project Director at AES Corporation, where she focused on business development and project finance in Central America, the Caribbean and Mexico. She holds a B.B.A. from James Madison University and a Masters of Business Administration from the Kellogg School of Management at Northwestern University.

Mr. Max Gardner was appointed as a vice president of operations of our general partner in June 2016. Mr. Gardner joined First Solar in 2010 as a Manager in the Project Finance group and was appointed Vice President, Project Finance (North America) in 2016. Prior to joining First Solar, Mr. Gardner was a strategy consultant at a boutique cleantech management consultancy from 2008 to 2010, and he began his career with General Electric in a management rotation program and as an analyst in the renewable energy finance group in 2003. In addition, Mr. Gardner also serves on the board of directors of Powerhive Inc. and Clean Energy Collective. Mr. Gardner holds a Master’s of Business Administration from Harvard Business School and a Bachelor of Science in Computer Science from the University of Southern California.

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Mr. Alexander R. Bradley was appointed as a member of the Board in June 2016. Mr. Bradley also serves as the Chief Financial Officer of First Solar since July 2016. From June 2015 to June 2016, Mr. Bradley served as a vice president of operations of our general partner. From December 2012 to June 2016, Mr. Bradley served as a Vice President, Global Project Finance and, in May 2015, Mr. Bradley was named Treasurer of First Solar. In these roles, Mr. Bradley was responsible for First Solar’s global debt, equity and tax equity financings, project structuring and project sales, as well as for global treasury. Mr. Bradley has led or supported the structuring, sale and financing of over $10 billion and approximately 2.7 GW of First Solar’s worldwide development assets, including several of the largest photovoltaic power plant projects in North America. Mr. Bradley’s professional experience includes more than ten years in investment banking, mergers and acquisitions, project finance and business development in the United States and internationally. Prior to joining First Solar, Mr. Bradley worked at HSBC in investment banking and leveraged finance, in London and New York, covering the energy and utilities sector. He received his Master of Arts from the University of Edinburgh, Scotland. We believe that Mr. Bradley’s extensive experience in finance and mergers and acquisitions in the renewable energy industry makes him well qualified to serve as a member of the Board.

Mr. Thomas C. O’Connor was appointed as a member of the Board in June 2015. Mr. O’Connor also serves on the board of directors of Keyera Corporation and New Jersey Resources. From November 2007 through December 2012, Mr. O’Connor served as chairman of the board of directors and Chief Executive Officer of DCP Midstream, LLC, one of the largest natural gas gatherers, processors, and marketers in the United States, and continued to serve as chairman of the board until March 2013. From November 2007 through September 2012, he also served as President of DCP Midstream, LLC. In September 2008, he became chairman of the board of DCP Midstream GP, LLC, the general partner of DCP Midstream Partners, LP, a publicly held master limited partnership, which position he held until December 2013. Prior to joining DCP Midstream, LLC, Mr. O’Connor had over 21 years of experience in the energy industry with Duke Energy, Corp., a gas and electricity services provider. From 1987 to 2007, Mr. O’Connor held a variety of roles with Duke Energy in the company’s natural gas pipeline, electric and commercial business units. After serving in a number of leadership positions with Duke Energy, he was named President and Chief Executive Officer of Duke Energy Gas Transmission in 2002 and he was named Group Vice President of corporate strategy at Duke Energy in 2005. In 2006 he became Group Executive and Chief Operating Officer of U.S. Franchised Electric and Gas and later in 2006 was named Group Executive and President of Commercial Businesses at Duke Energy. He previously served on the board of directors of QEP Resources, Inc. from January 2014 to January 2015 and on the board of directors of the general partner of Andeavor Logistics LP (formerly Tesoro Logistics LP) from May 2011 to December 2017. Mr. O’Connor earned his master’s degree in environmental studies and his Bachelor of Science degree in biology at the University of Massachusetts at Lowell, and he completed the Harvard Business School Advanced Management Program. We believe that Mr. O’Connor’s extensive experience in the energy industry and his prior experience as a director of the general partner of a master limited partnership makes him well qualified to serve as a member of the Board.

Mr. Norman J. Szydlowski was appointed as a member of the Board in June 2015. Since November 2017, Mr. Szydlowski has served as a member of the board of directors of EQT Corporation. Since March 2017, Mr. Szydlowski has served as the Chairman of the board of directors of Contanda Terminals, LLC. Since October 2014, Mr. Szydlowski has served as a member of the board of directors of the general partner of JP Energy Partners LP. From July 2014 through March 2017, Mr. Szydlowski managed his personal investments as a private investor. From November 2014 through December 2016, Mr. Szydlowski served on the board of directors of Transocean Partners, LLC. He has also served on the board of directors of Novus Energy, LLC since July 2014 and the board of directors of Rebellion Photonics, Inc. since September 2014. Mr. Szydlowski served as President, Chief Executive Officer and Chairman of the board of directors of Rose Rock Midstream GP, LLC from December 2011 to April 2014. He served as a director and as President and Chief Executive Officer of SemGroup Corporation from November 2009 to April 2014, remaining as an advisor until June 2014, and as a director of NGL Energy Partners from November 2011 to April 2014. From January 2006 until January 2009, Mr. Szydlowski served as President and Chief Executive Officer of Colonial Pipeline Company, an interstate common carrier of petroleum products. From 2004 to 2005, he served as a senior consultant to the Iraqi Ministry of Oil in Baghdad on behalf of the U.S. Department of Defense, where he led an advisory team in the rehabilitation, infrastructure security and development of future strategy of the Iraqi oil sector. From 2002 until 2004, he served as Vice President of Refining for Chevron Corporation. Mr. Szydlowski joined Chevron in 1981 and served in various capacities of increasing responsibility in sales, planning, supply chain management, refining and plant operations, transportation and construction engineering. Mr. Szydlowski received his Master’s degree in Business Administration in 1976 from Indiana University in Bloomington and his Bachelor’s degree in Mechanical Engineering in 1974 from the Kettering University in Flint, Michigan. We believe that Mr. Szydlowski’s extensive experience in the energy industry and his prior experience as a director of the general partner of a master limited partnership makes him well qualified to serve as a member of the Board.

Mr. Mark R. Widmar was appointed as a member of the Board in March 2015. Mr. Widmar also serves as the Chief Executive Officer of First Solar since July 2016. From March 2015 to June 2016, Mr. Widmar served as the Chief Financial Officer of our general partner. Mr. Widmar also served as First Solar’s Chief Financial Officer from April 2011 through June

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2016 and Chief Accounting Officer from February 2012 through June 2015. Prior to joining First Solar, Mr. Widmar served as Chief Financial Officer of GrafTech International Ltd., a leading global manufacturer of advanced carbon and graphite materials, from May 2006 through March 2011, as well as President, Engineered Solutions from January 2011 through March 2011. Prior to joining GrafTech, Mr. Widmar served as Corporate Controller of NCR Inc. from 2005 to 2006, and was a Business Unit Chief Financial Officer for NCR from November 2002 to his appointment as Controller. He also served as a Division Controller at Dell, Inc. from August 2000 to November 2002 prior to joining NCR. Mr. Widmar also held various financial and managerial positions with Lucent Technologies Inc., Allied Signal, Inc., and Bristol Myers/Squibb, Inc. Mr. Widmar was a certified public accountant, State of Indiana and holds a B.S. in Business Accounting and a Masters of Business Administration from Indiana University. We believe that Mr. Widmar’s extensive experience in key financial positions in various industries makes him well qualified to serve as a member of the Board.

Mr. Michael W. Yackira was appointed as a member of the Board in June 2015. Since July 2014, Mr. Yackira managed his personal investments as a private investor. Mr. Yackira served as Chief Executive Officer of NV Energy, Inc. from August 2007 to June 2014, and as a member of NV Energy’s board of directors from February 2007 to June 2015. Prior to that, Mr. Yackira served in a variety of positions with NV Energy, including Chief Financial Officer, Chief Operating Officer and President. He formerly served as Chief Financial Officer of FPL Group, Inc. (now known as NextEra) from 1995 to 1998, and as president of FPL Energy LLC from 1998 to 2000. Mr. Yackira is a Certified Public Accountant. Mr. Yackira earned his Bachelor of Science degree in accounting from Lehman College, City University of New York. We believe that Mr. Yackira’s extensive experience in the electric service industry makes him well qualified to serve as a member of the Board.

Board Leadership Structure

As described in our corporate governance guidelines, our Board believes that the decision as to who should serve as chairman and as chief executive officer, and whether the offices should be combined or separate, is properly the responsibility of the board, to be exercised from time to time in appropriate consideration of then existing facts and circumstances. In view of the operational and financial opportunities and challenges faced by us, among other considerations, our Board’s judgment is that the functioning of the board is generally best served by maintaining a structure of having one individual serve as both chairman and chief executive officer. The board believes that having a single person acting in the capacities of chairman and chief executive officer promotes unified leadership and direction for the board and executive management and allows for a single, clear focus for the chain of command to execute our strategic initiatives and business plans and to address its challenges. Accordingly, although the board believes that no single board leadership model is universally or permanently appropriate, the position of chairman is currently held by the chief executive officer.

Director Independence

The NASDAQ standards and our corporate governance guidelines require that the audit committee be composed entirely of independent directors. The NASDAQ standards and Rule 10A-3 under the Exchange Act include the additional requirements that members of the audit committee may not be affiliated persons of us or our subsidiaries or accept, directly or indirectly, any consulting, advisory or other compensatory fee from us or our subsidiaries, other than their compensation as our Board. Compliance by audit committee members with these requirements is separately assessed by our Board.

The Board has determined that Thomas C. O’Connor, Norman J. Szydlowski and Michael W. Yackira are independent under the NASDAQ standards, including the separate Audit Committee standards, and our corporate governance guidelines.

Board Role in Risk Oversight

Our corporate governance guidelines provide that the Board is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. In addition, the audit committee is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

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Committees of the Board of Directors

The standing committees of the Board are the audit committee, the conflicts committee and the project operations committee. The committees regularly report their activities and actions to the full board, generally at the next board meeting that follows the committee meeting. Each of the committees operate under a charter approved by the board and each committee conducts an annual evaluation of its performance. The charter of the audit committee is required to comply with the NASDAQ corporate governance requirements. There are no NASDAQ requirements for the charter of the conflicts committee or the project operations committee. Each of the committees is permitted to take actions within its authority through subcommittees, and references in this Annual Report on Form 10-K to any of those committees include any such subcommittees. The current membership and functions of the committees are described below.

Audit Committee

The audit committee is composed of three directors, all of whom meet the independence and experience standards established by the NASDAQ and the Exchange Act. The audit committee is composed of Michael W. Yackira (Chair), Thomas C. O’Connor and Norman J. Szydlowski. The Board has designated all three members of the audit committee as financial experts. The audit committee assists the Board in its oversight of the integrity of our financial statements and our compliance with related legal and regulatory requirements, corporate policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee. The audit committee met on a quarterly basis in 2017, and at such meetings met regularly with PricewaterhouseCoopers LLP, the Partnership’s independent registered public accounting firm, both privately and in the presence of management. A more detailed description of the audit committee’s duties and responsibilities is contained in the audit committee charter, a copy of which is available on the Partnership’s website at http://www.8point3energypartners.com.

Conflicts Committee

The conflicts committee is composed of Thomas C. O’Connor (Chair), Norman J. Szydlowski and Michael W. Yackira. The conflicts committee determines if the resolution of any conflict of interest referred to it by our general partner is in the best interests of our partnership. There is no requirement that our general partner seek the approval of the conflicts committee for the resolution of any conflict. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, may not hold an ownership interest in the general partner or its affiliates other than our Class A shares, including shares or awards under any long-term incentive plan, equity compensation plan or similar plan implemented by the general partner or the partnership, and must meet the independence and experience standards established by the NASDAQ and the Exchange Act to serve on an audit committee of a board of directors. Any matters approved by the conflicts committee in good faith will be deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our shareholders. Any shareholder challenging any matter approved by the conflicts committee will have the burden of proving that the members of the conflicts committee did not subjectively believe that the matter was in the best interests of our partnership. Moreover, any acts taken or omitted to be taken by our general partner in reliance upon the advice or opinions of experts such as legal counsel, accountants, appraisers, management consultants and investment bankers, where our general partner (or any members of the Board, including any member of the conflicts committee) reasonably believes the advice or opinion to be within such person’s professional or expert competence, will be conclusively presumed to have been done or omitted in good faith.

Project Operations Committee

The project operations committee is composed of two directors, one designated by each Sponsor. The project operations committee is composed of Alexander R. Bradley and Natalie F. Jackson. Unless otherwise prescribed by the Board or delegated to the officers of our general partner, the project operations committee is delegated the authority to make certain decisions related to the operation of our projects up to certain risk and economic thresholds, including in respect of annual budgets, project financings, asset dispositions and certain other material transactions. Any action by the project operations committee will require unanimous consent and to the extent the directors on the project operations committee do not unanimously agree on any matter and are unable to resolve such disagreement, either director may refer the matter to the full Board.

Compensation Committee Interlocks and Insider Participation

The listing rules of NASDAQ do not require us to maintain, and we do not maintain, a compensation committee.

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Code of Business Conduct and Code of Ethics

We have adopted a Code of Business Conduct and Ethics applicable to all employees, directors and officers. Our Code of Business Conduct and Ethics covers topics including, but not limited to, conflicts of interest, insider dealing, competition, discrimination and harassment, confidentiality, bribery and corruption, sanctions and compliance procedures. Our Code of Business Conduct and Ethics is posted on the “Corporate Governance” section of our website at http://ir.8point3energypartners.com/corporate-governance/highlights.

Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires the directors and executive officers of our general partner and persons who own more than ten percent of a registered class of our equity securities, to file reports of beneficial ownership on Form 3 and changes in beneficial ownership on Forms 4 or 5 with the SEC. Based on our review of the reporting forms and written representations provided to us from the persons required to file reports, we believe that each of the directors and executive officers of our general partner and persons who own more than ten percent of a registered class of our equity securities has complied with the Section 16 reporting requirements for transactions in our securities during fiscal 2017.

Item 11. Executive Compensation.

Compensation Discussion and Analysis

We have paid no cash or other compensation to our executive officers since our inception. Because our general partner’s executive officers are employed by our Sponsors, compensation of the executive officers is set and paid by our Sponsors. Our general partner has not entered into any employment agreements with any of its executive officers. Compensation for our general partner’s executive officers was determined and structured under our Sponsors’ respective compensation programs. Our Sponsors provide us with various general administrative services, such as legal, accounting, tax, treasury, and other related support services pursuant to the MSAs, for which we pay management service fees. Our general partner’s executive officers, as well as the employees of our Sponsors who provide services to us, may participate in employee benefit plans and arrangements sponsored by our Sponsors, including plans that may be established in the future, and certain of such officers and employees of our Sponsors who provide services to us currently hold grants under each Sponsor’s respective equity incentive plans and retained these grants after the completion of the IPO.

Our general partner adopted the LTIP on our behalf for (i) the employees of our general partner and its affiliates who perform services for us, (ii) the non-employee directors of our general partner and (iii) the consultants who are natural persons and perform services for us. Awards under the LTIP may consist of unrestricted shares, restricted shares, restricted share units, options and share appreciation rights. The LTIP limits the number of shares that may be delivered pursuant to awards (subject to any adjustment due to recapitalization, reorganization or a similar event permitted under the LTIP) to 2,000,000 Class A shares. The LTIP provides that no director may receive awards in any calendar year with a grant date value in excess of $250,000. Shares that are forfeited or withheld to satisfy exercise price or tax withholding obligations are available for delivery pursuant to other awards. As of November 30, 2017, the awards under the LTIP have only been granted to the non-employee directors of our general partner. The table below in “—Non-Employee Director Compensation” sets forth the Class A shares granted in 2017 to the non-employee directors.

Compensation Committee Report

The Board does not have a compensation committee. The Board, acting in lieu of a compensation committee, has reviewed and discussed the Compensation Discussion and Analysis with management. Based on this review and discussion, the Board recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

By the members of the board of directors of our general partner:

Charles D. Boynton

Natalie F. Jackson

Alexander R. Bradley

Thomas C. O’Connor

Norman J. Szydlowski

Mark R. Widmar

Michael W. Yackira

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Compensation Committee Interlocks and Insider Participation

As discussed above, the Board does not have a compensation committee. If any compensation is to be paid to our general partner’s executive officers, the compensation would be reviewed and approved by the Board because it performs the functions of a compensation committee in the event such committee is needed. Since the completion of the IPO on June 24, 2015, none of the directors or executive officers of our general partner served as a member of a compensation committee of another entity that has or has had an executive officer who served as a member of the Board.

Compensation of Directors

Directors of our general partner who are salaried employees of our Sponsors or any of their subsidiaries do not receive any additional compensation for serving as a director or committee member of our general partner’s board. The independent directors serving on our general partner’s board receive an annual cash retainer of $75,000 and a number of our Class A shares determined by dividing $75,000 by the closing price of our Class A shares on the grant date, with any fractional shares paid in cash. Both the cash and stock portions of the annual retainer are paid in quarterly installments. In addition, the Chair of the audit committee and the Chair of the conflicts committee each receive an annual cash retainer of $20,000, which is payable in quarterly installments.

Each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law under a director indemnification agreement and our Partnership Agreement.

Non-Employee Director Compensation

The following table sets forth the compensation paid to non-employee directors for service as a member of the Board for fiscal 2017:

Name	Fees Earned or Paid in Cash		Share Awards(a)		Option Awards	Non-Equity Incentive Plan Compensation	All Other Compensation	Total
Michael W. Yackira	$	95,000	$	75,000	—	—	—	$	170,000
Thomas C. O’Connor	$	95,000	$	75,000	—	—	—	$	170,000
Norman J. Szydlowski	$	75,000	$	75,000	—	—	—	$	150,000

(a) Each of Messrs. Yackira, O’Connor and Szydlowski were granted 5,331 Class A shares in 2017 with a grant date fair value of $75,000.

Long-Term Incentive Plan

Our general partner adopted the LTIP, on our behalf for (i) the employees of our general partner and its affiliates who perform services for us, (ii) the non-employee directors of our general partner and (iii) the consultants who are natural persons and perform services for us. Awards under the LTIP may consist of unrestricted shares, restricted shares, restricted share units, options and share appreciation rights. The LTIP limits number of shares that may be delivered pursuant to awards (subject to any adjustment due to recapitalization, reorganization or a similar event permitted under the LTIP) to 2,000,000 Class A shares. The LTIP provides that no director may receive awards in any calendar year with a grant date value in excess of $250,000. Shares that are forfeited or withheld to satisfy exercise price or tax withholding obligations are available for delivery pursuant to other awards.

The LTIP is administered by the Board, unless the full Board appoints an alternative committee under the LTIP. For the remainder of this section the applicable plan administrator will be referred to as the “committee.” The Board or the committee may authorize a committee of one or more members of the Board to grant awards pursuant to such conditions or limitations as the Board or the committee may establish. The committee may also delegate to the Chief Executive Officer and to other employees of our general partner (i) the authority to grant individual awards to consultants and to employees who are not subject to Section 16(b) of the Exchange Act and (ii) other administrative duties under the LTIP pursuant to such conditions or limitations as the committee may establish.

The committee has full power and authority to: (i) designate participants; (ii) determine the type or types of awards to be granted to a participant; (iii) determine the number of shares to be covered by awards; (iv) determine the terms and conditions of any award; (v) determine whether, to what extent, and under what circumstances awards may be settled, exercised, canceled,

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or forfeited; (vi) interpret and administer the LTIP and any instrument or agreement relating to an award made under the LTIP; (vii) establish, amend, suspend or waive such rules and regulations and appoint such agents as it shall deem appropriate for the proper administration of the LTIP; and (viii) make any other determination and take any other action that the committee deems necessary or desirable for the administration of the LTIP.

The committee may, in its discretion, provide for the extension of the exercisability of an award, accelerate the vesting or exercisability of an award, eliminate or make less restrictive any restrictions applicable to an award, waive any restriction or other provision of this LTIP or an award or otherwise amend or modify an award or award agreement in any manner that is either (i) not materially adverse to the Participant to whom such award was granted or (ii) consented to by such Participant.

The Board has the right to terminate or amend the LTIP or any part of the LTIP from time to time, including increasing the number of shares that may be granted, subject to shareholder approval as may be required by the exchange upon which the Class A shares are listed at that time, if any. No change may be made in any outstanding grant that would materially reduce the benefits of the participant without the consent of the participant. The LTIP will expire upon the earliest of the date established by the Board or the committee, June 24, 2025 or the date that no shares remain available under the LTIP for awards. Upon termination of the LTIP, awards then outstanding will continue pursuant to the terms of their grants.

Class A shares to be delivered in settlement of awards under the LTIP may be newly issued Class A shares, Class A shares acquired in the open market, Class A shares acquired from any other person, or any combination of the foregoing.

Awards

Awards under the LTIP serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our Class A shares. Therefore, participants will not pay any consideration for the Class A shares they receive, and we will receive no remuneration for the shares. The following types of awards are available for issuance under the LTIP.

Unrestricted Shares. An unrestricted share is a Class A share that is fully vested upon grant and is not subject to forfeiture. The committee shall have the discretion to determine the employees, consultants and directors to whom unrestricted shares shall be granted and the number of shares to be granted.

Restricted Shares. A restricted share is a Class A share that vests over a period of time and that during such time is subject to forfeiture. In the future, the committee may determine to make grants of restricted shares under the LTIP to eligible employees and directors containing such terms as the committee determines. The committee determines the period over which restricted shares granted to participants will vest. The committee, in its discretion, may base its determination upon the achievement of performance metrics. Distributions made on restricted shares may be subjected to the same vesting provisions as the restricted share.

Restricted Share Units. A restricted share unit entitles the grantee to receive a Class A share upon the vesting of the restricted share unit or, in the discretion of the plan administrator, cash equivalent to the value of a Class A share. The plan administrator may make grants of restricted share units under the plan containing such terms as the plan administrator shall determine, including the period over which restricted share units granted will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives.

The committee, in its discretion, may grant distribution equivalent rights (“DERs”), with respect to a restricted share unit. DERs entitle the grantee to receive an amount in cash equal to the cash distributions made on a Class A share during the period the related award is outstanding. The committee establishes whether the DERs are paid currently, when the tandem restricted share unit vests or on some other basis.

Options. An option provides a participant with the option to acquire Class A shares at a specified price. The purchase price per share purchasable under an option shall be determined by the committee at the time the option is granted, provided such purchase price will not be less than the fair market value of the Class A shares on the date of grant. The committee has the authority to determine to whom options will be granted, the number of Class A shares to be covered by each grant, and the conditions and limitations applicable to the exercise of the option. Options may be exercised in the manner and at such times as the committee determines for each option. The committee determines the methods and form of payment for the exercise price of an option and the methods and forms in which Class A shares will be delivered to a participant.

Share Appreciation Rights. A share appreciation right is an award that, upon exercise, entitles the holder to receive the excess, if any, of the fair market value of a Class A share on the exercise date over the grant price of the share appreciation

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right. The excess may be paid in cash and/or in Class A shares, as determined by the committee in its discretion. The exercise price of a share appreciation right will be determined by the committee at the time the share appreciation right is granted, but each share appreciation right must have an exercise price that is not less than the fair market value of the underlying Class A share on the date of grant. The committee will have the authority to determine to whom share appreciation rights will be granted, the number of Class A shares to be covered by each grant, and the conditions and limitations applicable to the exercise of the share appreciation right. The committee determines the time or times at which a share appreciation right may be exercised in whole or in part.

Other LTIP Provisions

Tax Withholding. Unless other arrangements are made, our general partner and its affiliates will be authorized to withhold from any award, from any payment due under any award, or from any compensation or other amount owing to a participant the amount (in cash, shares, shares that would otherwise be issued pursuant to such award, or other property) of any applicable taxes payable with respect to the grant of an award, its settlement, its exercise, the lapse of restrictions applicable to an award or in connection with any payment relating to an award or the transfer of an award and to take such other actions as may be necessary to satisfy the withholding obligations with respect to an award.

Adjustments. Upon the occurrence of certain transactions or events affecting the Class A shares, the committee may make certain adjustments to awards under the LTIP; provided, however, that no adjustment will be made in a manner that results in noncompliance with the requirements of Section 409A of the Code, to the extent applicable.

Transferability of Awards. Awards are only exercisable by or payable to the participant during the participant’s lifetime, or by the person to whom the participant’s rights pass by will or the laws of descent and distribution. No award or right granted under the LTIP may be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered and any such purported transfer shall be void and unenforceable. Notwithstanding the foregoing, the committee may, in its discretion, allow a participant to transfer an award without consideration to an immediate family member or a related family trust, limited partnership, or similar entity on the terms and conditions established by the committee from time to time.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth information about the Partnership’s Class A Shares that may be issued under all existing equity compensation plans as of November 30, 2017.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Awards, Warrants and Rights	Weighted-Average Exercise Price of Outstanding Awards, Warrants and Rights	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
	(a)	(b)	(c)
Equity compensation plans approved by security holders	38,673	N/A	1,961,327
Equity compensation plans not approved by security holders	—	N/A	—
Total	—	N/A	—

The following table sets forth the beneficial ownership of our Class A shares as of November 30, 2017, held by:

• each person known by us to be a beneficial owner of more than 5% of the Class A shares;

• each of the directors of our general partner;

• each of our general partner’s named executive officers; and

• all of our general partner’s directors and executive officers as a group.

The amounts and percentage of Class A shares beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the

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voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all of the Class A and Class B shares shown as beneficially owned by them, subject to community property laws where applicable.

Percentage of total Class A shares beneficially owned is based on 28,088,673 Class A shares outstanding as of November 30, 2017. Percentage of total Class B shares beneficially owned is based on 51,000,000 Class B shares outstanding as of November 30, 2017.

Name of Beneficial Owner (1)	Class A Shares Beneficially Owned	Percentage of Class A Shares Beneficially Owned		Class B Shares Beneficially Owned	Percentage of Class B Shares Beneficially Owned		Percentage of Class A Shares and Class B Shares Beneficially Owned
First Solar (2)	—	—		22,116,925	43.4	%	28.0	%
SunPower (3)	—	—		28,883,075	56.6	%	36.5	%
Wellington Management Group LLP (4)	3,716,595	13.2	%	—	—		4.7	%
Vanguard Explorer Fund (5)	1,728,749	6.2	%	—	—		2.2	%
Eventide Asset Management, LLC (6)	1,553,700	5.5	%	—	—		2.0	%
Charles D. Boynton	17,668	*		—	—		*
Bryan Schumaker	2,158	*		—	—		*
Jason E. Dymbort	1,600	*		—	—		*
Natalie F. Jackson	—	—		—	—		—
Max Gardner	—	—		—	—		—
Alexander R. Bradley	—	—		—	—		—
Thomas C. O'Connor	19,391	*		—	—		*
Norman J. Szydlowski	16,891	*		—	—		*
Mark R. Widmar	—	—		—	—		—
Michael W. Yackira	25,391	*		—	—		*
All directors and executive officers as a group (10 persons)	83,099	*		—	—		*

* Less than 1%.

(1) Unless otherwise indicated, the address for all beneficial owners in this table is c/o 8point3 Energy Partners LP, 77 Rio Robles, San Jose, California 95134.

(2) As of November 30, 2017, First Solar held 22,116,925 Class B shares that provide First Solar with an aggregate number of votes on certain matters that may be submitted for a vote of our shareholders that is equal to the aggregate number of OpCo common units and OpCo subordinated units of OpCo held by First Solar on the relevant record date. Please read “Item 1. Business—Overview.”

(3) As of November 30, 2017, SunPower held 28,883,075 Class B shares that provide SunPower with an aggregate number of votes on certain matters that may be submitted for a vote of our shareholders that is equal to the aggregate number of OpCo common units and OpCo subordinated units of OpCo held by SunPower on the relevant record date. Please read “Item 1. Business—Overview.”

(4) Based on information provided by Wellington Management Group LLP, c/o Wellington Management Company LLP, 280 Congress Street, Boston, MA 02210, in a Schedule 13G/A filed with the SEC on February 9, 2017 reporting beneficial ownership as of December 30, 2016. According to such Schedule 13G/A, Wellington Management Group LLP has shared voting power with respect to 1,968,894 shares and shared dispositive power with respect to 3,716,595 shares.

(5) Based on the information provided by Vanguard Explorer Fund, PO Box 2600, V26, Valley Forge, PA 19482, in a Schedule 13G/A filed with the SEC on February 2, 2018 reporting beneficial ownership as of December 31, 2017. According to such Schedule 13G/A, Vanguard Explorer Fund has shared voting power and shared dispositive power with respect to 1,728,749 shares.

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(6) Based on the information provided by Eventide Asset Management, LLC, One International Place, 35th Floor, Boston, MA 02110, in a Schedule 13G with the SEC on February 13, 2017 reporting beneficial ownership as of December 31, 2016. According to such Schedule 13G, Eventide Asset Management, LLC has shared voting power and shared dispositive power with respect to 1,553,700 shares.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Certain Relationships and Related Party Transactions

As of November 30, 2017, our general partner and its affiliates, including our Sponsors, collectively owned 51,000,000 Class B shares in the Partnership, with SunPower and First Solar owning 28,883,075 and 22,116,925 Class B shares, respectively, and together owned a noncontrolling 64.5% limited liability company interest in OpCo. Transactions with our general partner and its affiliates, including our Sponsors, are considered to be related party transactions because our general partner and its affiliates own more than five percent of our equity interests. In addition, Mr. Boynton serves as an executive officer of both SunPower and our general partner.

Distributions and Payments to our General Partner and its Affiliates

OpCo will generally make cash distributions to its unitholders pro rata, including our Sponsors (as holders of an aggregate of 15,500,000 OpCo’s common units and all of OpCo’s subordinated units). In addition, if distributions exceed OpCo’s established minimum quarterly distribution and target distribution levels, the incentive distribution rights held by Holdings will entitle Holdings to increasing percentages of the distributions, up to 50 percent of the distributions above the highest target distribution level.

Assuming OpCo pays the full minimum quarterly distributions on all of its outstanding common and subordinated units for four quarters in fiscal 2018, our general partner and its affiliates, including our Sponsors, would receive an annual distribution of approximately $42.8 million on their common and subordinated units. For the four quarters in fiscal 2017, our general partner and its affiliates, including our Sponsors, received annual distributions of $53.1 million on their common and subordinated units.

Pursuant to our Partnership Agreement, we will reimburse our general partner and its affiliates, including our Sponsors, for costs and expenses they incur and payments they make on our behalf. Pursuant to the MSAs (described below), OpCo, on behalf of itself, our general partner and us, initially pays each Service Provider an annual management fee equal to $0.6 million, in the case of the First Solar MSA, and $1.1 million, in the case of the SunPower MSA, which amounts shall be adjusted annually for inflation. The management fee is paid in monthly installments. Each of these payments will be made prior to making any distributions on OpCo’s units.

Agreements with our Sponsors

We, OpCo and our general partner have entered into various agreements with our Sponsors. Below is a description of these agreements.

2017 Acquisitions

On January 26, 2016, OpCo and SunPower entered into a purchase, sale and contribution agreement, which was amended on September 28, 2016, November 30, 2016, February 24, 2017 and June 9, 2017, pursuant to which OpCo agreed to purchase an interest in the Kern Project for aggregate consideration of $31.7 million in cash. OpCo’s acquisition of the Kern Project was effectuated in phases with the Kern Phase 2(b) Assets and the Kern Phase 2(c) Assets being acquired on February 24, 2017 and June 9, 2017, respectively.

On November 11, 2016, OpCo and a subsidiary of First Solar entered into a purchase and sale agreement, pursuant to which OpCo acquired a 34% interest in the Stateline Project on December 1, 2016 for $329.5 million. For further details, please read Part I, Item 1, “Business—Utility Projects,” Part II, Item 8. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 3—Business Combinations—2017 Acquisitions” and Part II, Item 8. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 4—Investment in Unconsolidated Affiliates.”

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O&M Agreements

Certain Project Entities and certain other subsidiaries have entered into O&M agreements with First Solar or SunPower affiliates, as applicable. Under the terms of the O&M agreements, such affiliates have agreed to provide a variety of operation,

maintenance and asset management services, and certain performance warranties or availability guarantees, to our Project Entities in exchange for fixed annual fees, which are subject to certain adjustments.

First Solar Projects

The below-listed Project Entities have each entered into O&M agreements with FSEC, dated as of the following dates: 

Party	Date	Initial Term
Blackwell Project Entity	April 15, 2015	10 Years (1)
Kingbird Solar A, LLC	February 26, 2016	10 Years (2)
Kingbird Solar B, LLC	February 26, 2016	10 Years (2)
Lost Hills Project Entity	April 15, 2015	10 Years (1)
North Star Project Entity	April 30, 2015	10 Years (1)
Solar Gen 2 Project Entity	October 22, 2014	10 Years (1)
Stateline Project Entity	August 31, 2016	10 Years (1)

(1) The parties may elect upon mutual agreement to extend the term for up to two additional five-year renewal terms.

(2) The parties may elect, upon mutual agreement, to extend the term for up to two additional four-year renewal terms.

Pursuant to each O&M agreement with FSEC, FSEC provides customary day-to-day facility and O&M services to the applicable Project Entity. FSEC’s obligations under the O&M agreements are supported by a parent guaranty agreement issued by First Solar for the benefit of the relevant Project Entity party thereto. As consideration for the performance of O&M services under these O&M agreements, FSEC receives an annual service fee, paid in quarterly installments, subject to an annual escalator. Additionally, each applicable Project Entity is required to pay FSEC a one-time mobilization fee under its O&M agreement. For fiscal 2017, FSEC received a total of approximately $0.4 million in compensation under its O&M agreements with our Project Entities (including reimbursement of expenses).

SunPower Projects

The below-listed Project Entities have each entered into O&M agreements with SunPower Systems, dated as of the following dates:  

Party	Date	Initial Term
Kern Project Entity	January 22, 2016	10 Years (1)
Henrietta Project Entity	October 14, 2015	5 Years (2)
Hooper Project Entity	March 24, 2015	5 Years (2)
Macy's California Project Entities	June 19, 2015	10 Years (1)
Macy's Maryland Project Entity	May 6, 2016	10 Years (1)
Quinto Project Entity	October 6, 2014	5 Years (2)
RPU Project Entity	June 8, 2015	10 Years (1)
UC Davis Project Entity	June 19, 2015	10 Years (1)

(1) Term is automatically extended for successive two-year periods, unless terminated in writing by the applicable Project Entity. For services performed during the final year of the initial term and, if applicable, the final year of each renewal term, SunPower Systems provides a one-year warranty that such services will be performed in good and workmanlike manner and will be free from defects in workmanship, and that any repaired or replaced items will be free from defects for one year from the date of such repair or replacement.

(2) Term is renewable for three additional five-year periods at the option of the applicable Project Entity (subject to certain exceptions related to defaults by such Project Entity or disputes between the parties).

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Pursuant to each O&M agreement with SunPower Systems, SunPower Systems provides customary day-to-day facility and O&M services to the applicable Project Entity. As consideration for the performance of O&M services under these O&M agreements, SunPower Systems receives a fixed annual fee paid in quarterly installments. Additionally, each such Project Entity is also responsible for paying SunPower Systems for any additional services and emergency services. For fiscal 2017, SunPower Systems received a total of approximately $3.4 million in compensation under its O&M agreements with the Project Entities listed in the above chart (including reimbursement of expenses).

Residential Portfolio

On May 4, 2015, our Residential Portfolio entered into a Maintenance Services Agreement (the “Residential Portfolio Maintenance Agreement”) with SunPower Systems. Under the Residential Portfolio Maintenance Agreement, SunPower Systems maintains the projects under each customer lease and guarantees that each project in the Residential Portfolio that is subject to a lease agreement will produce a range of kilowatt hours of electric energy equivalent to SunPower Systems’ estimate of the amount of electricity the project produces in each guarantee year. The term of the Residential Portfolio Maintenance Agreement is concurrent with each customer lease in the Residential Portfolio.

The Residential Portfolio Project Entity compensates SunPower Systems on a monthly per lease basis, the amount of which fee escalates at an agreed annual rate as set forth in the Residential Portfolio Maintenance Agreement. To the extent a lease is extended, the applicable monthly fee under this agreement is subject to the mutual agreement of SunPower Systems and the Residential Portfolio Project Entity. For fiscal 2017, SunPower Systems received a total of approximately $0.7 million in compensation under the Residential Portfolio Maintenance Agreement.

Asset Management Agreements

First Solar Projects

The below-listed wholly owned subsidiaries of OpCo have each entered into AMAs with FSAM, a wholly owned direct subsidiary of First Solar, dated as of the following dates:

Party	Project	Date	Initial Term (1)
FSAM DS Holdings, LLC	Stateline Project	August 31, 2015	One Year
FSAM Lost Hills	Lost Hills Project	June 17, 2015	One Year
Blackwell Holdings, LLC	Blackwell Project
FSAM NS Holdings, LLC	North Star Project	June 17, 2015	One Year
FSAM SG2 Holdings, LLC	Solar Gen 2 Project	June 17, 2015	One Year
Kingbird Solar, LLC	Kingbird Project	February 6, 2016	Ten Years
Maryland Solar Project Entity	Maryland Solar Project	June 17, 2015	One Year

(1) Term is automatically extended annually unless otherwise terminated.

Under each AMA, FSAM will provide, or cause an affiliate or a third-party subcontractor to provide, services to the applicable First Solar Project Entity including (among others):

• accounting and preparing financial books and records;

• filing tax returns (if applicable);

• preparing budgets and financial projections;

• preparing reports;

• billing and accounts payable;

• legal and regulatory compliance oversight; and

• executive management and oversight and corporate governance services.

The services to be provided to the Maryland Solar Project Entity are of a more limited scope during the term of the MD Solar Lease Agreement, since the project is operated by the lessee during such period. In consideration for providing the above services, the relevant First Solar Project Entity is required to pay FSAM a fixed annual fee, in quarterly installments. Such fee

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is subject to an escalator. For fiscal 2017, FSAM received a total of approximately $0.6 million in compensation under its AMAs with OpCo’s subsidiaries.

SunPower Projects

The below-listed subsidiaries of OpCo have each entered into AMAs with SunPower Capital, dated as of the following dates:

Party	Project	Date	Term
Kern Project Entity	Kern Project	January 22, 2016	One Year (1)
Parrey Class B Member, LLC	Henrietta Project	September 29, 2016	Continuous (unless otherwise terminated)
Hooper Project Entity	Hooper Project	February 10, 2015	One Year (1)
Macy's California Project Entities	Macy's California Project	June 19, 2015	One Year (1)
Macy's Maryland Project Entity	Macy's Maryland Project	May 6, 2016	One Year (1)
Quinto Project Entity	Quinto Project	October 6, 2014	One Year (1)
RPU Project Entity	RPU Project	June 8, 2015	One Year (1)
UC Davis Project Entity	UC Davis Project	June 19, 2015	One Year (1)

(1) Term is automatically extended annually unless otherwise terminated.

The terms of the AMAs with SunPower Capital are set forth below. For fiscal 2017, SunPower Capital received a total of approximately $0.8 million in compensation under its AMAs with the subsidiaries of OpCo listed in the above chart.

Henrietta Project

Pursuant to the applicable AMA, SunPower Capital provides management services to Parrey Class B Member, LLC, including the following:

• performing cash management, billing and collection services;

• maintaining the Parrey Class B Member, LLC’s bank accounts;

• maintaining and completing accurate financial books and records of Parrey Class B Member, LLC;

• maintaining records of Parrey Class B Member, LLC’s limited liability company documents;

• completing all federal, state and utility mandated reporting requirements; and

• supervising the preparation of tax returns.

As consideration for the performance of services under the applicable AMA, SunPower Capital receives a fixed annual fee paid in quarterly installments.

Hooper and Quinto Projects

Pursuant to the applicable AMAs with the Hooper Project Entity and the Quinto Project Entity, SunPower Capital provides management services to such Project Entities, including the following:

• development and operations at the projects;

• supervising and monitoring SunPower Systems with respect to the applicable projects’ O&M agreements;

• performing cash management, billing and collection services;

• maintaining each Project Entity’s bank accounts;

• maintaining and completing accurate financial books and records of the operations of each project and Project Entity;

• maintaining records of each Project Entity’s limited liability company documents;

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• monitoring each Project Entity’s compliance with the terms and conditions of the financing documents, lease, site agreements and all other project documents;

• maintaining insurance for each Project Entity and coordinating insurance claims;

• procuring and maintaining governmental approvals for each project and Project Entity;

• completing all federal, state and utility mandated reporting requirements;

• preparing status reports relating to each project’s operations;

• supervising the preparation of tax returns; and

• preparing proposed budgets for management, compliance servicing and monitoring costs and services associated with each project.

As consideration for the performance of the services under the applicable AMAs, SunPower Capital receives a fixed annual fee paid in quarterly installments. SunPower Capital is also entitled to be reimbursed for costs actually incurred by SunPower Capital in the performance of its duties in accordance with an approved budget, including overhead and internal expense and amounts due to subcontractors. With respect to the AMA for the Quinto Project, beginning on the fifth full quarter of the term, the service fee will be increased annually by the greater of 2.5% or the increase in the U.S. Department of Labor’s Employment Cost Index.

Kern, Macy’s California, Macy’s Maryland, RPU and UC Davis Projects

Pursuant to the applicable AMAs with the Kern Project Entity, the Macy’s California Project Entities, the Macy’s Maryland Project Entity, the RPU Project Entity and the UC Davis Project Entity, SunPower Capital provides management services to such Project Entities, including the following:

• providing facility development and operations services at the projects;

• providing cash management, billing services and collection services with respect to the projects;

• providing accounting and banking services;

• providing owner record keeping and monitoring services;

• providing insurance;

• procuring and maintaining necessary governmental approvals;

• satisfying all reporting requirements for the projects;

• supervising the preparation and filing of financial statements;

• supervising the preparation and filing of tax returns;

• preparing or filing limited liability company documents for the projects; and

• maintaining full, complete and otherwise adequate books of accounts and such other records as are necessary to reflect operations of the facility in accordance with prudent management practices and U.S. GAAP.

As consideration for the performance of management services under the applicable AMAs, SunPower Capital receives a fixed annual fee paid in equal quarterly installments. With respect to the AMAs for the Kern Project, the Macy’s California Project, the Macy’s Maryland Project and the UC Davis Project, beginning on the fifth full quarter of the term, the service fee will be increased annually by the greater of 2.5% or the increase in the U.S. Department of Labor’s Employment Cost Index. With respect to the AMA for the RPU Project, beginning on the fifth full quarter of the term, the service fee will be increased annually by the greater of 3% or the increase in the U.S. Department of Labor’s Employment Cost Index.

These Project Entities are also responsible for reimbursing SunPower Capital for its actual costs reasonably incurred in performance of its duties in accordance with an approved budget, including overhead and internal expense and amounts.

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Residential Portfolio

Our Residential Portfolio entered into a Lease Servicing Agreement (the “Residential Portfolio Servicing Agreement”), dated as of May 4, 2015, with SunPower Capital, an affiliate of the Residential Portfolio Project Entity. Under the Residential Portfolio Servicing Agreement, SunPower Capital will perform services to administer each customer lease in our Residential Portfolio, which includes customary billing, accounting and enforcement of the customer leases. The term of the Residential Portfolio Servicing Agreement is concurrent with each customer lease in the Residential Portfolio. The Residential Portfolio Project Entity compensates SunPower Capital for these services with a monthly fee for each lease agreement then in effect, escalating annually in an amount equal to 2.5% of the fee paid for the preceding year. For fiscal 2017, SunPower Capital received a total of approximately $0.6 million in compensation under the Residential Portfolio Servicing Agreement.

Performance and Limited Warranties

First Solar Projects

The below-listed Project Entities have each entered into limited warranty agreements with First Solar, dated as of the following dates:

Party	Project	Date
Blackwell Project Entity	Blackwell Project	April 15, 2015
Kingbird Solar A, LLC	Kingbird Project	February 26, 2016
Kingbird Solar B, LLC	Kingbird Project	February 26, 2016
Lost Hills Project Entity	Lost Hills Project	April 15, 2015
North Star Project Entity	North Star Project	April 30, 2015
Solar Gen 2 Project Entity	Solar Gen 2 Project	October 22, 2014
Stateline Project Entity	Stateline Project	August 31, 2015

Under the applicable limited warranty agreements, First Solar has issued certain warranties regarding the solar modules for each of the projects listed in the above chart. Under the applicable limited warranty agreements for such projects, First Solar provides a ten-year limited warranty that (i) each module will be new and unused when originally installed at the projects pursuant to the applicable EPC contracts for such projects and (ii) each module will be free from defects in materials and workmanship, excluding degradation-related power output defects. In addition, First Solar provides a 25-year limited warranty that actual energy performance shall meet or exceed the projected energy output of the project, subject to a degradation factor of 3% (during the first year of such warranty), which shall increase by an additional 0.7% per year. Under this warranty, First Solar will not be responsible for reductions in energy performance attributable to reasons other than degradation in the performance of the solar modules. If a valid claim is made by a Project Entity under this warranty, First Solar will be required to repair or replace certain of the plant’s modules in order to increase projected energy output to the warranted levels or may instead elect to pay the Project Entity liquidated damages.

In addition, the below-listed Project Entities have each entered EPC agreements with First Solar, dated as of the following dates:

Party	Project	Date
Kingbird Solar A, LLC	Kingbird Project	February 26, 2016
Kingbird Solar B, LLC	Kingbird Project	February 26, 2016
North Star Project Entity	North Star Project	April 30, 2015
Solar Gen 2 Project Entity	Solar Gen 2 Project	October 22, 2014
Stateline Project Entity	Stateline Project	August 31, 2015

Under these EPC agreements, FSEC (as contractor) provides a defect warranty, design warranty and installation services warranty, which generally commence on the substantial completion date and expire 12 months following such date. The defect warranty is a limited warranty that the project is (i) free from defects in materials and workmanship; (ii) new and unused when installed; (iii) in substantial conformance with the technical specifications set forth in the applicable EPC contract; and (iv) of good quality and in good condition. These warranties are subject to certain carve-outs.

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SunPower Projects

The below-listed Project Entities have each entered into performance warranty agreements with SunPower Systems, dated as of the following dates:

Party	Project	Date
Kern Project Entity	Kern Project	January 22, 2016
Henrietta Project Entity	Henrietta Project	October 14, 2015
Hooper Project Entity	Hooper Project	March 24, 2015
Macy's California Project Entities	Macy's California Project	June 19, 2015
Macy's Maryland Project Entity	Macy's Maryland Project	May 6, 2016
Quinto Project Entity	Quinto Project	October 6, 2014
RPU Project Entity	RPU Project	June 8, 2015
UC Davis Project Entity	UC Davis Project	June 19, 2015

Under the applicable performance warranty agreements, SunPower Systems guarantees to each Project Entity that the actual solar energy generation during each 24-month period shall not be less than 95% of the applicable project’s expected (ac) electricity generation for such period. To the extent that the applicable project generates less than the expected amount of electricity, SunPower Systems must compensate such Project Entity for performance liquidated damages. The performance agreements automatically terminate concurrent with the termination of the O&M Agreement for the applicable project.

In addition, the below-listed Project Entities have each entered into EPC agreements with SunPower Systems, dated as of the following dates:

Party	Project	Date
Kern Project Entity	Kern Project	January 22, 2016
Henrietta Project Entity	Henrietta Project	October 14, 2015
Hooper Project Entity	Hooper Project	March 24, 2015
Macy's California Project Entities	Macy's California Project	June 19, 2015
Macy's Maryland Project Entity	Macy's Maryland Project	May 6, 2016
Quinto Project Entity	Quinto Project	October 6, 2014
RPU Project Entity	RPU Project	June 8, 2015
UC Davis Project Entity	UC Davis Project	June 19, 2015

Under the applicable EPC contracts, SunPower Systems provides a limited warranty that the project is (i) free from defects in materials, construction, fabrication and workmanship; (ii) new and unused at the time of delivery (except for use as part of the project facility); (iii) in substantial conformance with the technical specifications set forth in the applicable EPC contract; and (iv) of good quality and in good condition. The defect warranty commences on the substantial completion date and expires on the second anniversary of such date. The defect warranty does not apply to damage or failure to the extent caused by:

• failure by the Project Entity or its representatives, agents or contractors to maintain the facility or perform the work in accordance with industry standards or the recommendations set forth in the manuals provided by SunPower Systems or any of its subcontractors or suppliers;

• operation of the facility in excess of or outside of the operating parameters or specifications as set forth in the applicable manuals provided by SunPower Systems or any of its subcontractors or suppliers;

• any repairs, adjustments, alterations, replacements or maintenance that may be required as a result of normal wear and tear;

• a force majeure event or a specifically excluded site condition as defined in the applicable EPC contract;

• site conditions that are materially non-conformant with the conditions referenced in pre-feasibility studies and other site information provided to SunPower Systems to complete its design work for the facility;

• damage caused by rodents, insects, other animals or plant life;

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• any modifications or enhancement to the facility, or alterations, repairs or replacements performed by the Project Entity or its subsidiaries or affiliates (other than SunPower Systems or any of its subcontractors) made after the substantial completion date without the approval of SunPower Systems and not executed in accordance with the applicable manuals provided by SunPower Systems or any of its subcontractors or suppliers, applicable law, applicable codes and standards set forth in the applicable EPC contract, applicable permits or applicable practices of the utility-scale industry of the United States; or

• acts or omissions of the Project Entity or any subsidiary or affiliate thereof.

If a project covered by the warranty manifests a defect during the warranty period, SunPower Systems, at its own cost and expense, shall refinish, repair or replace, at its option, such non-conforming or defective part of such project as promptly as practical.

Additionally, pursuant to the applicable EPC contracts, SunPower has provided a limited module warranty that (i) the solar modules delivered pursuant to such EPC contracts are free from defects in materials and workmanship under normal application, installation, use and service conditions and (ii) the power output of the modules is at least 95% of the minimum peak power rating for the first five years, declining by no more than 0.4% per year for the following 20 years. The module warranty period begins on the substantial completion date of the applicable project.

The module warranty does not apply to:

• modules subjected to: misuse, abuse, neglect or accident; alteration, improper installation, application or removal; non-observance of the applicable SunPower installation, users and/or maintenance instructions or non-compliance with national and local electric codes; repair or modifications by someone other than an approved service technician of SunPower; conditions exceeding the voltage, wind or snow load specifications; power failure surges, lightning, flood or fire; damage from persons, insects, animals or industrial chemical exposure; glass breakage from impact or other events outside of SunPower’s control;

• cosmetic affects stemming from normal wear and tear of module materials or other cosmetic variations which do not cause power output lower than what is guaranteed by the module warranty;

• modules installed in locations which may be subject to direct contact with bodies of salt water;

• modules for which the labels containing product type or serial number have been altered, removed or made illegible;

• modules which have been moved from their original installation location without the express written approval of SunPower; or

• modules which have been installed on single-family homes or semi-detached homes.

If, during the module warranty period, any module fails to conform to the SunPower module warranty and any loss in power is determined by SunPower (in its sole discretion) not to have resulted from one of the excluded events described above, then SunPower will make all reasonable efforts to repair or replace the affected module with an electrically and mechanically compatible module with an equal or greater power rating. If repair or replacement is not commercially feasible, SunPower will refund the purchase price of the defective module as paid by the Project Entity.

Further, SunPower Systems has agreed to pass through to the applicable Project Entity warranties from identified third-party manufacturers, including an inverter warranty with a warranty term of five years following the substantial completion date.

Residential Portfolio

The Residential Portfolio Project Entity receives certain pass-through warranties from the installer of each PV system. Under the installer’s warranty, the installer warrants that (i) for a period of one year following the applicable lease term start date, or if the system is located in Arizona for a period of two years following the applicable lease term start date, the system will be installed in the manner set forth in the applicable lease; (ii) for a period of ten years following the applicable lease term start date, under normal use and service conditions, the system will conform to the requirements of the applicable lease agreement upon the date of installation and will be free from defects in workmanship or defects in, or breakdown of, materials or components; and (iii) for a period beginning on the date the installer begins installation of the system and continuing through the longer of one year following the lease term start date or the length of any existing roof warranty up to but not exceeding five years, if in the course of installation work the installer is required to penetrate the roof of the premises and thereby cause

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damage to areas of the roof that are within a three-inch radius of roof penetrations, the installer will repair such damages. This warranty does not apply to any lost electricity production or any repair, replacement or correction required due to the following:

• someone other than the installer or a subcontractor specifically approved by the installer installed, constructed, tested, removed, re-installed or repaired the system;

• destruction or damage to the system or its ability to safely produce energy not caused by the installer or its approved subcontractor while servicing the system;

• any event or condition beyond the installer’s control that is a force majeure event;

• a power or voltage surge caused by someone other than the installer, including a grid supply voltage outside of the standard range specified by the local utility or the system specifications or as a result of a local power outage or curtailment;

• shading from foliage that is new growth or is not kept trimmed to the same condition on the date the system was installed;

• any system failure not caused by a system defect; or

• theft of the system.

During the applicable warranty period, the installer will repair or replace any defective part, material or component or correct any defective workmanship at no cost or expense to the lessor or lessee when the lessor submits a valid claim. Additionally, on the applicable lease term start date, the installer agrees to assign to the lessor all limited warranties provided by the manufacturers of the system components.

Shared Facilities Agreement

The North Star Project Entity entered into a shared facilities common ownership agreement (the “Shared Facilities Agreement”), with Little Bear Solar 1, LLC (“Little Bear 1”), Little Bear Solar 2, LLC (“Little Bear 2”) and First Solar Development, LLC (“FSD”). Each of Little Bear 1, Little Bear 2 and FSD are wholly owned subsidiaries of First Solar. Little Bear 1 and Little Bear 2 are developing separate solar facilities in Fresno County, California. FSD may develop future electrical generating facilities in a similar location. Pursuant to the Shared Facilities Agreement, it is contemplated that the North Star Project, projects owned by Little Bear 1 and Little Bear 2 and certain potential future projects developed by FSD or its successors and assigns, may share ownership and usage of certain facilities in the operation of their respective projects in, and bear a pro rata share of the operating costs and expenses for such shared facilities corresponding to their respective ownership interests therein.

Maryland Solar Lease Arrangement

The Maryland Solar Project Entity entered into a lease agreement (the “MD Solar Lease Agreement”), with Maryland Solar Holdings, Inc. (the “Lessee”), an affiliate of First Solar. Under the MD Solar Lease Agreement, the Maryland Solar Project Entity leases the Maryland Solar Project to the Lessee. The MD Solar Lease Agreement has a lease term that expires on December 31, 2019 (unless terminated earlier as described below), and the Lessee is obligated to pay a fixed amount of rent.

Assignment of Leasehold Interests and Project Documents. The Maryland Solar Project Entity is a party to a ground lease for the Maryland Solar Project site with the State of Maryland. Concurrently with the MD Solar Lease Agreement, the Maryland Solar Project Entity subleased to the Lessee its leasehold interest under the ground lease pursuant to a sublease agreement for the term of the MD Solar Lease Agreement. In addition, the Maryland Solar Project Entity is a party to various project documents, including the PPA, O&M agreement and interconnection agreement for the Maryland Solar Project. The Maryland Solar Project Entity assigned these project agreements to the Lessee for the term of the MD Solar Lease Agreement, pursuant to a partial assignment and assumption agreement.

Operation and Maintenance.    During the terms of the MD Solar Lease Agreement, the Maryland Solar Project continues to be operated and maintained by Belectric pursuant to the Maryland Solar O&M Agreement, at the Lessee’s cost. Except for alterations or improvements required under applicable law or the terms of the Maryland Solar Project agreements, the Lessee is prohibited from making any alterations, modifications, additions or improvements to the Maryland Solar Project without the prior written consent of the Maryland Solar Project Entity.

Credit Support. Under the terms of the MD Solar Lease Agreement, the Maryland Solar Project Entity is required to provide and maintain all credit support required to operate the Maryland Solar Project (including letters of credit and surety

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bonds), subject to reimbursement by the Lessee of the actual cost incurred by the Maryland Solar Project Entity in providing and maintaining such instruments.

Termination.    The MD Solar Lease Agreement will terminate upon any termination of the PPA for the Maryland Solar Project or the site ground lease. Upon any such early termination, the Lessee is obligated to return the facility in its then current condition and location, without any warranties, and no rent shall thereafter be payable by the Lessee. Please read Part I, Item 1A, “Risk Factors—Risks Related to Our Business—We rely on a limited number of offtake counterparties and we are exposed to the risk that they are unwilling or unable to fulfill their contractual obligations to us or that they otherwise terminate their offtake agreements with us.”

In addition, either party has the right to terminate the MD Solar Lease Agreement upon the occurrence of certain specified events of default, including:

• a failure by the other party to pay amounts due when such failure to pay is not cured within the cure period;

• a failure by the other party to perform any material obligation under the MD Solar Lease Agreement or the failure of any representation or warranty by the other party to be true and correct in any material respect (in each case, unless due to a force majeure event or attributable to a default by the other party), when such failure is not remedied within the applicable cure period;

• certain bankruptcy or insolvency events related to the other party;

• a final, non-appealable judgment is rendered against the other party that is not covered by an insurance policy and remains unsatisfied for a period of 60 days (unless such judgment is subject to indemnification or is being contested); or

• any of the MD Solar Lease documents become unenforceable against the other party or the performance of the material obligations of the other party under any of the MD Solar Lease documents is declared in a final non-appealable judgment by a court of competent jurisdiction to be illegal.

In addition, the Maryland Solar Project Entity has the right to terminate the MD Solar Lease Agreement if the Lessee (i) abandons the Maryland Solar Project and such abandonment is not remedied within a specified cure period or (ii) sells, leases or disposes all or substantially all of the Lessee’s assets without the prior written consent of the Maryland Solar Project Entity.

Return of the Maryland Solar Project.    At the end of the lease term, or upon an early termination of the MD Solar Lease Agreement, the Maryland Solar Project, the facility site and the project agreements assigned under the MD Solar Lease documents are expected to revert back to the Maryland Solar Project Entity. Subject to compliance by the Maryland Solar Project Entity with its obligations under the MD Solar Lease Agreement, including its obligation regarding replacement of equipment, property insurance and rebuilding upon a casualty, the Lessee is required to return the Maryland Solar Project free and clear of all liens and in good repair, operating condition and working order (other than ordinary wear and tear).

Management Services Agreements

We, our general partner, OpCo and Holdings have entered into an MSA with an affiliate of SunPower and a separate, but similar, MSA with an affiliate of First Solar, each as amended. Hereinafter we refer to such affiliates of SunPower and First Solar under the respective MSAs as “Service Providers”. Under each MSA, the Service Provider agreed to provide or arrange for other persons, including affiliates of First Solar or SunPower, as appropriate, to provide certain management and administrative services to our general partner, OpCo, Holdings and us (each, under each MSA, a “Service Recipient”).

The following is a summary of certain provisions of the MSAs and is qualified in its entirety by reference to all of the provisions of the agreement. Because this description is only a summary of each MSA, it does not necessarily contain all of the information that you may find useful. We therefore urge you to review each MSA in its entirety.

Services Rendered

Under its MSA, the SunPower Service Provider provides, or arranges for an appropriate service provider to provide, the following services:

• providing advice with respect to the carrying out of services to be delivered under the MSA with the First Solar Service Provider;

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• causing or supervising the carrying out of all day-to-day management of the below referenced services;

• preparing and coordinating the preparation of the approved budgets for the Service Recipients, including promptly notifying us of any material variances from the approved budget;

• collecting all payments due to the Service Recipients;

• arranging to pay on behalf of any Service Recipient any amounts required to be paid by such Service Recipient (including all expenses incurred by such Service Recipient or that are due and payable under contracts to which such Service Recipient is a party);

• approving invoices;

• responding to billing inquiries, disputes and late payments;

• collecting and reviewing monthly revenue reconciliation reports;

• administering such Service Recipient’s cash management requirements under, and monitoring its compliance with the terms and conditions of, any financing document (including any revolving loan facility or term loan facility);

• collecting and transmitting required account set up information;

• managing foreign currency, if any;

• administering all hedging programs;

• assisting in the raising of funds and making recommendations regarding the same;

• maintaining each Service Recipient’s deposit accounts at a bank or other financial institution;

• preparing and forwarding for deposit to the appropriate account payments received and a summary transmittal;

• maintaining complete and accurate financial books and records of the operation of such Service Recipients;

• instituting and maintaining an insurance program covering each Service Recipient’s assets, including directors and officers insurance, and collecting, maintaining and distributing required insurance certificates;

• filing insurance claims on behalf of each Service Recipient with the appropriate insurance carrier for any loss;

• assisting in the distribution of any prospectus or offering memorandum and assisting with communications support in connection therewith;

• assisting the Service Recipients in connection with communications with investors and lenders, including presentations, conference calls and other related matters, and investor relations generally;

• managing the investor relations section of our website;

• assisting our general partner in the administration of a long-term incentive plan;

• satisfying all periodic reporting requirements (including any financial reporting requirements) of the Service Recipients; and

• supervising the preparation and submission of unaudited U.S. GAAP balance sheets and statements of operations and annual audited financial statements for each Service Recipient.

These activities are subject to the supervision by the governing body of the relevant Service Recipient.

On January 20, 2017, the parties thereto amended the SunPower MSA to include Kingbird Solar, LLC and the Kingbird Project Entities under certain aspects of SunPower’s scope of managerial services effective April 30, 2016 in return for the associated AMA fee payable by FSAM.

Under its MSA, the First Solar Service Provider provides, or arranges for an appropriate service provider to provide, the following services:

• providing advice with respect to the carrying out of services to be delivered under the MSA with the SunPower Service Provider;

• causing or supervising the carrying out of all day-to-day management of the below referenced services;

• supervising the preparation and filing of all federal, state, city and county tax returns;

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• causing to be paid all taxes and other governmental charges;

• performing additional tax-related services including the calculation of tax accounts, the determination of any tax reserves, the determination of a tax rate for planning and forecasting purposes and the handling of tax audits or other similar proceedings;

• advising and providing assistance related to the development and maintenance of each Service Recipient’s information technology system applications;

• creating, hosting and maintaining Service Recipients’ external website and managing our website (except for the investor relations section of our website);

• advising and providing remote assistance to each Service Recipient related to design, maintenance and operation of the computing environment, including business and network applications;

• negotiating contracts with third-party vendors and suppliers of network infrastructure and communications support;

• managing the purchase and maintenance of information technology software and software services;

• developing, and educating and training the user community regarding, management information systems procedures and policies;

• providing internal audit, compliance and control services for each Service Recipient to comply with applicable law and regulations, including independent identification of risk factors, an evaluation of financial, managerial and operational controls throughout the business designed to address those risk factors and recommendations to improve related processes and controls; and

• summarizing all audit activities to the audit committee of our general partner.

These activities are subject to the supervision by the governing body of the relevant Service Recipient.

Management Fee

Under the MSAs, OpCo, on behalf of itself, our general partner and us, and Holdings, on behalf of itself, pays each Service Provider an annual management fee equal to $0.6 million and $0.1 million, respectively, in the case of the First Solar MSA, and $1.1 million and $0.1 million, respectively, in the case of the SunPower MSA, which amounts shall be adjusted annually for inflation. The management fee is paid in monthly installments.

Reimbursement of Expenses

In addition to the above-described management fees, to the extent not directly billed to OpCo, us or our general partner, OpCo, on behalf of itself, our general partner and us, is required to pay the Service Providers for all out of pocket fees, costs and expenses incurred by or on behalf of such Service Provider in connection with the provision of services on behalf of such Service Recipients (but excluding all such costs related to services provided to Holdings), including those of any third party. To the extent any such expenses relate to other purposes, each Service Provider will, in good faith, limit the amounts charged under its MSA solely to the portion of such expenses related to the services under such MSA. Each Service Provider must obtain the prior written consent of OpCo before incurring any expenses in excess of 110% of the amount included in the approved budget for such expense. Under each MSA, Holdings is subject to an analogous reimbursement obligation, which requires it to pay each Service Provider for the out of pocket amounts it incurs in connection with providing services directly to Holdings.

Such out of pocket fees, costs and expenses include, among other things:

• fees, costs and expenses as a result of a Service Recipient, to the extent applicable, becoming and continuing to be a publicly traded entity;

• fees, costs and expenses relating to any equity financing or for arranging any debt financing;

• taxes, licenses and other statutory fees or penalties levied against or in respect of a Service Recipient in respect of services provided under the MSA;

• amounts owed under indemnification, contribution or similar arrangements;

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• fees, costs and expenses relating to our financial reporting, regulatory filings, investor relations and similar activities;

• fees, costs and expenses of agents, advisors, consultants and other persons who provide services to or on behalf of a Service Recipient;

• fees, expenses and costs incurred in connection with the investigation, acquisition, holding or disposal of any asset or business that is made or that is proposed to be made by the Service Recipients; provided that, where such acquisition or proposed acquisition involves an investment that is made alongside one or more other persons, including the Service Provider or its affiliates, such fees, costs and expenses are allocated in proportion to the notional amount of the investment made (or that would have been made in the case of an unconsummated acquisition) among the Service Recipients and their direct or indirect subsidiaries and such other persons; and

• premiums, deductibles and other costs, fees and expenses for insurance policies covering assets of the Service Recipients and their direct and indirect subsidiaries, together with other applicable insurance against other risks.

OpCo is also required to pay or reimburse the applicable Service Provider for all sales, use, value added, withholding or other similar taxes or customs duties or other governmental charges levied or imposed by reason of such Service Provider’s MSA or any agreement contemplated thereby, other than income taxes, corporate taxes, capital gains taxes or other similar taxes payable by any member of the applicable Service Provider Group.

Indemnification and Limitation on Liability

Under each MSA, each member of the applicable Service Provider Group does not assume any responsibility other than to provide or arrange for the provision of the services described in such MSA in good faith and is not responsible for any action taken by a Service Recipient in following or declining to follow the advice or recommendations of the relevant member of the Service Provider Group. The maximum amount of the aggregate liability of the Service Provider in providing services under the applicable MSA is equal to the aggregate amount of the management fee received by such Service Provider in the most recent fiscal year.

We and the Service Recipients have also agreed to indemnify each Service Provider Group and any directors, officers, agents, members, partners, stockholders, employees and other representatives thereof to the fullest extent permitted by law from and against any claims, liabilities, losses, damages, costs or expenses (including legal fees) incurred by them or threatened in connection with any and all actions, suits, investigations, proceedings or claims or any kind whatsoever arising in connection with the applicable MSA and the Services provided thereunder. However, no member of such Service Provider Group shall be so indemnified with respect to a claim that is finally determined by a final and non-appealable judgment entered by a court of competent jurisdiction or pursuant to a settlement agreement to have resulted from such indemnified person’s bad faith, fraud or willful misconduct or, in the case of a criminal matter, conduct undertaken with knowledge that such conduct was unlawful.

Termination

The term of each MSA is five years and will automatically renew for successive five-year periods unless OpCo or the applicable Service Provider provides written notice that it does not wish for the agreement to be renewed. However, OpCo is able to terminate the MSA prior to the expiration of its term (i) with cause, upon 30 days’ prior written notice or (ii) without cause, upon 90 days’ prior written notice. OpCo may only terminate the MSA in such a manner with the prior written approval of our Board.

Each Service Provider may terminate its applicable MSA, effective 30 days after written notice:

• if any Service Recipient defaults in the performance or observance of any material term, condition or agreement contained in the agreement in a manner that results in a material harm to any member of the Service Provider Group and the default continues unremedied for a period of 60 days after written notice thereof;

• upon the occurrence of certain events relating to the bankruptcy or insolvency of us, our general partner, Holdings or OpCo; and

• if such Service Provider’s Sponsor and its affiliates fail to own, directly or indirectly, at least 50% of the management units of Holdings.

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Omnibus Agreement

We have entered into the Omnibus Agreement, with First Solar, SunPower, our general partner, OpCo and Holdings. Pursuant to the Omnibus Agreement, (i) each Sponsor has an exclusive right to perform certain services not otherwise covered by an O&M agreement or AMA on behalf of the Project Entities contributed by such Sponsor, (ii) with respect to any project in the Portfolio that had not achieved commercial operation as of the date contributed to us, the Sponsor who contributed such project agreed to pay to OpCo all costs required to complete such project, as well as certain liquidated damages in the event such project fails to achieve operability pursuant to an agreed schedule (subject to certain adjustments), (iii) each Sponsor agreed to certain undertakings on the part of its affiliates who are members of the Project Entities or who provide asset management, construction, operating and maintenance and other services to the Project Entities contributed by such Sponsor, (iv) to the extent a Sponsor continues to post credit support on behalf of a Project Entity after it has been contributed to OpCo, OpCo agreed to reimburse such Sponsor upon any demand or draw under such credit support, and the Sponsor agreed to maintain such support pursuant to the applicable underlying contractual or regulatory requirements, (v) each Sponsor agreed to indemnify OpCo for certain costs it incurs with respect to certain tax-related events and events in connection with tax equity financing arrangements and (vi) the parties agreed to a mutual undertaking regarding confidentiality and use of names trademarks, trade names and other insignias.

Undertakings Related to Services; Credit Support

Each of First Solar and SunPower has the exclusive right to perform, itself or through one or more designees, certain construction, engineering, design and procurement services, and equipment supply services, in connection with any upgrade or expansion of any project owned by one of such Sponsor’s contributed Project Entities, as well as any operation and maintenance services and administrative services required by any such project (except as otherwise provided by an existing agreement). Such services must be provided on market-based terms and the contract governing such services must be administered on an arm’s-length basis. The right to provide such services shall cease to apply to any Sponsor that does not own, directly or indirectly, at least 50% of the management units of Holdings. To the extent that an affiliate of a Sponsor provides asset management services (under AMAs or similar agreements, for example), or acts as the managing member (under a tax equity arrangement), of a Project Entity contributed by such Sponsor, each of First Solar and SunPower agreed it will not permit such affiliate to cause such contributed Project Entity to take, or fail to take, any action which action, or failure to act, would have required the approval by the Board or the project operations committee of our general partner’s board pursuant to our general partner’s limited liability company agreement. Each Sponsor also agreed to cause its above-described affiliates to cooperate with the Service Providers, as necessary, in connection with the services provided by the Service Providers under their respective MSAs between such Service Provider, us, our general partner, OpCo and Holdings. In addition, where an affiliate of either Sponsor is the contractor under an EPC contract, or the operator under an O&M agreement, with any contributed Project Entity of such Sponsor, each of First Solar and SunPower agrees to reimburse such contributed Project Entity for the amount of certain performance bonuses (or, in some cases, a portion thereof) paid by such contributed Project Entity under such agreements, or to cause such affiliate to waive its rights to receive certain future bonuses. Each Sponsor also agreed to ensure its contributed Project Entities are provided with tax support and related services.

Where a Sponsor continues to provide certain guarantees and other forms of credit support on behalf of any of its contributed Project Entities, OpCo agreed to reimburse such Sponsor for payments made upon any demand or draw (or, in some cases, a portion thereof) under such credit support. However, OpCo will have no such obligation to the extent any such demand or draw results from any action of the Sponsor. Each Sponsor agreed to continue to provide such guarantees and other credit support on behalf of its contributed Project Entities, as required pursuant to the applicable contract or permit that gives rise to such obligation.

Undertakings Related to Commercial Operation; Liquidated Damages

Pursuant to the Omnibus Agreement, to the extent any project in the Portfolio had not achieved commercial operation as of the date contributed to us, the contributing Sponsor is obligated to take all actions necessary for such project to become commercially operational, and to pay or reimburse OpCo and its subsidiaries for all related costs (except as otherwise provided below). The Omnibus Agreement also provides that, if a project in the Portfolio fails to achieve commercial operation on or prior to an agreed deadline (as set forth in the Omnibus Agreement), the applicable contributing Sponsor is required to pay OpCo delay liquidated damages, the amount of which are calculated based on the operating cash flow projected to have been generated by such project had it achieved commercial operation as expected, as well as the amount of cash flow such project was expected to generate during the period prior to its projected completion date, minus the amount of actual distributed cash attributable to such project during the same periods (“Delay Damages”). With respect to each project, any Delay Damages will be paid to OpCo following such projects’ expected commercial operation date and thereafter on a quarterly basis.

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Moreover, to the extent any such project has still not achieved its agreed minimum capacity or commercial operation within one year of its agreed commercial operation deadline, the contributing Sponsor of such project shall pay to OpCo:

• in the event (i) such project’s actual capacity as measured by the most recent capacity test performed under such project’s construction contract (the “Actual Project Capacity”) fails to equal an agreed minimum capacity amount for such project (as set forth in the Omnibus Agreement) or (ii) such project has not yet achieved commercial operation or a similar milestone under the interconnection agreement and power purchase agreements, lease or hedging agreements, as applicable, for such project, “buy-down” liquidated damages in an amount calculated based on the minimum capacity required to achieve substantial completion or a similar milestone under such project’s construction contract (the “Guaranteed Project Capacity”) and a “Capacity Buy-Down Amount” (in $/MW) for such project, which was determined upon the closing of the IPO based on the portion of OpCo’s total market value agreed to be attributable to such project (such damages, “Total Buy-Down Liquidated Damages”); or

• in all other cases, “buy-down” liquidated damages equal to the product of (i) the positive difference of (x) the Guaranteed Project Capacity for such project less (y) such Project’s Actual Project Capacity, multiplied by (ii) the Capacity-Buy Down Amount for such project.

In either case, the amount of such damages are reduced by the amount of any capacity liquidated damages paid by the contractor under such project’s construction contract and which constitute distributed cash for OpCo. If a contributing Sponsor is required to pay Total Buy-Down Liquidated Damages in respect of a project, such Sponsor shall have the right to repurchase such project from OpCo without payment of any additional consideration. Moreover, with respect to each project, to the extent a contributing Sponsor becomes liable for the above-described “buy-down” liquidated damages, such Sponsor shall have no further obligation to incur costs related to achieving commercial operation or pay Delay Damages with respect thereto.

In addition, with respect to each of the North Star Project and the Quinto Project, the Sponsors agreed to pay to OpCo the difference, if any, between the amount of network upgrade refunds projected to be received in respect of the Sponsor’s contributed project at the time of our IPO and the amount of network upgrade refunds projected to be received in respect of such project at the commencement of commercial operation of such project.  

Tax-Related Indemnification

Under the Omnibus Agreement, each of First Solar and SunPower agreed to indemnify OpCo from and against certain damages up to agreed limits incurred or sustained by us and our subsidiaries relating to the following, with respect to any of the Project Entities contributed by such Sponsor:

• the inapplicability or unavailability of any exclusion or exemption from or other reduction in the base of or liability for any property or similar tax, to the extent such exclusion, exemption or reduction has been reflected in the financial model included in the Master Formation Agreement between the Sponsors (the “Exemption Loss Indemnity”);

• any reassessment with respect to any property or similar tax assessment to the extent such reassessment is not reflected in the financial model included in the Master Formation Agreement between the Sponsors (the “Reassessment Indemnity”);

• any payment under any tax equity financing agreement that is made as a result of any breach of any representation, warranty, covenant or similar provision of such agreement or pursuant to any indemnification obligation under such agreement;

• any payment that is made pursuant to the indemnification obligation under that certain Second Amended and Restated Limited Liability Company Agreement of Kingbird Solar, LLC for special underpayment interest;

• any requirement under any tax equity financing agreement to divert distributions due to a determination by a governmental entity (i) regarding a project’s fair market value or the tax basis of a project or (ii) that a contract entered into by a Project Entity and any affiliate thereof is not on arm’s-length terms;

• with respect to any SunPower Project Entity, any event which results in the repayment of all or any portion of any cash grant received by such Project Entity under the Federal section 1603 cash grant program; and

• to the extent OpCo or its subsidiary is required to pay the purchase price in respect of the acquisition of a Project Entity or project in excess of tax equity or equity contribution proceeds received by OpCo or such subsidiary for

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the purpose of paying such purchase price (and such Sponsor also agrees to waive, or cause its affiliate to waive, all claims for payment of such purchase price to the extent of such excess).

The Exemption Loss Indemnity and the Reassessment Indemnity will cease to apply to the Residential Portfolio as of June 24, 2018. Each Sponsor’s damages payable under such indemnification claims do not apply to a Sponsor in any fiscal year if the cash distributed to OpCo in such fiscal year from such Sponsor’s contributed Project Entities exceeds the cash projected to be distributed from such Project Entities and any projects contributed at no cost by such Sponsor to make up distributed cash shortfalls from such Project Entities. In addition, each Sponsor’s indemnity obligation is limited to an agreed amount, for each project, which is determined based on the portion of the total market value of Holdings (as determined in the IPO) agreed to be attributable to such project.

Use of Names and Insignia

Under the Omnibus Agreement, we agreed not to, and to cause our subsidiaries not to, directly or indirectly use any service marks, trade names, domain names or insignia related thereto containing the words First Solar or SunPower without the prior written consent of such party. 

Solar Gen 2 Working Capital Loan

On November 25, 2015, OpCo issued the Short-Term Note to First Solar in the principal amount of $2.0 million, in exchange for First Solar’s loan of such amount to OpCo. Upon the receipt of certain payments by the Solar Gen 2 Project Entity from SDG&E under the power purchase agreement between the Solar Gen 2 Project Entity and SDG&E, which had been previously withheld pending completion of an administrative requirement (each, a “Specified Payment”), OpCo was obligated to repay a portion of the principal amount of the Short-Term Note equal to such Specified Payment and the unpaid balance of all interest accrued under the Short-Term Note to and including the date of such repayment. Interest under the Short-Term Note accrued at a rate of 1% on the portion of the principal of the Short-Term Note equal to the amount of each Specified Payment from the date SDG&E remitted such payment to the Solar Gen 2 Project Entity through the date that OpCo repaid such amount to First Solar in accordance with the previous sentence. OpCo was permitted to prepay the Short-Term Note at any time without penalty or premium. On December 30, 2016, OpCo paid in full the Short-Term Note with a balance of $1,964,148 principal and no accrued interest.

Stateline Promissory Note

In connection with the acquisition of the Stateline Project on December 1, 2016, OpCo issued the Stateline Promissory Note to a subsidiary of First Solar in the principal amount of $50.0 million. The promissory note is unsecured and matures on the date that is six months after the maturity date under OpCo’s credit facility. Interest accrues at a rate of 4% per annum, except it will accrue at a rate of 6% per annum (i) upon the occurrence and during the continuation of a specified event of default and (ii) in respect of amounts accrued as payments-in-kind pursuant to the terms of the promissory note. OpCo is not permitted to prepay the promissory note without the consent of certain lenders under its existing credit agreement (except for certain mandatory prepayments). In fiscal 2017, OpCo paid $0.4 million of the principal amount and $1.5 million of interest to a subsidiary of First Solar.

Until OpCo has paid in full the principal and interest on the Stateline Promissory Note, OpCo is restricted in its ability to:

• acquire interests in additional projects;

• use the net proceeds of equity issuances except as prescribed in the Stateline Promissory Note;

• incur additional indebtedness to which the Stateline Promissory Note would be subordinate; and

• extend the maturity date under OpCo’s credit facility.

Please read Part I, Item 1A, “Risk Factors—Risks Related to Our Business—OpCo is not permitted to acquire interests in projects until we pay in full the principal of and interest on the Stateline Promissory Note.”

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ROFO Agreements

OpCo entered into the First Solar ROFO Agreement. Under the First Solar ROFO Agreement, as amended, First Solar granted OpCo a right of first offer to purchase certain projects in the event of any proposed sale, transfer or other disposition of such projects by First Solar until June 24, 2020. In fiscal 2017, we and our Sponsors agreed to make several adjustments to the projects subject to the ROFO Agreements to better align such agreements with our ability to acquire such projects. As a result of such adjustments, we no longer have a right of first offer on any projects developed by First Solar. OpCo entered into the SunPower ROFO Agreement. Under the SunPower ROFO Agreement, as amended, SunPower granted OpCo a right of first offer to purchase any of its SunPower ROFO Projects in the event of any proposed sale, transfer or other disposition of such SunPower ROFO Projects until June 24, 2020. For an overview of the SunPower ROFO Projects as of November 30, 2017, please read Part I, Item 1, “Business—Our Portfolio—SunPower ROFO Projects.”

Notwithstanding the above, certain sales and transfers of the SunPower ROFO Projects by SunPower are exempt from OpCo’s right of first offer. These exceptions include:

• mergers or consolidations of SunPower into a third party (or any sale by SunPower of all or substantially all of its assets);

• sales of any SunPower ROFO asset that is a utility-scale solar energy project, which result in the monetization of tax incentives associated with such project, so long as SunPower retains interests that entitle it to at least 45% of the cash distributions of such SunPower ROFO asset; and

• sales of a partial economic interest in any SunPower ROFO asset or any of its assets as part of a tax equity investment in such SunPower ROFO asset (including any partnership flip, sale leaseback or pass-through lease transaction);

provided, that the terms of any such sale referred to in the second or third bullet points above will not impair or delay the ability of OpCo to acquire such SunPower ROFO Project from SunPower or its affiliate in accordance with the terms of the SunPower ROFO Agreement if and when SunPower elects to sell, transfer or otherwise dispose of such SunPower ROFO Project to a third party.

Under the SunPower ROFO Agreement, SunPower is not obligated to sell the SunPower ROFO Projects and, therefore, we do not know when, if ever, these projects will be made available to OpCo. Even if an offer is made to OpCo, OpCo and SunPower may not reach an agreement on the terms for the sale of the applicable ROFO Project. In addition, SunPower has the right to remove a SunPower ROFO Project from the SunPower ROFO Agreement, to the extent SunPower sells or contributes a non-SunPower ROFO Project to OpCo for which forecasted distributed cash is projected to equal or exceed the forecasted distributed cash of such SunPower ROFO Project proposed for removal.

Due to the limitations on our ability to acquire projects under the Merger Agreement, in connection with the Conflicts Committee’s and the Board’s approval of the Merger Agreement, we agreed to enter into the Waiver Agreement with SunPower which waives our right of first offer on all the projects subject to the SunPower ROFO Agreement during the pendency of the Merger Agreement. In the event that the Merger Agreement terminates without the closing of the Mergers, the waiver would terminate with respect to all projects subject to the SunPower ROFO Agreement, except, with respect to individual projects still owned by SunPower at the termination of such waiver, such project is either under an exclusivity agreement with a third party or has an offer for purchase from a third party pursuant to which SunPower is in negotiations.

Exchange Agreement

We have entered into an Exchange Agreement with our Sponsors, our general partner and OpCo, under which a Sponsor can tender OpCo common units and an equal number of such Sponsor’s Class B shares (together referred to as the “Tendered Units”), for redemption to OpCo and us. Each Sponsor has the right to receive, at the election of OpCo with the approval of the Conflicts Committee, either the number of our Class A shares equal to the number of Tendered Units or a cash payment equal to the number of Tendered Units multiplied by the then current trading price of our Class A shares. In addition, we have the right but not the obligation, to directly purchase such Tendered Units for, subject to the approval of our Conflicts Committee, cash or our Class A shares at our election.

The Exchange Agreement also provides that, subject to certain exceptions, a Sponsor does not have the right to exchange its OpCo common units if OpCo or we determine that such exchange would be prohibited by law or regulation or would violate other agreements to which we may be subject, and OpCo and we may impose additional restrictions on exchange

170

that either of us determines necessary or advisable so that we are not treated as a “publicly traded partnership” for U.S. federal income tax purposes.

If OpCo elects to require the delivery of our Class A shares in exchange for such Sponsor’s Tendered Units, the exchange will be on a one-for-one basis, subject to adjustment in the event of splits or combinations of units, distributions of warrants or other unit purchase rights, specified extraordinary distributions and similar events. If OpCo elects to deliver cash in exchange for such Sponsor’s Tendered Units, or if we exercise our right to purchase Tendered Units for cash, the amount of cash payable will be based on the net proceeds received by us in a sale of an equivalent number of our Class A shares.

Registration Rights Agreement

We have entered into a Registration Rights Agreement with our Sponsors and certain of their respective affiliates under which each Sponsor and its affiliates are entitled to demand registration rights, including the right to demand that a shelf registration statement be filed, and “piggyback” registration rights, for our Class A shares that they may acquire.

Procedures for Review, Approval and Ratification of Related-Person Transactions

We have established procedures in our general partner’s limited liability company agreement, our Partnership Agreement and OpCo’s limited liability company agreement for the identification, review and approval of related person transactions. These procedures set forth certain transactions that must be approved by the Board. If, after applying these standards, management determines that a proposed transaction is a related person transaction, management must present the proposed transaction to the Board for review. The board must then either approve or reject the transaction in accordance with the terms of our Partnership Agreement. The Board may, but is not required to, seek the approval of the Conflicts Committee for the resolution of any related person transaction.

Director Independence

The NASDAQ does not require a listed publicly traded limited partnership, such as us, to have a majority of independent directors on the Board. For a discussion of the independence of the members of the Board, please read Part III, Item 10, “Directors, Executive Officers and Corporate Governance—Management—Director Independence.”

Item 14. Principal Accounting Fees and Services.

The following table presents fees for professional accounting and other related services rendered by PricewaterhouseCoopers LLP:

	Year Ended
	November 30, 2017		November 30, 2016
Audit Fees	$	1,411,658	$	1,835,250
Audit-Related Fees	—		—
Tax Fees	—		—
All Other Fees	—		—
Total Fees	$	1,411,658	$	1,835,250

In accordance with the requirements of the Sarbanes-Oxley Act and the audit committee charter, all services performed by PricewaterhouseCoopers LLP are approved in advance by the audit committee. The audit committee is also responsible for confirming the independence and objectivity of PricewaterhouseCoopers LLP. PricewaterhouseCoopers LLP is given unrestricted access to the audit committee.

171

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a)    The following documents are filed as a part of this Annual Report on Form 10-K.

(1) Financial Statements:

The financial statements and supplementary information listed in the Index to Financial Statements, which appears in Part II, Item 8. “Financial Statements and Supplementary Data,” are filed as part of this Annual Report on Form 10-K.

(2) Financial Statement Schedule:

All financial statement schedules are omitted as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or Notes to Consolidated Financial Statements under Part II, Item 8. “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

The consolidated financial statements of SG2 Holdings, North Star Holdings and Henrietta Holdings, 49% owned equity method investees, as well as Stateline Holdings, a 34% owned equity method investee, required pursuant to Rule 3-09 of the Securities and Exchange Commission’s Regulation S-X, will be filed when available by amendment to this Form 10-K on or before April 1, 2018. The consolidated financial statements of SG2 Holdings, North Star Holdings, Henrietta Holdings and Stateline Holdings will be audited as of both December 31, 2017 and December 31, 2016 and prepared in accordance with U.S. GAAP.

(3) Exhibits: See Item 15(b) below.

(b)    Exhibits: The exhibits listed on the accompanying Index to Exhibits on this Annual Report on Form 10-K are filed, furnished, or incorporated into this Annual Report on Form 10-K by reference, as applicable.

172

Exhibit Index
Exhibit		Incorporated by Reference
Number	Description	Form	File No.	Exhibit	Filing Date
2.1	Purchase, Sale and Contribution Agreement dated January 26, 2016 by and between SunPower Corporation and 8point3 Operating Company, LLC.	8-K	001-37447	2.1	1/27/2016
2.2	First Amendment to Purchase, Sale and Contribution Agreement dated September 28, 2016 by and between SunPower Corporation and 8point3 Operating Company, LLC.	8-K	001-37447	2.1	10/3/2016
2.3	Second Amendment to Purchase, Sale and Contribution Agreement dated November 30, 2016, by and between SunPower Corporation and 8point3 Operating Company, LLC.	8-K	001-37447	2.1	12/5/2016
2.4	Third Amendment to Purchase, Sale and Contribution Agreement dated February 24, 2016, by and between SunPower Corporation and 8point3 Operating Company, LLC.	8-K	001-37447	2.1	3/1/2017
2.5	Letter Agreement dated June 9, 2017, by and between 8point3 Operating Company, LLC and SunPower Corporation.	8-K	001-37447	2.1	6/13/2017
2.6	Purchase and Sale Agreement dated March 31, 2016 by and among First Solar Asset Management, LLC, 8point3 Operating Company, LLC and First Solar, Inc..	8-K	001-37447	2.1	4/1/2016
2.7	Contribution Agreement dated March 31, 2016 by and among SunPower AssetCo, LLC, 8point3 Operating Company, LLC and SunPower Corporation.	8-K	001-37447	2.2	4/1/2016
2.8	Contribution Agreement dated June 29, 2016 by and among SunPower AssetCo, LLC, 8point3 Operating Company, LLC and SunPower Corporation.	8-K	001-37447	2.1	6/29/2016
2.9	Contribution Agreement dated September 20, 2016 by and among SunPower AssetCo, LLC, 8point3 Operating Company, LLC and SunPower Corporation.	8-K	001-37447	2.1	9/22/2016
2.10	Purchase and Sale Agreement dated November 11, 2016 by and among First Solar Asset Management, LLC, 8point3 Operating Company, LLC and First Solar, Inc..	8-K	001-37447	2.1	11/14/2016
3.1	Certificate of Limited Partnership of 8point3 Energy Partners LP dated March 2, 2015.	S-1	333-202634	3.1	3/10/2015
3.2	Amended and Restated Agreement of Limited Partnership of 8point3 Energy Partners LP dated June 24, 2015.	8-K	001-37447	3.1	6/30/2015
3.3	Certificate of Formation of 8point3 Operating Company, LLC dated April 8, 2015.	S-1/A	333-202634	3.3	4/27/2015
3.4	Amended and Restated Limited Liability Company Agreement of 8point3 Operating Company, LLC dated June 24, 2015.	8-K	001-37447	3.2	6/30/2015
3.5	Certificate of Formation of 8point3 General Partner, LLC dated March 2, 2015 (incorporated by reference to Exhibit 3.5 to the Registrant’s Registration Statement on Form S-1.	S-1	333-202634	3.5	3/10/2015
3.6	Amended and Restated Limited Liability Company Agreement of 8point3 General Partner, LLC dated June 24, 2015.	8-K	001-37447	3.2	6/30/2015

173

Exhibit Index
Exhibit		Incorporated by Reference
Number	Description	Form	File No.	Exhibit	Filing Date
10.1	Contribution, Conveyance, Assignment and Assumption Agreement dated June 24, 2015, by and among First Solar 8point3 Holdings, LLC, Maryland Solar Holdings, Inc., SunPower YC Holdings, LLC, 8point3 Energy Partners LP and 8point3 Operating Company, LLC.	8-K	001-37447	10.1	6/30/2015
10.2	Amended and Restated Omnibus Agreement dated April 6, 2016, by and among 8point3 Operating Company, LLC, 8point3 General Partner, LLC, 8point3 Holding Company, LLC, 8point3 Energy Partners LP, First Solar, Inc. and SunPower Corporation.	8-K	001-37447	10.2	4/7/2016
10.3	Amendment No. 1 to Amended and Restated Omnibus Agreement dated July 1, 2016, by and among 8point3 Operating Company, LLC, 8point3 General Partner, LLC, 8point3 Holding Company, LLC, 8point3 Energy Partners LP, First Solar, Inc. and SunPower Corporation.	8-K	001-37447	10.1	7/6/2016
10.4	Amendment No. 2 to Amended and Restated Omnibus Agreement dated September 9, 2016, by and among 8point3 Operating Company, LLC, 8point3 General Partner, LLC, 8point3 Holding Company, LLC, 8point3 Energy Partners LP, First Solar, Inc. and SunPower Corporation.	8-K	001-37447	10.1	9/14/2016
10.5	Amendment No. 3 to Amended and Restated Omnibus Agreement dated September 29, 2016, by and among 8point3 Operating Company, LLC, 8point3 General Partner, LLC, 8point3 Holding Company, LLC, 8point3 Energy Partners LP, First Solar, Inc. and SunPower Corporation.	8-K	001-37447	10.1	10/3/2016
10.6	Amendment No. 4 to Amended and Restated Omnibus Agreement dated November 30, 2016, by and among 8point3 Operating Company, LLC, 8point3 General Partner, LLC, 8point3 Holding Company, LLC, 8point3 Energy Partners LP, First Solar, Inc. and SunPower Corporation.	8-K	001-37447	10.1	12/5/2016
10.7	Amendment No. 5 to Amended and Restated Omnibus Agreement dated December 1, 2016, by and among 8point3 Operating Company, LLC, 8point3 General Partner, LLC, 8point3 Holding Company, LLC, 8point3 Energy Partners LP, First Solar, Inc. and SunPower Corporation.	8-K	001-37447	10.2	12/5/2016
10.8	Amendment No. 6 to Amended and Restated Omnibus Agreement dated February 24, 2017, by and among 8point3 Operating Company, LLC, 8point3 General Partner, LLC, 8point3 Holding Company, LLC, 8point3 Energy Partners LP, First Solar, Inc. and SunPower Corporation.	8-K	001-37447	10.1	3/1/2017
10.9	Amendment No. 7 to Amended and Restated Omnibus Agreement dated June 9, 2017, by and among 8point3 Operating Company, LLC, 8point3 General Partner, LLC, 8point3 Holding Company, LLC, 8point3 Energy Partners LP, First Solar, Inc. and SunPower Corporation.	8-K	001-37447	10.1	6/13/2017

174

Exhibit Index
Exhibit		Incorporated by Reference
Number	Description	Form	File No.	Exhibit	Filing Date
10.1	Right of First Offer Agreement dated June 24, 2015, by and between 8point3 Operating Company, LLC and First Solar, Inc..	8-K	001-37447	10.3	6/30/2015
10.11	Amendment and Waiver to the Right of First Offer Agreement dated March 28, 2016, by and between 8point3 Operating Company, LLC and First Solar, Inc..	8-K	001-37447	10.2	4/1/2016
10.12	Amendment and Waiver No. 2 to Right of First Offer Agreement dated June 28, 2016, by and between 8point3 Operating Company, LLC and First Solar, Inc..	8-K	001-37447	10.1	6/29/2016
10.13	Right of First Offer Agreement dated June 24, 2015, by and between 8point3 Operating Company, LLC and SunPower Corporation.	8-K	001-37447	10.4	6/30/2015
10.14	First Amendment and Waiver to the Right of First Offer Agreement dated September 30, 2016, by and between 8point3 Operating Company, LLC and SunPower Corporation..	8-K	001-37447	10.3	10/3/2016
10.15	Second Amendment and Waiver to the Right of First Offer Agreement dated February 13, 2017, by and between 8point3 Operating Company, LLC and SunPower Corporation..	8-K	001-37447	10.1	2/14/2017
10.16	8point3 General Partner, LLC Long-Term Incentive Plan.	8-K	001-37447	10.5	6/30/2015
10.17	Management Services Agreement dated June 24, 2015, by and among 8point3 Operating Company, LLC, 8point3 Energy Partners LP, 8point3 General Partner, LLC, 8point3 Holding Company, LLC and First Solar 8point3 Management Services, LLC.	8-K	001-37447	10.6	6/30/2015
10.18	Amendment No. 1 to Management Services Agreement dated August 11, 2015, by and among 8point3 Operating Company, LLC, 8point3 Energy Partners LP, 8point3 General Partner, LLC, 8point3 Holding Company, LLC and First Solar 8point3 Management Services, LLC.	8-K	001-37447	10.2	8/17/2015
10.19	Management Services Agreement dated June 24, 2015, by and among 8point3 Operating Company, LLC, 8point3 Energy Partners LP, 8point3 General Partner, LLC, 8point3 Holding Company, LLC and SunPower Capital Services, LLC.	8-K	001-37447	10.7	6/30/2015
10.20	Amendment No. 1 to Management Services Agreement dated August 11, 2015, by and among 8point3 Operating Company, LLC, 8point3 Energy Partners LP, 8point3 General Partner, LLC, 8point3 Holding Company, LLC and SunPower Capital Services, LLC.	8-K	001-37447	10.3	8/17/2015
10.21	Amendment No. 2 to Management Services Agreement dated January 20, 2017, by and among 8point3 Operating Company, LLC, 8point3 Energy Partners LP, 8point3 General Partner, LLC, 8point3 Holding Company, LLC and SunPower Capital Services, LLC.	10-Q	001-37447	10.1	4/6/2017

175

Exhibit Index
Exhibit		Incorporated by Reference
Number	Description	Form	File No.	Exhibit	Filing Date
10.22	Exchange Agreement dated June 24, 2015, by and among SunPower YC Holdings, LLC, First Solar 8point3 Holdings, LLC, 8point3 Operating Company, LLC, 8point3 General Partner, LLC and 8point3 Energy Partners LP .	8-K	001-37447	10.8	6/30/2015
10.23	Registration Rights Agreement dated June 24, 2015, by and among 8point3 Energy Partners LP, First Solar 8point3 Holdings, LLC and SunPower YC Holdings, LLC.	8-K	001-37447	10.9	6/30/2015
10.24	Equity Purchase Agreement dated June 24, 2015, by and between 8point3 Energy Partners LP and 8point3 Operating Company, LLC.	8-K	001-37447	10.10	6/30/2015
10.25	Credit and Guaranty Agreement dated as of June 5, 2015, among 8point3 Operating Company, LLC, 8point3 Energy Partners LP, certain subsidiaries of 8point3 Operating Company, LLC, various lenders party thereto and Credit Agricole Corporate and Investment Bank, as administrative agent and collateral agent.	S-1/A	333-202634	10.6	6/9/2015
10.26	First Amendment and Consent to Credit and Guaranty Agreement dated April 6, 2016, among 8point3 Operating Company, LLC, 8point3 Energy Partners LP, certain subsidiaries of 8point3 Operating Company, LLC, various lenders party thereto and Credit Agricole Corporate and Investment Bank, as administrative agent and collateral agent.	8-K	001-37447	10.3	4/7/2016
10.27	Second Amendment and Consent to Credit and Guaranty Agreement dated September 30, 2016, among 8point3 Operating Company, LLC, 8point3 Energy Partners LP, certain subsidiaries of 8point3 Operating Company, LLC, various lenders party thereto and Credit Agricole Corporate and Investment Bank, as administrative agent and collateral agent.	8-K	001-37447	10.2	10/3/2016
10.28	Promissory Note dated as of December 1, 2016.	8-K	001-37447	10.3	12/5/2016
10.29#	Form of Indemnification Agreement.	8-K	001-37447	10.1	6/24/2015
21*	List of Subsidiaries.	—	—	—	—
23.1*	Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.	—	—	—	—
31.1*	Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	—	—	—	—
31.2*	Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	—	—	—	—
32.1**	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	—	—	—	—
32.2**	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	—	—	—	—
101.INS*	XBRL Instance Document	—	—	—	—
101.SCH*	XBRL Taxonomy Extension Schema Document	—	—	—	—

176

Exhibit Index
Exhibit		Incorporated by Reference
Number	Description	Form	File No.	Exhibit	Filing Date
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document	—	—	—	—
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document	—	—	—	—
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document	—	—	—	—
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document	—	—	—	—

* Filed herewith

** Furnished herewith

# Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K pursuant to Item 15(b).

177

Item 16. Form 10-K Summary

None.

178

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

		8point3 Energy Partners LP
		By:	8point3 General Partner, LLC
			its general partner
Date:	February 5, 2018	By:	/s/ CHARLES D. BOYNTON
			Charles D. Boynton
			Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.

Name	Title
/s/ CHARLES D. BOYNTON	Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer) 8point3 General Partner, LLC	February 5, 2018
Charles D. Boynton
/s/ BRYAN SCHUMAKER	Chief Financial Officer (Principal Financial Officer) 8point3 General Partner, LLC	February 5, 2018
Bryan Schumaker
/s/ ALEXANDER R. BRADLEY	Director 8point3 General Partner, LLC	February 5, 2018
Alexander R. Bradley
/s/ NATALIE F. JACKSON	Director 8point3 General Partner, LLC	February 5, 2018
Natalie F. Jackson
/s/ THOMAS C. O’CONNOR	Director 8point3 General Partner, LLC	February 5, 2018
Thomas C. O’Connor
/s/ NORMAN J. SZYDLOWSKI	Director 8point3 General Partner, LLC	February 5, 2018
Norman J. Szydlowski
/s/ MARK R. WIDMAR	Director 8point3 General Partner, LLC	February 5, 2018
Mark R. Widmar
/s/ MICHAEL W. YACKIRA	Director 8point3 General Partner, LLC	February 5, 2018
Michael W. Yackira

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