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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

OR

For the transition period from December 28, 2014 to November 30, 2015

Commission File Number 001-37447

 

8point3 Energy Partners LP

(Exact name of Registrant as specified in its Charter)

 

 

Registrant’s telephone number, including area code: (408) 240-5500

 

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

 

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  o    No  x

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

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  x    No  o

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  x    No  o

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.  x

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

 

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

The aggregate market value of the registrant’s Class A Shares held by non-affiliates on June 30, 2015, the last business day of the Registrant’s most recently completed second fiscal quarter (based on the closing sale price of $18.62 of the Registrant’s Class A shares, as reported by the NASDAQ Global Select Market on such date) was approximately $372.4 million.

The number of shares of Registrant’s Class A Shares outstanding as of January 22, 2016 was 20,007,281.

Documents incorporated by reference:

None.

 

 

 

 

 

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Table of Contents

GLOSSARY

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

 

 

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GLOSSARY

Unless the context provides otherwise, references herein to “we,” “us,” “our,” “the Partnership” and “8point3 Partners” or like terms, when used for time periods prior to June 24, 2015, refer to the projects that our Sponsors contributed to us in connection with the IPO. When used for time periods on or subsequent to June 24, 2015, such terms refer to 8point3 Energy Partners LP together with its consolidated subsidiaries, including OpCo.

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

“(ac)” refers to alternating current.

“AMAs” refers to asset management agreements.

“AROs” refers to asset retirement obligations.

“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.

“C&I Holdings” refers to SunPower Commercial Holding Company I, LLC, an indirect subsidiary of OpCo and the holder of the C&I Project Entities.

“C&I Project Entities” refers to the Macy’s Project Entities and the UC Davis Project Entity.

“CAISO” refers to the California Independent System Operator.

“COD” refers to the commercial operation date.

“(dc)” refers to direct current.

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

“EPC” refers to engineering, procurement and construction.

“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 excludes us, the General Partner, Holdings and our subsidiaries, including OpCo.

“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 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.

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

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

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

“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 by Holdings.

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

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

“IID” refers to the Imperial Irrigation District, a California public utility.

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

“IRS” refers to the Internal Revenue Service.

“ITCs” refers to investment tax credits.

“kV” refers to a kilovolt, or 1,000 volts.

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

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

“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.

“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 Transition 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.

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“NOLs” refers to net operating losses.

“North Star Holdings” refers to NS Solar Holdings, LLC.

“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.

“OECD” refers to the Organization for Economic Co-operation and Development, the membership of which consists of: Australia, Austria, Belgium, Canada, Chile, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Israel, Italy, Japan, Luxembourg, Mexico, Netherlands, New Zealand, Norway, Poland, Portugal, Slovak Republic, Slovenia, South Korea, Spain, Sweden, Switzerland, Turkey, United Kingdom and United States.

“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 Omnibus Agreement, dated as of June 24, 2015, as amended, among the Partnership, OpCo, the General Partner, Holdings, First Solar and SunPower.

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

“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.

“Partnership Agreement” refers to our partnership agreement.

“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, which consists of the Lost Hills Blackwell Project, the Macy’s Project, the Maryland Solar Project, the North Star Project, the Quinto Project, the Solar Gen 2 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 SunPower Project Entities prior to the completion of the IPO.

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

“Prospectus” refers to the Partnership’s prospectus dated June 18, 2015 and filed with the SEC pursuant to Rule 424(b) under the Securities Act on June 19, 2015.

“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.

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

“RECs” refers to renewable energy certificates.

“Residential Portfolio” refers to the approximately 5,900 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 39 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, collectively, our portfolio of ROFO Projects.

“ROFO Projects” refers to, collectively, the First Solar ROFO Projects and 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” refers to Riverside Public Utilities.

“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.

“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.

“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.

“SP Holding Companies” refers, collectively, to Quinto Holdings, RPU Holdings and C&I Holdings.

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

“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 excludes 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.

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“SunPower Project Entities” refers to the Macy’s 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.

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

“SunPower ROFO Projects” refers to, collectively, the projects set forth in the chart in Part I, Item 1, under the heading “Business—Our Portfolio—ROFO Projects” with SunPower listed as the Developing Sponsor and 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.

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

“Utility Project Entities” refers to 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 and the Solar Gen 2 Project Entity.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Transition 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, 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 Transition Report on Form 10-K include 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.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement, including industry data referenced elsewhere in this Transition Report on Form 10-K. 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 Transition Report on Form 10-K. Actual results may vary materially. 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:

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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 8point3 General Partner, LLC, a wholly-owned subsidiary of 8point3 Holding Company, LLC, a joint venture between First Solar and SunPower. A registration statement on Form S-1, as amended through the time of its effectiveness, was filed by the Partnership with the U.S. Securities and Exchange Commission (“SEC”) and was declared effective on June 18, 2015. On June 19, 2015, Class A shares representing limited partner interests in 8point3 Energy Partners LP began trading on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “CAFD”. On June 24, 2015, the Partnership completed its initial public offering (the “IPO”) of 20,000,000 Class A shares.

As of November 30, 2015, we owned a 28.2% limited liability interest in OpCo as well as a controlling non-economic managing member interest in OpCo and the Sponsors collectively own 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 71.8% limited liability company interest in OpCo.

We are a growth-oriented limited partnership formed to own, operate and acquire solar energy generation projects. Upon the completion of our IPO on June 24, 2015, our Portfolio, which we acquired from our Sponsors, consists of interests in 432 MW of solar energy projects.

As of November 30, 2015, we owned interests in six utility-scale solar energy projects, two commercial and industrial (“C&I”) solar energy projects, and a portfolio of approximately 5,900 residential solar installations, all of which are operational. Each utility-scale and C&I project in our Portfolio sells all of 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 IV, Item 15. “Exhibits, Financial Statement Schedules—Notes to Consolidated Financial Statements—Note 17. Segment Information.”

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The following diagram depicts our simplified organizational and ownership structure as of January 27, 2016.

 

 

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Our Business Strategies

Our primary objective is to generate predictable cash distributions that grow at a sustainable rate. We intend to achieve this objective through the following strategies:

Own and operate long-term contracted solar generation assets

We believe that contracted solar energy projects generate predictable cash flows. Solar power is generally sold under long-term offtake agreements that require the purchaser to acquire all of the power that is produced by the solar energy project. The principal factor affecting the amount of power produced is the level of sunlight reaching the project, which is largely predictable over the long term. Solar energy systems generate most of their electricity during the time of peak demand, when energy from the sun is strongest. In addition, solar energy projects contain limited operational and technology risks given their modular nature and minimum number of moving parts, which results in relatively low, stable and predictable operations and maintenance (“O&M”) expenses. We intend to continue to own and operate long-term contracted solar energy systems as we grow our business and project portfolio over time.

Acquire assets in our target markets

We intend to pursue strategic opportunities to grow our company through acquisitions, primarily from our Sponsors, of long-term contracted solar energy projects that have commenced, or are close to commencing, commercial operations and that have characteristics similar to our Portfolio, including reliable technology with relatively stable cash flows. Under the ROFO Agreements with our Sponsors, our Sponsors are required for a period of five years from the closing of the IPO to offer us the opportunity to purchase their interests in certain solar energy projects should they seek to sell such interests to a third party. As of November 30, 2015, the weighted average remaining life of the offtake agreements for the currently contracted projects in our ROFO Portfolio is over 20 years. In addition to making acquisitions from the ROFO Portfolio, we seek to acquire solar assets with similar long-term contracted cash flow profiles primarily from our Sponsors and in some cases from other third-party developers and owners of solar energy systems.

On January 26, 2016, OpCo entered into a Purchase, Sale and Contribution Agreement (the “Purchase Agreement”) with SunPower, pursuant to which OpCo agreed to purchase a 20.23 MWac photovoltaic solar generating project located in Kern County, CA and which consists or will consist of solar generation systems attached to fixed-tilt carports located at 27 school sites in the Kern High School District (the “Kern Project”).  The Kern Project will be effectuated in three phases, with the closing of the first phase occurring simultaneously with the execution of the Purchase Agreement. The closings of the second and third phases are expected to occur in the fiscal quarter ending August 31, 2016 and in the fiscal quarter ending November 30, 2016, respectively.  

The aggregate purchase price for the acquisition is $35.0 million in cash, of which approximately $4.9 million was paid on January 27, 2016, in connection with the closing of the first phase. OpCo expects to fund 100% of the purchase price for the Kern Project with cash on hand.

Capitalize on our Sponsors’ leading solar O&M services

We benefit from our Sponsors’ vertically integrated business models across the solar value chain. We believe these business models enable our Sponsors to more effectively operate and maintain solar energy projects. For example, First Solar and SunPower have each consistently maintained utility-scale solar energy system availability above 99.5%. Through various O&M agreements, each Sponsor, subject to oversight by the board of directors of our general partner, will continue to manage and operate all but one of the contributed projects in our Portfolio, providing continuity and quality assurance of the O&M services.

Expand into new strategic markets

We intend to capitalize on opportunities to expand into new markets over time. Our ROFO Portfolio contains utility-scale solar energy projects located in the United States, Chile and Japan, and we will consider expanding our portfolio to include new assets in target markets primarily within additional OECD member countries, including Australia, Canada, France, Germany, Mexico and the United Kingdom. Our criteria for entering into new markets includes an assessment of the market’s macroeconomic environment, project level economics, demand for solar energy and regulatory policy and legal framework for the solar industry.

Maintain financial flexibility

As of November 30, 2015, we had a $300 million term loan outstanding, an undrawn $25.0 million delayed draw term loan facility available, and $151.2 million available under our revolving credit facility. The delayed draw term loan facility is available to us during the 12-month period following the closing of our IPO. Subject to certain conditions, the credit facility includes conditional

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borrowing capacity for incremental commitments to increase the term loan facility and revolving credit facility by $250.0 million, with any increase in the revolving facility not to exceed $100.0 million. Our ability to borrow under our delayed draw term loan facility and revolving credit facility should provide us with the financial flexibility to pursue acquisition opportunities.

Our Portfolio

The following table provides an overview of the assets that comprise our portfolio (the “Portfolio”), all of which have reached commercial operation:

 

 

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 Investment Tax Credits (“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

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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 and the North Star Project, a modified flip partnership structure was utilized that distributes available cash on the basis of 51% to the tax equity investor and 49% to OpCo.

The flip partnership structures employed on the Quinto Project, the RPU Project, the UC Davis Project and the Macy’s 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 generally 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 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. Upon expiration of this lease, we will directly benefit from the operating results of the Maryland Solar Project.

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ROFO Projects

Our Sponsors have 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 during the term of such agreements. Our ROFO Agreements include assets similar to the projects in our Portfolio and represent interests in 1,143 MW capacity, or more than 2.6 times our Portfolio. The following table provides a brief description of the ROFO Projects:

 

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Our Portfolio

The following is a description of the assets that comprise our Portfolio.

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.

Energy Sale Arrangements.    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 to certain adjustments as described in more detail in the project descriptions below. 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:

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).

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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 Agreements and AMAs.    Our Utility Project Entities and certain other subsidiaries have entered into O&M agreements and asset management agreements (“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.”

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

Lost Hills Blackwell

Overview.    The Lost Hills Project Entity and the Blackwell Project Entity, respectively, own the 20 MW Lost Hills Project and the 12 MW Blackwell Project, which are located on adjoining sites in Kern County, California. Commercial operation of the Lost Hills Blackwell Project occurred in April 2015. Through FSAM Lost Hills Blackwell Holdings, LLC, we own 100% of the class B membership interests in Lost Hills Blackwell Holdings, LLC (“Lost Hills Blackwell Holdings”), the indirect 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 eleven 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 the class A member 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.

Power Purchase Agreement.    Each of the Lost Hills Project Entity and the Blackwell Project Entity currently sell 100% of the output of the Lost Hills Project and the Blackwell Project, respectively, to the City of Roseville until December 31, 2018 pursuant to separate power purchase agreements (collectively, the “Roseville PPAs”). As of January 1, 2019, 1% of the output of the Lost Hills Project and the Blackwell Project will continue to be sold to the City of Roseville for a term expected to last approximately seven years. The Roseville PPAs have a stated contract price. Beginning January 1, 2019, the Lost Hills Project Entity and the Blackwell Project Entity are expected to sell the remaining output of the Lost Hills Project and the Blackwell Project, respectively, to PG&E, under separate 25-year power purchase agreements (together, the “PG&E PPAs”). The PG&E PPAs have a stated contract price, which will be adjusted pursuant to time-of-delivery factors.

Engineering, Procurement and Construction Agreement.    The Lost Hills Blackwell Project was designed, engineered, constructed and commissioned pursuant to a single EPC agreement between McCarthy Building Companies, Inc., the Lost Hills Project Entity and the Blackwell Project Entity. The Lost Hills Blackwell Project utilizes 43 MW (dc) of First Solar thin-film solar modules.

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Operations & Maintenance.    The Lost Hills Project Entity and the Blackwell Project Entity have entered into separate O&M agreements with First Solar Electric (California), Inc., a wholly-owned indirect subsidiary of First Solar (“FSEC”), under which FSEC operates and maintains the Lost Hills Project and the Blackwell Project, respectively, and provides a guarantee of each plant’s availability. The O&M agreements have a 10-year term, which the parties may mutually agree to extend for up to two additional five-year renewal periods.

Transmission Interconnection Agreements.    The Lost Hills Project interconnects to PG&E’s 70kV transmission network, while the Blackwell Project interconnects to PG&E’s 12kV distribution system, respectively, pursuant to separate interconnection agreements entered into in March 2011 between each of the Lost Hills Project Entity and the Blackwell Project Entity, PG&E and, solely with respect to the agreement for the Lost Hills Project, the California Independent System Operator (“CAISO”). Each interconnection agreement has an initial term of 25 years and will be subject to automatic renewals for successive one-year periods thereafter.

Real Estate.    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, including an operations and maintenance facility jointly used by both of the Lost Hills Project and the Blackwell Project. The initial term of both leases commenced on July 17, 2014, and each lease runs for a term of 30 years with an option to renew for an additional 10 years at the discretion of the Lost Hills Project Entity and the Blackwell Project Entity. 

Maryland Solar

Overview.    The Maryland Solar Project Entity owns the 20 MW Maryland Solar Project. The Maryland Solar Project has been operational since February 2014. The Maryland Solar Project is subject to a lease between the Maryland Solar Project Entity and Maryland Solar Holdings, Inc., an affiliate of First Solar, that runs until December 31, 2019. The lease requires fixed rent payments and does not feature any purchase option exercisable by the lessee.

Power Purchase Agreement.    The Maryland Solar Project Entity sells 100% of the output of the Maryland Solar Project to FirstEnergy Solutions Corp. pursuant to a power purchase agreement (the “Maryland Solar PPA”), effective until March 31, 2033. The Maryland Solar PPA has a stated contract price, which remains fixed throughout the term, for the Maryland Solar Project. The price paid for output in excess of the expected output may vary over time.

Engineering, Procurement and Construction Agreement.    The Maryland Solar Project was designed, engineered, constructed and commissioned pursuant to an EPC agreement between the Maryland Solar Project Entity and Belectric, Inc. (“Belectric”). The Maryland Solar Project utilizes 29 MW (dc) of First Solar thin-film solar modules.

Operations & Maintenance.    The Maryland Solar Project Entity has an O&M agreement with Belectric, under which Belectric operates and maintains the Maryland Solar Project and provides a guarantee of plant availability. The O&M agreement has a 10-year term that is extended automatically for an additional five years unless a Belectric event of default has occurred. Under the O&M agreement, Belectric’s fee escalates 2% per year, and if the term is extended for the additional five years, there is a one-time 4% adjustment to the fee and then the fee is subject to a 2% escalation thereafter.

Interconnection Service Agreements.    In February 2012, the Maryland Solar Project Entity entered into an interconnection service agreement with PJM Interconnection L.L.C., and the Potomac Edison Company (“Potomac Edison”), that provides for the Maryland Solar Project’s interconnection to Potomac Edison’s distribution system.

Real Estate.    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.

North Star

Overview.    The North Star Project Entity owns the 60 MW North Star Project. The North Star Project achieved commercial operation in June 2015. Through FSAM NS Holdings, LLC we own 100% of the class B membership interests in NS Solar Holdings, LLC (“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 eleven years, the allocation of tax-related items between

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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.

Power Purchase Agreement.    The North Star Project Entity sells 100% of its output to PG&E under a 20-year power purchase agreement (the “North Star PPA”). The North Star PPA has a stated contract price, which escalates each year of the term and is adjusted by time of delivery factors.

Engineering, Procurement and Construction Agreement.    The North Star Project was designed, engineered, constructed and commissioned pursuant to an EPC agreement (the “North Star EPC Contract”) entered into between the North Star Project Entity and FSEC. The North Star Project utilizes 73 MW (dc) of First Solar thin-film solar modules.

Operations & Maintenance.    The North Star Project Entity has entered into a 10-year O&M agreement with FSEC, pursuant to which FSEC operates and maintains the North Star Project and provides a guarantee of plant availability. The O&M agreement has a 10-year term, which the parties may mutually agree to extend for up to two additional five-year renewal periods.

Transmission Interconnection Agreements.    In July 2013, the North Star Project Entity entered into an interconnection agreement with PG&E and CAISO, which provides for the North Star Project Entity’s interconnection to PG&E’s transmission grid. The interconnection agreement has an initial term of 30 years and is automatically renewed for successive one-year periods thereafter unless terminated by either party.

Real Estate.    The North Star Project consists of a leasehold interest governed by a single lease that runs for an initial term of 30 years from July 17, 2014 to July 16, 2044, with an option to renew the lease term for an additional 10 years at the discretion of the North Star Project Entity.

Quinto Project

Overview.    The Quinto Project is comprised of a 108 MW solar generation facility located in Merced County, California, which commenced operations in November 2015. The Quinto Project is situated on an approximately 949 acre site leased by the Quinto Project Entity. The Quinto Project site consists of two non-contiguous areas, Quinto Farms and Stockton Terminal, that have been developed with solar facilities. A half-mile utility connection for medium voltage transmission connects Quinto Farms with Stockton Terminal. The Quinto Project is interconnected to the transmission grid controlled by CAISO via a 230 kV Quinto Project substation located on the Quinto Project site, and a new PG&E switchyard on an approximately 10-acre PG&E-owned parcel located adjacent to the Quinto Project substation.

Through SSCA XIII Managing Member, LLC, we own 100% of the class B membership interests in SSCA XIII Holding Company, LLC (“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 an affiliate of SunPower.  Distributions of cash flows from the Quinto Project are subject to a waterfall. Until the fifth anniversary of the date that the class A members fund their second capital contribution (“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 $3,278,000. 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. In addition, 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.

Quinto Holdings and the Quinto Project are managed by SunPower Capital, who was appointed by the members at the execution of the operating agreement of Quinto Holdings. The manager may be replaced in 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.

Power Purchase Agreement.    All of the Quinto Project’s output and related renewable attributes are sold to Southern California Edison pursuant to a power purchase agreement (the “Quinto PPA”), that expires 20 years from COD. The Quinto PPA has an effective date of January 7, 2011. The California Public Utilities Commission approved the Quinto PPA in January 2012.

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Engineering, Procurement and Construction Agreement.    The Quinto Project was designed, engineered, constructed and commissioned pursuant to a lump sum turn-key EPC agreement with SunPower Corporation, Systems, a wholly owned subsidiary of SunPower (“SunPower Systems”), which includes a two-year system warranty against defects in materials, construction, fabrication and workmanship. The Quinto Project utilizes differentiated 435-watt modules with 20.4% module conversion efficiency. In addition to the system warranty, the modules are backed by SunPower’s 25-year module warranty.

Operations & Maintenance.    SunPower Systems operates the Quinto Project under a five-year operation and maintenance agreement, which may, at the election of the Quinto Project, be extended for up to three additional five-year terms, provided that the terms (including service fees) of any such extension will be subject to mutual agreement by SunPower Systems and the Quinto Project Entity. SunPower Systems’ service commitment is supported by a performance warranty agreement that guarantees the weather adjusted output of the Quinto Project will be at least 95% of the benchmark annual energy output during each two year period during the term of the Quinto O&M agreement.

Transmission Interconnection Agreements.    In March 2013, as amended in October 2013 and December 2014, the Quinto Project Entity entered into a Large Generator Interconnection Agreement with PG&E and CAISO. This agreement has an initial 30-year term, with automatic one-year extensions thereafter. The Quinto Project Entity has also entered into an affected system agreement to support associated network upgrades on “Affected Systems.”

Real Estate.    The Quinto Project is located on leased property pursuant to a single 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.

Asset Management Agreements.    SunPower Capital Services, LLC, a wholly owned subsidiary of SunPower (“SunPower Capital”), manages the Quinto Project, which includes offtake billing, collection, administration and project management.

Solar Gen 2

Overview.    The Solar Gen 2 Project Entity owns the 150 MW Solar Gen 2 Project. The Solar Gen 2 Project achieved commercial operation in November 2014. Through FSAM SG2 Holdings, LLC, we own 100% of the class B interests in SG2 Holdings, LLC (“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 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 eleven 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.

Power Purchase Agreement.    The Solar Gen 2 Project Entity sells 100% of the output from the Solar Gen 2 Project to San Diego Gas & Electric Company (“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 Locational Marginal Price (“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.

Engineering, Procurement and Construction Agreement.    The Solar Gen 2 Project was designed, engineered, constructed and commissioned pursuant to an EPC agreement between the Solar Gen 2 Project Entity and FSEC. The Solar Gen 2 Project utilizes 154 MW (dc) of First Solar thin-film solar modules. In addition, approximately 39 MW (dc) of solar modules manufactured by Canadian Solar Inc. are distributed evenly among the Solar Gen 2 Project.

Operations & Maintenance.    The Solar Gen 2 Project Entity entered into a 10-year O&M agreement with FSEC, pursuant to which FSEC operates and maintains the Solar Gen 2 Project and provides a guarantee of plant availability. The O&M agreement has a 10-year term, which the parties may mutually agree to extend for up to two additional five-year renewal periods.

Transmission Interconnection Agreements.    The Solar Gen 2 Project Entity is a party to three interconnection agreements with the Imperial Irrigation District (“IID”) for the Solar Gen 2 Project, pursuant to which the Solar Gen 2 Project interconnects with IID’s

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transmission system. Two of the interconnection agreements became effective on April 3, 2012 and the third interconnection agreement took effect on August 9, 2011. Each interconnection agreement has an initial term of 27 years and will be subject to automatic renewals for successive one-year periods thereafter.

Real Estate.    The Solar Gen 2 Project consists of a leasehold interest governed by a single ground lease that runs for an initial term of 30 years from August 29, 2013, with an option to renew the lease term for an additional 10 years at the discretion of the Solar Gen 2 Entity. 

RPU Project

Overview.    The RPU Project is comprised of an approximately 7 MW solar generation facility located in Riverside County, California, which commenced operations in September 2015. The RPU Project is situated on a portion of a 120-acre site licensed by the City of Riverside to the RPU Project Entity. The RPU Project interconnects at facilities built by the City of Riverside that access the closest feeder to the City’s distribution network.  

Through SSCA XXXI Managing Member, LLC, we own 100% of the class B membership interests in SSCA XXXI Holding Company, LLC (“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, who are tax motivated project equity investors, and the class C membership interests in RPU Holdings are held by an affiliate of SunPower.  Distributions of cash flows from the RPU Project are subject to a waterfall.  Until the fifth anniversary of the date that the class A members fund their second capital contribution (“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 $271,000.  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. In addition, 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.  

RPU Holdings and the RPU Project are managed by SunPower Capital, who was appointed by the members at the execution of the operating agreement of RPU Holdings. The manager may be replaced in 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.

Power Purchase Agreement.    All energy and green attributes are sold to the City of Riverside pursuant to a 25-year power purchase agreement (the “RPU PPA”). The RPU PPA grants the RPU Project Entity an irrevocable license which allows access to and use of the site for the construction maintenance and operation of the system.

Engineering, Procurement and Construction Agreement.    The RPU Project was designed, engineered, constructed and commissioned pursuant to an EPC agreement with SunPower Systems, which includes a two-year system warranty against defects in materials, construction, fabrication and workmanship. The facility utilizes differentiated 435-watt modules with 20.7% module conversion efficiency and 410-watt modules with 19.0% module conversion efficiency. In addition to the system warranty, the RPU Project is backed by SunPower’s 25-year power and product warranty on the modules.

Operations & Maintenance.    SunPower Systems, an affiliate of the RPU Project Entity, maintains the RPU Project, including performing system monitoring and preventative and corrective maintenance. The term is five years and will be automatically extended for one additional five-year period, unless the RPU Project Entity provides six-months notice that it does not extend the term.

Transmission Interconnection Agreements.    The RPU Project interconnects to a 15 kV switchgear to be built by RPU and that accesses RPU’s distribution network. RPU owns and operates its own electrical distribution network, and is responsible for engineering and constructing the electrical facilities from the 15 kV switchgear to the distribution grid. There is no stand-alone interconnection agreement signed for this project. Instead, the project complies with provisions in RPU’s standards for connecting generation facilities to its distribution system (RPU’s Electric Rule 22) as required under the RPU PPA. In addition, the project relies upon RPU’s Metered Subsystem Agreement with the CAISO and its Wholesale Distribution Access Tariff service agreement with Southern California Edison.

Real Estate Interests.    The PPA grants the RPU Project Entity an irrevocable license pursuant to which the RPU Project Entity is permitted to access, construct, maintain and operate the RPU Project.

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Asset Management Agreements.    SunPower Capital, an affiliate of the RPU Project Entity, manages the RPU Project, including providing offtake billing, collection, administration, and project management services. The one-year term began on commercial operation and will be automatically extended (unless terminated in accordance therewith) for an indefinite term.

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.

Energy Sale Arrangements.    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, subject to certain adjustments as described in more detail 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:

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 engineering, procurement and construction 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 2- to 10-year warranty on the system.

O&M and Asset Management.    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 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

Macy’s Project

Overview.    The Macy’s Project is comprised of seven solar generation facilities with a total of approximately 3 MW located in Sacramento, Santa Clara, Santa Cruz, Alameda, and San Francisco Counties, California, which commenced operations in October 2015. The Macy’s 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 Project Entities. The facilities are interconnected to Macy’s main electrical module at 480 V. PG&E or Sacramento Municipal Utility District (“SMUD”), depending on site location, have separately entered into a “net-metering” Interconnection Agreements with Macy’s. The Downtown Sacramento site is not allowed to net meter due to local utility requirements.

Through SunPower Commercial Managing Member, LLC, we own 100% of the class B membership interests in SunPower Commercial Holding Company I, LLC (“C&I Holdings”), the owner of 100% of the limited liability company membership interests of the Macy’s 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 an affiliate of SunPower.  Distributions of cash flows from the Macy’s Project are subject to a waterfall. Until the date (the “C&I’s Flip Date”) 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 the fifth anniversary of the date the last project owned by C&I Holdings is placed in service for U.S. federal income tax purposes, 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 $375,000 a year. After the occurrence of the C&I Flip Date, 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 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 C&I Holdings.  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 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 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.

Power Purchase Agreement.    All energy is sold to Macy’s pursuant to seven site-specific 20-year power purchase agreements (the “Macy’s PPAs”). Green attributes are retained by the Macy’s Project Entities.

Engineering, Procurement and Construction Agreement.    The Macy’s Project was designed, engineered, constructed, and commissioned pursuant to an EPC agreement with SunPower Systems, which includes a ten-year system warranty against defects in materials, construction, fabrication and workmanship. The facility utilizes differentiated 327-watt modules with 20.4% module conversion efficiency. In addition to the system warranty, the Macy’s Project is backed by SunPower’s 25-year power warranty on the modules.

Operations & Maintenance.    SunPower Systems, an affiliate of the Macy’s Project Entities, maintains the Macy’s Project, including performing system monitoring and preventative and corrective maintenance. The term is ten years.

Transmission Interconnection Agreements.    Macy’s or its affiliate and PG&E entered into four Interconnection Agreements, one for each site within PG&E territory, which provided for the generating facilities to operate in parallel with PG&E’s distribution system. Under these four agreements, Macy’s or its affiliate was responsible for all reasonable expenses associated with the generating facilities. Each of these agreements has an indefinite term, until terminated in accordance with the agreement. These agreements were countersigned by PG&E upon successful interconnection of the systems. The other three sites, which are located in the SMUD territory, received Permission to Operate confirmation.

Real Estate Interests.    The Macy’s Project Entities have entered into site lease agreements with Macy’s for each project rooftop site, which are coterminous with the Macy’s PPAs and permit the Macy’s Project Entities to access, construct and operate the project.

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Asset Management Agreements.    SunPower Capital, an affiliate of the Macy’s Project Entities, manages the Macy’s Project, including providing offtake billing, collection, administration, and project management services. The one-year term began on commercial operation and will be automatically extended (unless terminated in accordance therewith) for an indefinite term.

UC Davis Project

Overview.    The UC Davis Project is comprised of a 13 MW solar generation facility located in Solano County, California, which commenced operations 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”) to the UC Davis Project Entity. The facility is interconnected to an existing UC Davis substation at 12 kV and supplements on-site load at the campus. 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 Project, which are set forth above.

Power Purchase Agreement.    All energy and green attributes are sold to the University pursuant to a 20-year power purchase agreement (the “UC Davis PPA”).

Engineering, Procurement and Construction Agreement.    The UC Davis Project was designed, engineered, constructed, and commissioned pursuant to an EPC agreement with SunPower Systems, which includes a five-year system warranty against defects in materials, construction, fabrication and workmanship. The facility utilizes differentiated 435-watt modules with 20.1% module conversion efficiency. In addition to the system warranty, the UC Davis Project is backed by SunPower’s 25-year power warranty on the modules.

Operations & Maintenance.    SunPower Systems, an affiliate of the UC Davis Project Entity, maintains the UC Davis Project, including performing system monitoring and preventative and corrective maintenance. The term is ten years.

 

Transmission Interconnection Agreements.    The University entered into an Electric Rule 21 Interconnection Agreement for Non-Exporting Generating Facilities with PG&E, pursuant to which PG&E required the installation of reverse power relays to prevent the system from exporting power to PG&E’s distribution grid during light load conditions. Under the terms of the UC Davis PPA, the University is obligated to pay for any energy that would have been generated during an outage or curtailment that was caused by the University or required by PG&E.

 

Real Estate Interests.    The UC Davis Project Entity has entered into a ground lease agreement with the University, which is coterminous with the UC Davis PPA and which permits the UC Davis Project Entity to access, construct and operate the project.

 

Asset Management Agreements.    SunPower Capital, an affiliate of the UC Davis Project Entity, manages the UC Davis Project, including providing offtake billing, collection, administration, and project management services. The one-year term began on commercial operation and will be automatically extended (unless terminated in accordance therewith) for an indefinite term.

Residential Portfolio

Overview.    Our residential lease program allows customers in the United States to obtain SunPower residential solar energy systems under lease agreements with an initial term of 20 years. Our Residential Portfolio is comprised of residential solar energy systems with an aggregate of 39 MW of capacity and an average solar energy system capacity of approximately 7.95 kW. Our Residential Portfolio is comprised of approximately 5,900 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 energy 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.

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Engineering and Installation.    The primary means by which SunPower goes to market in the residential solar sector is through an independent dealer channel. These qualified dealers partner with SunPower to provide subcontracted sales, installation, and maintenance services for lease customers.

Operations & Maintenance.    SunPower Systems, an affiliate of the Residential Portfolio Project Entity, 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 10 gigawatts (“GW”) installed worldwide. First Solar’s integrated power plant solutions deliver an economically 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. As of September 30, 2015, First Solar had total assets of $7.1 billion.

SunPower (NASDAQ: SPWR) 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 North and South America, Europe, Australia, Africa and Asia. As of September 27, 2015, SunPower had total assets of $4.4 billion. SunPower is majority owned by Total S.A., the fifth largest publicly-listed energy company in the world.

Seasonality

The amount of electricity our solar energy 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 reserved 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. These include our Sponsors and growth vehicles similar to us that seek to acquire energy projects from our Sponsors or third parties. 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 energy 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.

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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.

Clean Water Act.    Our projects may be covered under federal Clean Water Act 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 U.S. Environmental Protection Agency (the “EPA”) published its final rule, making changes to its 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. We are currently assessing the potential impact of the EPA’s final rule on our operations, as any expansion to Clean Water Act jurisdiction could impose additional obligations on our operations.

BLM Right-of-Way Grants.    Our projects may be located, or partially located, on lands administered by the U.S. Bureau of Land Management (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 in implementing our growth strategy 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, which establishes standards to limit carbon dioxide emissions from existing power generation facilities by 30% from 2005 levels by 2030. If, in implementing the Clean Power Plan or any future 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, growth strategy, 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.

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Safety and Maintenance

We are subject to the requirements of the Occupational Safety and Health Act (“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 U.S. Federal Energy Regulatory Commission (“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 U.S. Federal Power Act (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:

Public Utility Holding Company Act of 2005

The Public Utility Holding Company Act of 2005 (“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 favorable net

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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:

Key state and local programs and incentives include:

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 Management Services Agreements and the 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 and transition 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 Securities Exchange Act of 1934, as amended (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, and public conference calls and webcasts.  The information contained in or connected to our website is not incorporated by reference into this report.

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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.

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 Business

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:

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:

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.

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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. Four of our utility projects and our two C&I projects just attained COD in fiscal 2015 and the other two of our utility projects attained COD in fiscal 2014.  In addition, approximately 85% of our Residential Portfolio attained COD within the last two years and all of our Residential Portfolio attained COD within the last four years. We expect that many of the projects that we may acquire, including the First Solar ROFO Projects and SunPower ROFO Projects, will either not have commenced operations, have recently commenced operations or otherwise have a limited operating history at the time of acquisition. 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:

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 their respective credit facilities 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.

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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 projects, such as the Quinto Project or the Solar Gen 2 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.

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

Of the 432 MW in our Portfolio, a total of 396 MW is located in California, including approximately 95% of the MW of our utility projects and 72% of the MW of our DG Solar projects, and we expect much of our near-term future growth to occur in California, 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 laws. Please read “—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.”

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 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.

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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:

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 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 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 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.

Neither we nor our Sponsors control certain of the entities that own our projects and we may acquire future projects that we do not control.

A subsidiary of Southern Company owns a 51% economic interest in, and we own a 49% economic interest in, the Solar Gen 2 Project Entity, the Lost Hills Blackwell Project Entity and the North Star Project Entity. We do not own a majority of ownership of these project entities or control these project entities’ governing boards. As a result, our ability to make distributions to our Class A shareholders depends in large part on the performance of these entities and their distribution of cash to us. Specifically,

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In the case of the Solar Gen 2 Project Entity, the Lost Hills Blackwell Project Entity and the North Star 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 51% to a subsidiary of Southern Company and 49% to OpCo.

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.

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”.

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. 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.

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

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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.

We 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 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 Macy’s 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.

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 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 may be subject to information technology system failures or network disruptions that could damage our business operations, financial conditions, or reputation.

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.

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Risks Related to Our Acquisition Strategy and Future Growth

We may not be successful in implementing our growth strategy of making 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 consistent with our business strategy. 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 below:

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.

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 our ROFO Agreements with our Sponsors provide us with a right of first offer for five years with respect to certain projects that our Sponsors are developing should they choose to sell such projects, there is no guarantee that the Sponsors will make available to us any projects before our right of first offer expires or at all. 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 growth vehicles similar to us or be unable to obtain necessary governmental or third-party consent. 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. 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 our ROFO Agreements, our Sponsors 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 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. In addition, the Sponsors may sell a portion of the equity in non-U.S. projects to development partners.

Our Sponsors’ failure to complete the development of the First Solar ROFO Projects and 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.

Our Sponsors could decide not to develop or to discontinue development of the First Solar ROFO Projects and 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:

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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.

If solar energy technology is not suitable for widespread adoption at economically attractive rates of return, or if sufficient additional demand for solar energy 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 energy 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 energy 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 energy systems, including the following:

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.

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 or a significant increase in interest rates could make it difficult for development companies to raise 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.

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 projects), siting, land use and other arrangements with a variety of third parties. Failure to execute project contracts would limit the ability of a project developer to complete development of a project, which would limit the projects available to us to acquire.

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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.

Our Residential Portfolio relies on net metering and related policies to offer competitive pricing to our customers in some of our key markets.

More than 40 U.S. states, along with Washington, D.C. and Puerto Rico, have a regulatory policy known as net energy metering, or net metering. Most of the states where we currently serve customers has 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 operating in states without 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.

Our Residential Portfolio 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 existing limits on the amount of net metering in states that have implemented it, the imposition of new charges that only or disproportionately impact customers that utilize net metering, or reductions in the amount or value of credit that customers receive through net metering. In addition, our Residential Portfolio may be adversely impacted by the unavailability of expedited or simplified interconnection for grid-tied solar energy systems 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. For example, utilities in some states have proposed imposing additional monthly charges on customers who interconnect solar energy systems installed on their homes. If such charges are imposed, the cost savings associated with switching to solar energy 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 energy systems and other operational policies in key markets could limit the number of solar energy systems installed in those markets. If caps on net metering are reached or if the amount or value of credit that customers receive for net metering is significantly reduced, future customers will be unable to recognize the current cost savings associated with net metering. Net metering is used to establish competitive pricing for prospective customers and the absence of net metering for new customers would greatly limit demand for residential solar energy systems.

Government regulations providing incentives and subsidies for solar energy could change at any time and such changes may negatively impact our growth strategy.

Our strategy to grow our business through the acquisition of 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. 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 could decrease the attractiveness of solar energy projects to project developers, including our Sponsors, and the attractiveness of solar energy 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 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, 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.  A solar project that commences construction during 2021 and is placed in service prior to January 1, 2024, may qualify

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for an ITC equal to 22% of eligible basis.  A solar project that commences construction during 2022 or thereafter or is placed in service on or after to January 1, 2024, may qualify for an ITC equal to 10% 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 that benefit our projects, they could generate reduced revenues and reduced economic returns, experience increased financing costs and encounter difficulty obtaining financing.

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 one of the most aggressive RPS in the United States, is poised to meet its current target of 25% renewable energy generation by 2016 and has the potential to meet its goal of 33% renewable power generation by 2020 with already-proposed new renewable energy projects. 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.

The seasonality of our operations may affect our liquidity.

The amount of electricity our solar energy 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. We expect our Portfolio’s power generation to be at its lowest during the winter season of each year. Similarly, 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.

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 projects.

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

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 energy 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 energy system offerings less competitive and reduce demand for such solar energy systems. 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 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.

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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.

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 the 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 attributes primarily include (i) ITCs, which are federal income tax credits equal to (a) 30% multiplied by the cost of eligible assets that commence construction prior to January 1, 2020; (b) 26% multiplied by the cost of eligible assets that commence construction during 2020; (c) 22% multiplied by the cost of eligible assets that commence construction during 2021; and (d) 10% multiplied by the cost 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.

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 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.

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

We expect that OpCo will distribute a substantial amount of its available cash to its unitholders, including us, and will rely primarily upon its cash reserves (including the net proceeds retained from our IPO) and external financing sources, including borrowings under our 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. Furthermore, our and its ability to access the capital markets is dependent on,

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among other factors, the overall state of the capital markets and investor appetite for investment in clean energy projects 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 could significantly limit our ability to consummate future acquisitions and effectuate our growth strategy. 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.

To the extent we are unable to finance growth 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, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations.

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 our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our Class A shareholders.

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 energy 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.

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:

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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.

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 and our current growth strategy is only focused on acquiring 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 Regulations

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

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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 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 energy systems.

Although we own the underlying solar energy 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 energy systems qualify for the same levels of rebates or other non-tax incentives available for customer-owned solar energy systems and whether third-party owned solar energy systems are eligible at all for these incentives. Reductions in, eliminations of, or rebates or incentives for these third-party ownership arrangements could reduce demand for our solar energy 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 internal growth or 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, our employees, 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.

Risks Related to Our Project Agreements

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. 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 energy 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 customers was approximately 765 at the time of initial contract. The risk of customer defaults may increase as 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:

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.

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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, 2015, the weighted average remaining life of offtake agreements across our Portfolio was 21.6 years. Our ability to extend, renew or replace our existing offtake agreements depends on a number of factors beyond our control, including:

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 energy system, no earlier than year 6 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 energy 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 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.

Risks Related to Our Financial Activities

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

On June 5, 2015, OpCo entered into a $525 million senior secured credit facility, consisting of a $300 million term loan facility, a $25 million delayed draw term loan facility and a $200 million revolving credit facility. At November 30, 2015, the full amount of

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the term loan facility and approximately $48.8 million of letters of credit under our revolving credit facility are outstanding. The remaining portion of the revolving credit facility and the delayed draw term loan facility are undrawn. In the future, we may significantly increase our debt to fund our operations or future acquisitions. This credit facility contains various covenants and restrictive provisions that limit OpCo’s ability to, among other things:

In addition, OpCo’s debt could have important negative consequences on our financial condition, including:

OpCo’s credit facilities also contain 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 facilities contain events of default customary for transactions of this nature, including the occurrence of a change of control.

The provisions of the credit facilities 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 facilities could result in an event of default, which could enable the lenders to declare, subject to the terms and conditions of the applicable credit facilities, 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

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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.

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 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 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’ 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, financial condition and growth prospects.

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.

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 initial 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 General Partner’s board of directors 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:

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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 First Solar ROFO Agreement and 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

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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 under 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 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.

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The credit and risk profile of the General Partner and its owners, our Sponsors, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

The credit and business risk profiles of the General Partner and our Sponsors may be considered in credit evaluations of us because the General Partner, which is owned by our Sponsors, controls our business activities, including our and OpCo’s cash distribution policy and growth strategy. 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 the 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.

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 of directors. Rather, the board of directors of the General Partner 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:

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In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by the General Partner, the board of directors of the General Partner 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 of directors of the General Partner 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 of directors of the General Partner 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 of directors of the General Partner, 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:

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.

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 of directors and

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officers of the General Partner 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 the growth of our partnership and 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 of the General Partner 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, 2015, the General Partner and its affiliates, including our Sponsors, owned 71.8% 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.

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 of directors of the General Partner, cannot vote on any matter.

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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:

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, 2015, the General Partner and its affiliates own approximately 71.8% of our outstanding shares through their ownership of Class B shares. At the end of the subordination period (which could occur as early as August 31, 2016), assuming no additional issuances of Class A shares by us, the General Partner and its affiliates will own OpCo common units convertible into approximately 71.8% of our outstanding Class A shares and therefore would not be able to exercise the call right at that time.

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 permits 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

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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:

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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.

 

Pursuant to the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for so long as we are an emerging growth company and we may take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards.

For as long as we are an “emerging growth company” under the Jumpstart Our Business Act (the “JOBS Act”), our independent registered public accounting firm will not be required to attest to the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”). We could be an emerging growth company for up to five years. An effective system of internal controls is necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with U.S. GAAP, but our internal accounting controls may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our system of internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. For example, Section 404 will require us, among other things, to annually review and report on the effectiveness of our system of internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending November 30, 2016. Any failure to develop, implement or maintain our effective internal controls, or the failure by the entities that are our equity investees to do so, or the failure by us or them to improve our or their system of internal controls could harm our operating results or cause us to fail to meet our reporting obligations.

As an emerging growth company, we have the option to take advantage of these reporting exemptions until we are no longer an “emerging growth company.” We cannot predict if investors will find our units less attractive because we will rely on these exemptions. If some investors find our units less attractive as a result, there may be a less active trading market for our units and our trading price may be more volatile.

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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 requirements of being a public company may strain our resources, divert management’s attention and affect our ability to attract and retain qualified board members and officers.

As a public company, we are subject to the reporting requirements of the Exchange Act, the listing requirements of the NASDAQ and other applicable securities rules and regulations. Compliance with these rules and regulations will increase our legal and financial compliance costs, make some activities more difficult, time-consuming or costly and increase demand on our systems and resources. The Exchange Act requires, among other things, that we file annual, quarterly and current reports with respect to our business and operating results and maintain effective disclosure controls and procedures and internal control over financial reporting. To maintain and, if required, improve our disclosure controls and procedures and internal control over financial reporting to meet this standard, significant resources and management oversight may be required. As a result, management’s attention may be diverted from other business concerns, which could harm our business and operating results. Although we have already hired additional employees to comply with these requirements, we may need to hire more employees in the future, which will increase our costs and expenses.

We also expect that being a public company will make it more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified executive officers and members of our board of directors, particularly to serve on our audit committee and conflicts committee.

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 General Partner’s board of directors 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

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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.

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 net operating losses (“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 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 Internal Revenue Service (“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.

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.

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,

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

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 interest began trading on the NASDAQ Global Select Market under the symbol “CAFD” on June 19, 2015. Prior to that, there was no public market for our Class A shares representing limited partner interests. The Partnership's Class B shares representing limited partner interests are not publicly traded.

As of January 22, 2016, there were 4 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 high and low sale prices and cash distributions per share of our Class A shares since June 19, 2015, the first day of trading of our Class A shares, through November 30, 2015:

 

 

On October 15, 2015, we distributed $3.1 million on our 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, we distributed $4.3 million on our Class A shares, or $0.217 per share for the period from September 1, 2015 to November 30, 2015. Although our Partnership Agreement requires that we distribute all of our available cash each quarter, we do not have a legal obligation to distribute any particular amount per Class A share.

 

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 all of 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 at 8point3 Partners would be established solely to provide for the payment of income taxes payable by 8point3 Partners, if any. Our cash flow is generated from distributions we receive from OpCo.

Shares Eligible for Distribution

As of November 30, 2015, we had 20,007,281 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 will be entitled to receive distributions (including upon liquidation) on a pro rata basis. Class B shares will not be 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. 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.

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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 distribute its available cash to its unitholders of record on the applicable record date.

Units Eligible for Distribution

As of November 30, 2015, we owned 20,007,281 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:

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, 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 partners, 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 of $0.2097 per unit, or $0.8388 per unit on an annualized basis, to the holders of OpCo’s common units, including us, and OpCo’s subordinated units 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 Management Services Agreements. However, OpCo may not be able to pay the minimum quarterly distribution 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” 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.

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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.

 

 

Subordination Period

The OpCo limited liability company agreement provides that, during the subordination period (as defined 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:

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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 ending August 31, 2016, if each of the following has occurred:

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.

Forbearance Period

Our Sponsors have agreed to forego any distributions declared on their common and subordinated units of OpCo during the forbearance period. The amount of distributions to be foregone by the Sponsors will be $10.7 million per fiscal quarter assuming OpCo distributes the minimum quarterly distribution. The purpose of this forbearance is to reduce the risk that the holders of Class A shares will not receive the full initial quarterly distribution. The “forbearance period” will end in the fiscal quarter commencing on or after March 1, 2016 that the board of directors of our general partner, with the concurrence of the conflicts committee, determines that OpCo will be able to earn and pay at least the minimum quarterly distribution on each of its outstanding common and subordinated units for such quarter and the successive quarter. During the forbearance period, our Sponsors’ common and subordinated units in OpCo will not be treated as outstanding for purposes of calculating whether the subordination period has ended.

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” for information regarding our equity compensation plans as of November 30, 2015.

Issuer Purchases of Equity Securities

We did not repurchase any of our Class A Shares in the year ended November 30, 2015.

Use of Proceeds from Registered Securities

On June 24, 2015, we completed our IPO of 20,000,000 Class A shares at a price to the public of $21.00 per share, for aggregate gross proceeds of $420.0 million. The offer and sale of all of the Class A shares in the IPO were registered under the Securities Act pursuant to a Registration Statement on Form S-1 (File No. 333-202634), which was declared effective by the SEC on June 18, 2015.

Goldman Sachs & Co. and Citigroup Global Markets Inc. served as lead book running managers and as representatives of the several underwriters for the IPO. 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. The expenses of the IPO, not including the underwriting discount and the structuring fee, were approximately $6.1 million and were paid by our Sponsors. In addition, the underwriters reimbursed our Sponsors $2.3 million for certain expenses in connection with our IPO.

We received net proceeds of $393.8 million from the sale of the Class A shares after deducting underwriting fees and structuring fees (but before offering expenses, which were paid by the Sponsors). We used all of the net proceeds from the IPO to purchase 20,000,000 OpCo common units from OpCo. OpCo used (i) approximately $154.4 million of such net proceeds to make a cash distribution to First Solar, (ii) approximately $201.6 million of such net proceeds to make a cash distribution to SunPower and (iii) approximately $37.8 million of such net proceeds for general purposes, including to fund future acquisition opportunities.

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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 Item 15. Exhibits, Financial Statements and Schedules.

 

 

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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 years ended November 30, 2015, December 28, 2014, and December 29, 2013, respectively and the notes thereto included elsewhere in this Transition Report on Form 10-K.

Overview

Description of Partnership

We are a growth-oriented limited partnership formed by First Solar and SunPower to own, operate and acquire solar energy generation projects. Our Portfolio, which we acquired from our Sponsors, consists of interests in 432 MW of solar energy projects.

As of November 30, 2015, we owned interests in six utility-scale solar energy projects, all of which are operational. These assets represent 87% of the generating capacity of our Portfolio. We own interests in two C&I solar energy projects and a portfolio of residential DG Solar assets, which represent 13% of the generating capacity of our Portfolio. Our Portfolio is located entirely in the United States and consists of utility-scale and C&I assets that sell substantially all of their output under long-term, fixed-price offtake agreements with investment grade offtake counterparties and residential DG Solar assets that 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, 2015, the weighted average remaining life of offtake agreements across our Portfolio was 21.6 years.

Initial Public Offering

On June 24, 2015, we completed our IPO by issuing 20,000,000 Class A shares representing limited partner interests in us at a price to the public of $21.00 per share for aggregate gross proceeds of $420.0 million. As of November 30, 2015, we owned a 28.2% limited liability company interest in OpCo as well as a controlling non-economic managing member interest in OpCo and the Sponsors collectively own 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 71.8% limited liability company interest in OpCo.

In connection with the IPO, OpCo entered into a $525.0 million senior secured 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. As of November 30, 2015, the full amount of the term loan facility and approximately $48.8 million of letters of credit under the revolving credit facility were outstanding. The remaining portion of the revolving credit facility and the delayed draw term loan facility are undrawn. Our ability to borrow under the revolving credit facility and the delayed draw term loan facility should provide us with the financial flexibility to pursue acquisition opportunities. As of November 30, 2015, none of our Project Entities had any indebtedness for borrowed money.

We received $393.8 million of net proceeds from the sale of the Class A shares after deducting the underwriting fees and structuring fees (but before offering expenses, which were paid by our Sponsors).

We used all of the net proceeds of the IPO to purchase 20,000,000 OpCo common units from OpCo. OpCo used (i) approximately $154.4 million of such net proceeds to make a cash distribution to First Solar, (ii) approximately $201.6 million of such net proceeds to make a cash distribution to SunPower and (iii) approximately $37.8 million of such net proceeds for general purposes, including to fund future acquisition opportunities.

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Our Portfolio

Our Portfolio refers to, collectively, our portfolio of solar energy projects, which consists of the Lost Hills Blackwell Project, the Macy’s Project, the Maryland Solar Project, the North Star Project, the Quinto Project, the Solar Gen 2 Project, the RPU Project, the UC Davis Project and the Residential Portfolio. The following table provides an overview of the assets that comprise our Portfolio:

 

 

How We Generate Revenues

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 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, 2015, the weighted average remaining life of offtake agreements across our Portfolio was 21.6 years, with the offtake agreements of our Utility Project Entities having remaining terms ranging from 17.3 to 28.1 years and our C&I offtake agreements and residential offtake agreements having remaining terms ranging from 16.8 to 19.9 years.

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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.

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 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 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) benefit, depreciation, amortization and accretion, including our proportionate share of net interest expense, income taxes and depreciation, amortization and accretion from our unconsolidated affiliates that are accounted for under the equity method, and share-based compensation; 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 and transaction costs in our future acquisitions of projects. 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. 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, net cash provided by (used in) operating activities or any other performance or liquidity 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 or net cash provided by (used in) operating activities.

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Cash Available for Distribution.    

Although we have not quantified cash available for distribution on a historical basis, 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 of indebtedness plus cash distributions from unconsolidated affiliates, test electricity generation and cash proceeds from sales-type residential leases. 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 make our minimum quarterly distribution. In addition, cash available for distribution is used by our management team for determining future acquisitions and managing our growth. The U.S. GAAP measures most directly comparable to cash available for distribution are net income and net cash provided by (used in) operating activities.

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, net cash provided by (used in) operating activities or any other performance or liquidity 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 or net cash provided by (used in) operating activities.

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The following table presents a reconciliation of net income to Adjusted EBITDA and Cash Available for Distribution for the eleven months ended November 30, 2015 and the years ended December 28, 2014 and December 29, 2013:

 

 

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Items Affecting the Comparability of Our Financial Results

Our current and future results of operations will not be comparable to our historical results of operations for the reasons described below.

Formation Transactions.    At the closing of our IPO, we acquired the First Solar Project Entities, which were not included in the results of the Predecessor. Our consolidated financial statements include the financial condition and results of operations of the First Solar Project Entities since June 24, 2015, the date we completed our IPO. Results of operations of the Predecessor mainly relate to our Residential Portfolio, which represents less than 10% of the assets in our Portfolio. Prior to the IPO on June 24, 2015, none of the Predecessor’s Utility and C&I Projects had commenced operation and the First Solar Projects, which only recently commenced operations, are not included in the Predecessor’s results of operations.

Selling, General and Administrative Expense.    The Predecessor’s historical combined carve-out financial statements included SG&A expenses that have historically included direct charges for certain overhead and shared services expenses allocated by SunPower. Allocations for SG&A services included such items as information technology, legal, human resources and other financial and administrative services. These expenses were charged or allocated to the Predecessor based on management’s estimate of proportional use. Under the Management Services Agreements, which were amended in August 2015, we pay annual fees of $1.7 million to our Sponsors for general and administrative services. These annual management fees are subject to annual adjustment to reflect the cost to provide SG&A services to us. In addition, our SG&A expenses also include the fees we pay to our Sponsors pursuant to AMAs.

Accounting for Joint Ventures.    The Predecessor’s historical combined carve-out financial statements do not include equity in earnings from any minority-owned joint ventures. As of November 30, 2015, OpCo owned a 49% interest in the Solar Gen 2 Project, the North Star Project and the Lost Hills Blackwell Project; however, as these interests were previously owned by First Solar, they are not included in the Predecessor’s combined carve-out financial statements. The results of operations of joint ventures in which OpCo owns a meaningful noncontrolling interest are not consolidated in our consolidated financial statements and instead are represented as earnings from equity investments.

Financing.    The Predecessor’s historical combined carve-out financial statements reflect 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. On June 5, 2015, OpCo entered into a $525.0 million senior secured 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. As of November 30, 2015, the full amount of the term loan facility and approximately $48.8 million of letters of credit under our revolving credit facility were outstanding. The remaining portion of the revolving credit facility and the delayed draw term loan facility are undrawn. We used the proceeds of the term loan facility to pay distributions to our Sponsors.

Expiration of Section 1603 Cash Grant Program.    The Predecessor’s combined carve-out financial statements reflect the effect of the federal Section 1603 cash grant program. This program has expired and we no longer benefit from these cash grants.

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.

Change in Fiscal Year.    Historically, the Predecessor’s fiscal year was a 52-to-53-week fiscal year that ended on the Sunday closest to December 31. On June 24, 2015, in connection with the closing of our IPO, we amended our Partnership Agreement, which included a change in our fiscal year to a fiscal year ending November 30. Our second quarter of fiscal 2015 included the period from March 30, 2015 to June 28, 2015, our third quarter of fiscal 2015 included the period from June 1, 2015 to August 31, 2015, and our fourth quarter of fiscal 2015 included the period from September 1, 2015 to November 30, 2015 consistent with our November 30 fiscal year end.

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These accompanying consolidated financial statements cover the period from December 29, 2014 through November 30, 2015, representing the eleven months ended of the Partnership’s recently adopted fiscal year. The prior years’ comparable twelve-month periods cover the periods from December 30, 2012 through December 29, 2013 and from December 30, 2013 through December 28, 2014 and is reported on the basis of the previous fiscal year end of the Predecessor. As a result of the change in our fiscal year end, the annual period of our newly adopted fiscal year does not coincide with the historical annual periods previously reported by the Predecessor. Financial information for eleven months ended November 30, 2014 and November 30, 2013 have not been included in this Transition Report on Form 10-K for the following reasons: (i) the years ended December 28, 2014 and December 29, 2013 provide as meaningful a comparison to the eleven months ended November 30, 2015 as would the eleven months ended November 30, 2014 and November 30, 2013; (ii) we believe that there are no significant factors, seasonal or other, that would impact the comparability of information if the results for the eleven months ended November 30, 2014 and November 30, 2013 were presented in lieu of results for the years ended December 28, 2014 and December 29, 2013; and (iii) it was not practicable or cost justified to prepare this information.

Significant Factors and Trends Affecting Our Business

The assets in our Portfolio sell substantially all of their output or are leased pursuant to long-term, fixed price offtake agreements. We believe these long-term agreements substantially mitigate volatility in our cash flows. Over time, our results of operations and our ability to grow our business could be impacted by a number of factors and trends that affect our industry generally, including the development of our ROFO Portfolio and the other projects we may acquire in the future.

Increasing Demand for Solar Energy

Global energy demand is increasing due to economic development and population growth. The U.S. Energy Information Administration projects OECD electricity generation to increase 34% between 2014 and 2040, requiring an increase in capacity of more than 600 GW of electricity generation, including through solar energy projects. 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. We expect the coal and nuclear energy segments will continue to face regulatory and economic headwinds. As a form of electricity generation that is not dependent on fossil fuels, does not produce greenhouse gas emissions and whose costs are falling, solar energy is well positioned to continue to capture an increasing share of this new build capacity. We believe we are well-positioned to benefit from this increased demand for solar energy.

Government Incentives

Our Sponsors benefit from certain U.S government incentives designed to promote the development and use of solar energy. These incentives include accelerated tax depreciation, ITCs, Renewable Portfolio Standards (“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. For more information about the risks associated with these government incentives, please read Part I, Item 1A. “Risk Factors—Government regulations providing incentives and subsidies for solar energy could change at any time and such changes may negatively impact our growth strategy”.

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, 2015, have a weighted average remaining life of approximately 21.6 years. In addition, our near-term growth strategy is also largely insulated from the trends discussed above. We expect that most of our short-term growth will come from opportunities to acquire the projects included in our ROFO Portfolio, all of which will have executed power sale agreements.

Critical Accounting Policies & Estimates

We prepare our consolidated financial statements in conformity with U.S. generally accepted accounting principles, 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

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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 IV, Item 15. “Exhibits, Financial Statement Schedules—Notes to Consolidated Financial Statements—Note 2.  Summary of Significant Accounting Policies”.

Revenue Recognition

Power Purchase Agreements: Revenue is generated from the sale of energy to various non-affiliated parties under long-term PPAs. Amounts are recognized as revenue based on rates stipulated in the respective PPAs when energy and any related renewable energy attributes are delivered.

Sales-type leases:    Certain residential leased solar energy systems are classified as sales-type leases because the net present value (“NPV”) of the minimum lease payments per the contract, excluding the portion of payments representing executory costs, equals or exceeds 90% of the excess of the fair value of the leased property to the lessor at lease inception. For such solar energy systems, the NPV of the minimum lease payments, net of executory costs, is recognized as revenue when the lease is placed in service. This NPV includes fixed and determinable state or local rebates defined in the minimum lease payments under the lease but excludes performance-based incentives (“PBI Rebates”) because these rebates are not fixed and determinable as they relate to the generation of electricity from the leased solar energy system, and therefore represent contingent revenue recognized upon cash receipt. This NPV, as well as that of the residual value of the lease at termination, are recorded as financing receivables in the condensed consolidated balance sheets. The difference between the initial net amounts and the 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 energy system is recognized on a straight-line basis over the 20-year lease term. The residual values of solar energy systems are determined at the inception of the lease applying an estimated system fair value at the end of the lease term. As all the leases owned by the Predecessor have been placed into service before fiscal 2015, all revenue related to the NPV of the minimum lease payments has been recognized as of December 28, 2014. Accordingly, other than interest revenue, there was no sales-type lease revenue recognized on the consolidated financial statements for the eleven months ended November 30, 2015.

Operating leases:  For those residential systems classified as operating leases, revenue associated with renting the solar energy 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 condensed 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.

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 our concentration of credit risk is limited because of its large number of residential customers, high credit quality of the residential customer base with an average FICO credit score of 765 at the time of initial contract, small account balances for most of these residential customers, and customer geographic diversification. As of November 30, 2015 and December 28, 2014, no 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 energy 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 bases such reserves on several factors, including consideration of historical credit losses. As of November 30, 2015 and December 28, 2014, $0.3 million and zero, respectively, had been recorded as allowance for losses on financing receivables.

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Valuation of Long-Lived Assets

We evaluate our 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 energy systems include lease asset depreciation expense greater than associated operating revenue, decrease in the estimated residual value of the leased solar energy 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 energy 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 either quoted market prices, if available, or discounted cash flow analyses.

With respect to 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 or the selling price of the electricity to decrease.

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):

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 energy systems at the end of the term of the agreement. We account for such legal obligations or asset retirement obligations (“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, plant 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 $10.0 million as of November 30, 2015. The Predecessor had not accrued any AROs as of December 28, 2014 since it had not significantly commenced construction on any of the projects on the sites.

Noncontrolling Interests

Noncontrolling interests represent the portion of net assets in consolidated subsidiaries that are not attributable, directly or indirectly, to the Partnership. Our largest portion of noncontrolling interest relates to our Sponsor’s 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 hypothetical liquidation at book value method (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

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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 condensed consolidated balance sheets. 

Business Combinations

We record all acquired assets and liabilities 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. The acquisition related costs that are not part of the consideration are expensed as they are incurred. These costs typically include transaction and integration costs, such as legal, accounting, and other professional fees.

Income Taxes

Deferred tax assets and liabilities are recognized for temporary differences between financial statement and income tax bases of assets and liabilities. 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.

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 recognize 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 will accrue interest and penalties on tax contingencies, which are not considered material, if any.

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.

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.

The Partnership records uncertain tax positions in accordance with ASC 740, Income Taxes, 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.

Recent Accounting Pronouncements

In November 2015, the Financial Accounting Standards Board (the “FASB”) issued an update which requires entities that present a classified balance sheet to classify all deferred taxes as noncurrent assets or noncurrent liabilities. The new guidance is effective for the Partnership for annual periods beginning after December 15, 2016. Early adoption of this standard is permitted. The Partnership is evaluating the potential impact of this standard on its consolidated financial statements and disclosures.

In September 2015, the FASB issued an update to the business combination standards to eliminate the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. Instead, an acquirer must recognize measurement-period adjustments during the period in which it determines the amounts, including the effect on earnings of any amounts that would have been recorded in previous periods if the accounting had been completed at the acquisition date.  The new guidance is effective for the Partnership no later than the first quarter of fiscal 2016 and requires a prospective approach to

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adoption.  Early adoption of this standard is permitted.  The Partnership adopted the standard effective January 1, 2016 and the adoption of this standard did not impact the Partnership’s results of operations, cash flows or financial position.

In April 2015, the FASB issued an update to the standards for the presentation of debt issuance costs to reduce complexity in accounting standards and to align with International Financial Reporting Standards. The updated standard requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. U.S. GAAP previously required debt issuance costs to be reflected as an asset on the Partnership’s balance sheet. The new debt issuance cost guidance is effective for the Partnership no later than the first quarter of fiscal 2016 and requires a retrospective approach to adoption. We have elected early adoption of the updated accounting standard, effective in the second quarter of fiscal 2015. There is no reclassification required as there was no debt issuance cost that was recorded as an asset in the prior periods.

In February 2015, the FASB issued a new standard which modifies existing consolidation guidance for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The new consolidation guidance is effective for the Partnership in the first quarter of 2016 and requires either a retrospective or a modified retrospective approach to adoption. Early adoption of this standard is permitted. We have adopted the standard effective January 1, 2016 and the adoption of this standard did not impact the Partnership’s results of operations, cash flows or financial position.

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. In August 2015, the FASB deferred the effective date of this standard for all entities by one year. The new revenue recognition standard becomes effective for the Partnership in the first quarter of fiscal 2019, and is to be applied retrospectively using one of two prescribed methods. We are evaluating the application method and impact on its consolidated financial statements and disclosures.

Results of Operations

 

 

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Eleven Months Ended November 30, 2015 Compared to Year Ended December 28, 2014

Revenues

 

 

Operating revenues for the eleven months ended November 30, 2015 were comprised of lease revenues from our solar energy system lease arrangements and power purchase agreements. Residential systems are leased under lease agreements which are classified for accounting purposes either as sales-type leases or operating leases. As all the leases owned by the Predecessor have been placed into service, and all revenue related to the net present value of the minimum lease payments for sales-type leases has been recognized as of December 28, 2014. Accordingly, other than interest revenue, we had no sales-type lease revenue on our consolidated financial statements for the eleven months ended November 30, 2015.

For those residential leases classified as sales-type leases, the net present value of the minimum lease payments, net of executory costs, is recognized as revenue when the leased asset is placed in service. Executory costs represent estimated lease operation and maintenance costs, including insurance, to be paid by the lessor, including any profit thereon. This net present value is inclusive of certain fixed and determinable state or local rebates, described below, defined in the lease document as part of minimum lease payments. The difference between the net amount and the gross amount of a sales-type lease is amortized as revenue over the lease term using the interest method. Revenue from executory costs is recognized on a straight-line basis over the lease terms, almost all of which are 20 years.

For those residential leases classified as operating leases, revenue associated with renting the solar energy system and related executory costs are recognized on a straight-line basis over the lease terms, almost all of which are 20 years. We do not record certain fixed and determinable state or local rebates. Previously, certain of these fixed and determinable state or local rebates, described below, defined in the lease document as part of minimum lease payments, were recorded as deferred revenue in the Predecessor’s balance sheets when the lease was placed in service and amortized to revenue on a straight-line basis over the lease term.

State or local rebates that are fixed and determinable are recognized when the related solar energy system is placed in service. State or local rebates that are not fixed and determinable, since they relate to the generation of electricity from the leased solar energy system, are recognized as revenue upon cash receipt for both sales-type leases and operating leases. All revenues for the period were generated in the United States in the eleven months ended November 30, 2015 and the year ended December 28, 2014.

Total revenues increased by $1.4 million, or 15.5%, during the eleven months ended November 30, 2015 as compared to the year ended December 28, 2014 due to the addition of a solar energy system contributed by our Sponsor, First Solar, at the closing of the IPO as well as the commencement of operations of all of our solar system projects as of the fourth quarter of fiscal 2015.

Operating Costs and Expenses

 

 

Cost of Operations: Cost of operations primarily includes expenses related to O&M agreements. The Predecessor’s cost of operations includes costs incurred in connection with sales-type leases that are recognized when the leased solar energy system is placed in service, and also costs related to system output performance warranty and residential lease system repairs accrual and reserves for upfront rebate receivables. Costs recognized on sales-type leases include initial direct costs to complete a leased solar

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energy system, such as costs for constructing a solar energy system inclusive of dealer payments, freight charges and direct lease costs. The Predecessor received federal cash grants under the federal Section 1603 cash grant program on a portion of our Residential Portfolio, the benefit of which was recorded as a reduction of cost of operations on the combined statements of operations when eligible leased solar energy systems were placed in service and all criteria necessary to be entitled to such grant income were met. We did not recognize any cash grants as a reduction of sales-type lease cost of operations for the eleven months ended November 30, 2015. For the year ended December 28, 2014, we recognized $5.7 million of cash grants as a reduction of sales-type lease cost of operations.

The increase of $5.8 million, or 182.1%, for the eleven months ended November 30, 2015 as compared to the year ended December 28, 2014 was mainly driven by (i) $5.7 million lower cost in 2014 due to the recognition of certain cash grants related to sales-type leases placed in service in prior periods until all criteria necessary to be entitled to such grant income were met during the second quarter of fiscal 2014 and (ii) an increase of $0.1 million in O&M fees associated with projects that commenced operations in fiscal 2015.

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 the eleven months ended November 30, 2015 and $0.9 million for the year ended December 28, 2014.

Selling, General and Administrative: Selling, general and administrative 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; 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 energy systems leased to residential homeowners and solar energy projects under construction. These 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 $5.9 million, or 122.1%, for the eleven months ended November 30, 2015 as compared to the year ended December 28, 2014 was primarily driven by a $2.4 million higher allocation of SunPower operating expenses for the period before the IPO based on the proportional level of effort attributable to the Quinto Project, the RPU Project, the UC Davis Project and the Macy’s Project under construction, all of which achieved commercial operation as of November 30, 2015, $3.0 million of post-IPO operating expenses related to audit, legal, insurance, retaining the independent directors of our board of directors, MSA, AMA and other fees, the allocation of $1.6 million of costs incurred by SunPower related to our IPO, and $0.4 million increase in bad debt expense and other costs related to residential lease customers, offset by approximately $1.2 million reduction in land lease costs of the Predecessor related to the Quinto Project and other non-capitalizable project-related expenses incurred during the project development period in the prior year.

Depreciation: Depreciation expense reflects costs associated with depreciation of our solar system assets that have been placed in service. The Predecessor was entitled to receive federal cash grants for the construction of the residential leased solar energy systems; therefore, the benefit of the cash grants is recorded as a reduction to the carrying value of the operating lease assets when eligible leased solar energy systems are placed in service and all criteria necessary to be entitled to such grant income are met. After the cash grant contra-asset is recorded to reduce the carrying value of the operating lease assets, it is subsequently amortized as a reduction to depreciation expense.

The increase of $2.0 million, or 83.5%, for the eleven months ended November 30, 2015 as compared to the year ended December 28, 2014 was primarily a result of a solar system contributed by our Sponsor, First Solar, at the closing of the IPO and the commencement of operations of additional solar system projects during eleven months ended November 30, 2015.

Acquisition-related transaction costs: Acquisition-related transactions costs represent legal and consulting fees incurred in connection with a project acquisition that was consummated in January 2016.

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Other Expense

 

 

Interest expense: Non-cash interest expense primarily relates to two financing arrangements under which leased solar energy systems were financed by two third-party investors. Both financing arrangements were terminated in 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 is recognized on the consolidated statements of operations using the effective interest rate method calculated at a rate of approximately 14-15%.

Cash interest expense relates to letter of credit fees and revolver fees as well as financing fees due to the two third-party investors for undrawn commitment of the financing arrangement. The interest incurred related to our projects that are 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 energy system is ready for its intended use.

Interest expense for the eleven months ended November 30, 2015 included $1.3 million of non-cash interest expense and $0.5 million of cash interest expense compared to total interest expense for the year ended December 28, 2014 which included $4.8 million of non-cash interest expense and $0.7 million of cash interest expense. Non-cash interest expense decreased $3.5 million, or 72.9% due to the Predecessor terminating one residential lease financing obligation in January 2015 and the remaining obligation in May 2015.

Interest income of $1.5 million for the eleven months ended November 30, 2015 represents the accrued interest on reimbursable network upgrade costs related to the Quinto Project. These costs plus accrued interest are reimbursable by the utility company over five years when the project achieves commercial operation.

Other expense for the eleven months ended November 30, 2015 included a loss on cash flow hedges of $5.4 million associated with the Predecessor, a $0.6 million unrealized loss on cash flow hedge associated with our term loan facility, and a loss on termination of the residential lease financial obligation of $6.5 million, respectively.

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 the year ended December 28, 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 quarter ended March 28, 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 the quarter ended June 28, 2015. During the eleven months ended November 30, 2015 and year ended December 28, 2014, $5.4 million and zero, respectively, was reclassified into loss on cash flow hedges within other expense, net in the condensed consolidated statements of operations, as the transaction was terminated.

Loss on cash flow hedges associated with term loan facility: During the eleven months ended November 30, 2015, we entered into interest rate swap agreements to economically hedge the cash flows on our term loan facility. 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. During the eleven months ended November 30, 2015, we recorded an unrealized loss of $0.6 million for the mark-to-market valuation adjustment of interest rate swap agreements.

Loss on termination of financing obligation: On January 30, 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

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termination of the arrangement, the Predecessor paid $10.8 million to terminate the $10.1 million outstanding financing obligation. On May 4, 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. During the eleven months ended November 30, 2015 and years ended December 28, 2014 and December 29, 2013, $6.5 million and zero, respectively, was recognized as a loss on termination within other expense, net in the condensed consolidated statements of operations.

Income tax provision

 

 

Income Tax Provision: Our tax rate is primarily affected by the tax impact of equity in earnings, valuation allowances during the Predecessor period, the tax impact of noncontrolling interest, and state tax rates (net of federal benefit) in various jurisdictions, most significantly California. We included the income tax provision related to our equity in earnings of unconsolidated investees in the income tax (provision) benefit line of the condensed consolidated statements of operations.

Our income tax (provision) benefit following the IPO closing date primarily represents deferred federal and state taxes on the net income of OpCo that is allocated to the Partnership (exclusive of income tax but after noncontrolling interest). The Predecessor’s income tax (provision) benefit, which was calculated on a separate return basis for the carve-out period, was due to minimum state income taxes. The change in income tax (provision) benefit as a percentage of revenues for the eleven months ended November 30, 2015 of (117.3)% compared to (0.2)% for the year ended December 28, 2014 is primarily the result of the income generated by the Project Entities following the IPO which was allocated to the Class A shares compared to the loss before income taxes of $1.2 million for the year ended December 28, 2014.

Equity in Earnings of Unconsolidated Investees

 

 

Equity in earnings of unconsolidated investees represents our proportionate share of the earnings and losses from SG2 Holdings, North Star Holdings and Lost Hills Blackwell Holdings. We own a 49% ownership interest in each of SG2 Holdings, North Star Holdings and Lost Hills Blackwell Holdings, and an affiliate of Southern Company, which is not affiliated with us, owns the other 51% ownership interest. The minority membership interests are accounted for as equity method investments. During the eleven months ended November 30, 2015, we recognized equity in earnings of $9.1 million. We did not have any equity method investments during the year ended December 28, 2014.

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests

 

 

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests for the eleven months ended November 30, 2015 included (i) a net loss of $102.2 million 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

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power systems and (ii) net income of $79.6 million attributable to our Sponsors as a result of their economic ownership in our OpCo. We apply the hypothetical liquidation value 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.

Year Ended December 28, 2014 Compared to Year Ended December 29, 2013

Revenues

 

 

Total Revenues:    Operating revenues for the period were comprised of revenues generated from solar energy systems leased to residential customers. These systems are leased under lease agreements which are classified for accounting purposes either as sales-type leases or operating leases.

Total revenue decreased 62% during the year ended December 28, 2014 as compared to the year ended December 29, 2013 due to a $15.3 million decrease in sales-type lease revenue, which is recognized when the sales-type leases are placed in service, as compared to operating lease revenue, which is recognized over the applicable lease term, as the majority of residential leases were placed in service in prior periods.

Operating Costs and Expenses

 

 

Cost of Operations:    Our Predecessor’s cost of operations includes costs incurred in connection with sales-type leases that is recognized when the leased solar energy system is placed in service. Costs recognized on sales-type leases include initial direct costs to complete a leased solar energy system, such as costs for constructing a solar energy system inclusive of dealer payments, freight charges and direct lease costs. Our Predecessor received federal cash grants under Section 1603 on a portion of our Residential Portfolio, the benefit of which was recorded as a reduction of cost of operations on the combined statements of operations when eligible leased solar energy systems are placed in service and all criteria necessary to be entitled to such grant income were met. For the years ended December 28, 2014 and December 29, 2013, we recognized $5.7 million and $4.7 million, respectively, of cash grants as a reduction of sales-type lease cost of operations.

The decrease of $16.3 million, or 124%, for the year ended December 28, 2014 as compared to the year ended December 29, 2013 is primarily a result of a $11.5 million decrease in sales-type leases as majority have been placed in service in prior periods and a $5.7 million decrease due to the deferral of the recognition of certain cash grants related to sales-type leases placed in service in prior periods until all criteria necessary to be entitled to such grant income were met during the year ended December 28, 2014, partially offset by a $0.8 million increase in other costs, including system output performance warranty and residential lease system repairs accrual.

Cost of Operations—SunPower, prior to IPO:    Cost of operations—SunPower, prior to IPO, represents executory costs that were allocated to the Predecessor by our Sponsor. Costs incurred for these services were $0.9 million for each of the years ended December 28, 2014 and December 29, 2013.

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Selling, General and Administrative:    Selling, general and administrative expense includes (i) charges that were incurred by SunPower that were specifically identified as attributable to our Predecessor; and (ii) an allocation of SunPower operating expenses based on the proportional level of effort attributable to the operation of our Predecessor’s portfolio of solar energy systems leased to residential homeowners and solar energy 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 increase of $0.5 million, or 13%, for the year ended December 28, 2014 as compared to the year ended December 29, 2013 was primarily driven by the ramp up in non-capitalizable selling, general and administrative expenses for development and construction activities on projects included in our Portfolio.

Depreciation: Depreciation expense reflects costs associated with depreciation of our operating lease assets, which are depreciated using the straight-line method to their estimated residual value over the 20 year lease term. Our Predecessor was entitled to receive federal cash grants for the construction of these leased solar energy systems; therefore, the benefit of the cash grants is recorded as a reduction to the carrying value of the operating lease assets when eligible leased solar energy systems are placed in service and all criteria necessary to be entitled to such grant income are met. After the cash grant contra-asset is recorded to reduce the carrying value of the operating lease assets, it is subsequently amortized as a reduction to depreciation expense. The decrease of $0.9 million, or 27.5%, for the year ended December 28, 2014 as compared to the year ended December 29, 2013 is primarily a result of the recognition of certain cash grants related to operating leases placed in service in prior periods, which were deferred until the recognition criteria was met during the year ended December 28, 2014.

Other Expense

 

 

Interest expense for the year ended December 28, 2014 included $4.8 million of non-cash interest expense and $0.7 million of cash interest expense and included $4.6 million of non-cash interest expense and $2.2 million of cash interest expense for the year ended December 29, 2013.

Non-cash interest expense for the years ended December 28, 2014 and December 29, 2013 totaled $4.8 million and $4.6 million, respectively, relating to two financing arrangements under which leased solar energy systems are financed by two third-party investors. Under the terms of these financing arrangements, the investors provided upfront payments to our Predecessor, for which our Predecessor recognizes 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. Non-cash interest expense is recognized on our Predecessor’s combined carve-out statements of operations using the effective interest rate method calculated at a rate of approximately 14%. Non-cash interest expense increased by $0.3 million, or 7%, for the year ended December 28, 2014 as compared to the year ended December 29, 2013 as portfolios were still being funded through the end of the year ended December 29, 2013, resulting in a higher interest expense on a higher financed balance throughout the year ended December 28, 2014.

Cash interest expense for the year ended December 28, 2014 and December 29, 2013 totaled $0.7 million and $2.2 million, respectively, relating to letter of credit fees of $0.7 million and $0.3 million for the year ended December 28, 2014 and December 29, 2013, respectively, for the Quinto Project as well as an incremental $1.9 million financing fee for the year ended December 29, 2013 due to the third-party investors for undrawn commitment of the financing arrangement. The interest incurred related to the Quinto Project financing is not reflected as an expense in the combined carve-out statement of operations as it is capitalized to construction-in-process until the solar energy system is ready for its intended use.

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Income tax (provision) benefit

 

 

Our Predecessor’s income tax expense for the years ended December 28, 2014 and December 29, 2013 was due to state income taxes payable. The change in effective tax rate for the year ended December 28, 2014 of 1.9% compared 0.8% for the year ended December 29, 2013 is the result of lower losses before income taxes for the year ended December 28, 2014 of $1.2 million compared to a loss before income taxes of $3.8 million for the year ended December 29, 2013 while our income tax expense year-on-year did not change materially.

Liquidity and Capital Resources

Historically, the Predecessor’s sources of liquidity included cash generated from operations and funding from SunPower or third-party financial institutions. The Predecessor participated in SunPower’s centralized cash management system; therefore, the Predecessor’s cash receipts were deposited in SunPower’s or its affiliates’ bank accounts, all cash disbursements were made from those accounts, and the Predecessor maintained no bank accounts dedicated solely to our assets.

As of the closing of the IPO, we established separate bank accounts. SunPower will continue to provide treasury services on the General Partner’s behalf under our MSA with an affiliate of SunPower.

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 and dividends 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. 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.

Term Loan, Delayed Draw Term Loan and Revolving Credit Facility

On June 5, 2015, OpCo entered into a $525.0 million senior secured 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. As of November 30, 2015, the full amount of the $300.0 million term loan facility and approximately $48.8 million of letters of credit under the revolving credit facility are outstanding. The delayed draw term loan facility is available to us during the 12-month period following the closing of our IPO. Subject to certain conditions, the credit facility includes conditional borrowing capacity for incremental commitments to increase the term loan facility and revolving credit facility by $250.0 million, with any increase in the revolving facility not to exceed $100.0 million. The proceeds of the term loan facility were used to pay fees and expenses, to repay existing indebtedness, to make a distribution to the Sponsors and for general purposes, including to fund acquisition opportunities, while the proceeds of the delayed draw term loan facility is expected to be used for acquisitions. Amounts available under the revolving facility is expected to be used for capital expenditures, acquisitions and other investments, to provide for ongoing working capital requirements, and for general corporate purposes, with letters of credit issued thereunder to be used for credit support and general corporate purposes. The credit facility will mature in June 2020, five years following the closing of our IPO.

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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 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. 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. 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. In the future, we may increase our debt to fund our operations or future acquisitions.

OpCo’s credit facility is secured by a pledge over the equity of OpCo and certain of its domestic subsidiaries. The Partnership and each of OpCo’s domestic subsidiaries, other than certain non-guarantor subsidiaries, have guaranteed the obligations of OpCo under the credit facility. This credit facility contains various covenants and restrictive provisions that limit our, OpCo’s and certain of our and its domestic subsidiaries’ ability to take certain actions. Please read Part I, Item IA. “Risk Factors—Risks Related to Our Financial Activities—Our level of indebtedness or restrictions in OpCo’s credit facilities could adversely affect our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders”.

OpCo’s credit facility also contains covenants requiring us to maintain the following financial ratios beginning in the fiscal quarter ending August 31, 2015: (i) a debt to cash flow ratio (as more fully defined in the credit facility) of not more than (a) 7.00 to 1.00 for the fiscal quarters ending August 31, 2015 through May 31, 2016, (b) 5.50 to 1.00 for the fiscal quarters ending August 31, 2016 through May 31, 2017, and (c) 5.00 to 1.00 for each fiscal quarter ending thereafter; and (ii) a debt service coverage ratio (as more fully defined 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. In addition, this 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. As of November 30, 2015, we were in compliance with the debt covenants.

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 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.

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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

Eleven Months Ended November 30, 2015 Compared to Year Ended December 28, 2014

A summary of the sources and uses of cash and cash equivalents is as follows:

 

 

Operating Activities

Net cash provided by operating activities for the eleven months ended November 30, 2015 was $1.8 million and was primarily the result of: (i) $6.8 million of cash distributions from unconsolidated investees; (ii) non-cash charges of $26.5 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 energy systems, $1.3 million reserve for rebates receivable, $1.2 million interest expense for the financing arrangement of residential leased solar energy systems prior to termination, $0.6 million unrealized loss on interest rate swaps, and $0.1 million of stock-based compensation expense; (iii) a $5.4 million increase in accounts payable and other accrued liabilities; (iv) a $0.4 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.

Net cash provided by operating activities for the year ended December 28, 2014 was $1.8 million and was primarily the result of: (i) non-cash charges of $7.2 million for depreciation of operating lease assets and non-cash interest expense for two financing arrangements of leased solar energy systems; (ii) a $2.7 million decrease in rebates receivable and $1.1 million decrease in cash grants receivable; and (iii) a $0.5 million decrease in deferred costs related to leases placed in service during the year under sales-type leases. This was partially offset by: (i) a net loss of $1.2 million; (ii) a $3.6 million decrease in accounts payable and other accrued liabilities, related to recognition of deferred cash grant awards; (iii) an increase of $4.1 million in accounts receivable and financing receivable for rent due on sales-type and operating leases; and (iv) a $0.8 million increase in deferred revenue mainly due to additional rebates on systems under operating leases placed in service during the year.

Investing Activities

Net cash used in investing activities for the eleven months ended November 30, 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 Project, partially offset by $4.7 million of cash distributions from unconsolidated investees.

Net cash used in investing activities for the year ended December 28, 2014 was $55.2 million and relates to costs associated with solar energy projects under construction and completed residential leased solar energy systems that were classified as operating leases, net of cash grant received.

Financing Activities

Net cash provided by financing activities for the eleven months ended November 30, 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,

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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 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 a promissory 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.

Net cash provided by financing activities for the year ended December 28, 2014 was $53.4 million due to $61.5 million in debt proceeds from financing the Quinto Project and $3.1 million of capital contributions from SunPower, partially offset by $11.2 million of capital distributions to SunPower. Net cash provided by financing activities for the year ended December 29, 2013 was $2.7 million due to $54.6 million of payments from two third-party investors for two financing arrangements of leased solar energy systems, and $31.9 million of capital contributions from SunPower, partially offset by $83.8 million of capital distributions to SunPower.

Year Ended December 28, 2014 Compared to Year Ended December 29, 2013

A summary of the sources and uses of cash and cash equivalents is as follows:

 

 

Operating Activities

Net cash provided by operating activities for the year ended December 28, 2014 was $1.8 million and was primarily the result of: (i) non-cash charges of $7.2 million for depreciation of operating lease assets and non-cash interest expense for two financing arrangements of leased solar energy systems; (ii) a $2.7 million decrease in rebates receivable and $1.1 million decrease in cash grants receivable; and (iii) a $0.5 million decrease in deferred costs related to leases placed in service during the year under sales-type leases. This was partially offset by: (i) a net loss of $1.2 million; (ii) a $3.6 million decrease in accounts payable and other accrued liabilities, related to recognition of deferred cash grant awards; (iii) an increase of $4.1 million in accounts receivable and financing receivable for rent due on sales-type and operating leases; and (iv) a $0.8 million increase in deferred revenue mainly due to additional rebates on systems under operating leases placed in service during the year.

Net cash provided by operating activities for the year ended December 29, 2013 was $5.4 million and was primarily the result of: (i) $7.8 million in non-cash charges for depreciation of operating lease assets and non-cash interest expense for upfront payments made by two third-party investors; (ii) an $11.4 million decrease in deferred costs related to leases placed in service during the year under sales-type leases; (iii) a $7.6 million increase in accounts payable and other accrued liabilities due to deferral of cash grant awards until all criteria necessary to be entitled to such grant income were met and an accrual of financing fees to the third-party investors for the two financing arrangements of leased solar energy systems; (iv) a $1.2 million increase in deferred revenue due to additional deferred rebates and rents on systems under operating leases placed in service during the year; and (v) a $0.4 million increase in cash grants and rebates receivable. This was partially offset by: (i) a net loss of $3.8 million; and (ii) a $19.2 million increase in accounts receivable and financing receivable due to additional sales-type lease receivables recorded for systems placed in service during the year and billings on operating leases.

Investing Activities

Net cash used in investing activities for the years ended December 28, 2014 and December 29, 2013 was $55.2 million and $8.1 million, respectively, and relates to costs associated with solar energy projects under construction and completed residential leased solar energy systems that were classified as operating leases, net of cash grant received.

Financing Activities

Net cash provided by financing activities for the year ended December 28, 2014 was $53.4 million due to $61.5 million in debt proceeds from financing the Quinto Project and $3.1 million of capital contributions from SunPower, partially offset by $11.2 million of capital distributions to SunPower. Net cash provided by financing activities for the year ended December 29, 2013 was $2.7 million

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due to $54.6 million of payments from two third-party investors for two financing arrangements of leased solar energy systems, and $31.9 million of capital contributions from SunPower, partially offset by $83.8 million of capital distributions to SunPower.

Contractual Obligations

The following table summarizes our contractual obligations as of November 30, 2015:

 

 

Off-Balance-Sheet Arrangements

As of November 30, 2015, we did not have any significant off-balance-sheet arrangements.

Inflation

Inflation did not have a material impact on our results of operations in 2015.

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.

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 a credit approval process and 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 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.

The concentration of 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, 2015, we do not believe we had significant credit risk because of the creditworthiness of the offtake counterparties.

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

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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 growth 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, 2015, the outstanding principal balance of our variable interest borrowings was $300.0 million of which $60.0 million is unhedged.  An immediate 10% increase in interest rates would have an increase of approximately $0.02 million of annualized interest expenses on our consolidated financial statements. However, we entered into interest rate swaps on July 17, 2015, which would mitigate the interest rate risk of our term loan facility. As of November 30, 2015, our investment portfolio consisted of 100% in demand deposits.

Item 8. Financial Statements and Supplementary Data.

The financial statements and schedules are listed in Part IV, Item 15 of this Form 10-K and are incorporated by reference herein.

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 our 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 Transition Report on Form 10-K.

Management’s Report on Internal Control Over Financial Reporting

This Transition Report on Form 10-K does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of the Partnership's independent registered public accounting firm due to a transition period established by rules of the SEC for newly public companies.

Attestation Report of the Independent Registered Public Accounting Firm

This Transition 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 due to a transition period established by rules of the SEC for new public companies. 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 Partners

We are managed by the board of directors 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 will also not be entitled to elect the directors of our general partner, which are all appointed by our Sponsors, or 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 of directors have delegated authority over certain other matters to its project operations committee and to its officers. Our general partner’s board of directors is composed of seven members. Our Sponsors appointed all members to our general partner’s board of directors, including four Sponsor directors, two of which were appointed by First Solar and two of which 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 of directors.

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 of directors of our general partner. There are no family relationships among any of our general partner’s directors or executive officers of our general partner.  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.

The following sets forth information for our general partner’s directors and executive officers.

 

 

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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 of directors of our general partner. There are no family relationships among any of our general partner’s directors or executive officers of our general partner.

Mr. Charles D. Boynton serves as the chairman of the board of directors and chief executive officer of our general partner. Mr. Boynton has also served 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. 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 of directors of our general partner.

Mr. Mark R. Widmar serves as chief financial officer and a member of the board of directors of our general partner. Mr. Widmar also serves as the Chief Financial Officer of First Solar since April 2011. Mr. Widmar has also served as First Solar’s Chief Accounting Officer since February 1, 2012. 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. Mr. Widmar’s extensive experience in key financial positions in various industries makes him well qualified to serve as a member of the board of directors of our general partner.

Ms. Mandy Yang serves as the corporate controller and chief accounting officer of our general partner. Ms. Yang also serves as the Sr. Director and Division Controller of the Global Distributed Generation (DG) Division at SunPower. Prior to that, she was the Director and Controller for the Global Residential and Light Commercial business unit as well as responsible for the financial planning and analysis function for the residential lease program within the residential business unit of the DG division. Before that, Ms. Yang led the external financial reporting and global operating expenses financial planning and analysis function at SunPower. Before joining SunPower in August 2011, Ms. Yang held a variety of senior key finance positions at Spansion Inc. from 2006 to 2011, including leading the SEC financial reporting group and Corporate Treasury function as well as the Corporate R&D financial planning and analysis role. Prior to 2006, Ms. Yang was an internal auditor at Synnex Corp and an auditor with Deloitte and Touche, among others. Ms. Yang is a California Certified Public Accountant and a Chartered Financial Analyst. Ms. Yang earned her master’s degree in business administration with a dual major in accounting and finance from University of Illinois at Urbana-Champaign.

Mr. Jason E. Dymbort serves as general counsel of our general partner. Mr. Dymbort also serves as 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 serves as a vice president of operations of our general partner. Ms. Jackson also serves as a Vice President for Project Finance at SunPower in Richmond, California where Ms. Jackson is responsible for SunPower’s Global Utility project and structured debt and equity financings, including tax equity financing in the United States. Ms. Jackson’s professional experience includes more than 19 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.

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Mr. Alexander R. Bradley serves as a vice president of operations of our general partner. Mr. Bradley also serves as a Vice President, Global Project Finance and Treasurer for First Solar, Inc. in New York, where Mr. Bradley is 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 10 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.

Mr. Joseph G. Kishkill serves as a member of the board of directors of our general partner in May 2015. Mr. Kishkill joined First Solar in September 2013 as Chief Commercial Officer. Mr. Kishkill currently serves as President, International at First Solar. Prior to joining First Solar, Mr. Kishkill served as President, Eastern Hemisphere Operations, for Exterran Energy Solutions, L.P. and Senior Vice President of Exterran Holdings, Inc., a global provider of natural gas, petroleum and water treatment production services. Prior to that, he led Exterran’s business in the Latin America region. Prior to joining Exterran’s predecessor company in 2002, Mr. Kishkill held positions of increasing responsibility with Enron Corporation from 1990 to 2001, advancing to Chief Executive Officer for South America. During his career, Mr. Kishkill has been based in Dubai, Brazil and Argentina and has provided management services for energy projects and pipelines throughout South America. Mr. Kishkill holds a Master in Business Administration degree from the Harvard Graduate School of Business Administration and holds a Bachelor of Science degree in Electrical Engineering from Brown University. Mr. Kishkill’s extensive experience in the energy industry makes him well qualified to serve as a member of the board of directors of our general partner.

Mr. Ty P. Daul serves as a member of the board of directors of our general partner. Mr. Daul serves as the Senior Vice President, Americas Power Plant business for SunPower. Mr. Daul has been integrally involved in over 2.8 GW of operating renewable projects and 870 MW of operating gas-fired projects representing approximately $5.7 billion of total investment over the last 25 years in the power generation industry and his experience covers engineering, sales and marketing, product development, financial analysis, development and executive leadership. Prior to joining SunPower, Mr. Daul cofounded Element Power US, LLC in 2009, was on the company’s Board of Directors, had direct oversight of Element’s Americas wind and solar renewable energy businesses as well as investment oversight on activities in South America and Europe. Prior to founding Element Power US, LLC, Mr. Daul was the Senior Vice President of Business Development at Iberdrola Renewables/PPM Energy, where he was responsible for all North American renewable energy business development activities, which included playing key roles in developing and growing the business, greenfield development, acquisitions and turbine supply of over 2.5 GW spinning wind projects. Prior to PPM Energy, Mr. Daul was leading gas-fired generation development throughout the United States with Entergy’s unregulated power generation business and Newport Generation. He started his career in engineering, marketing and business development roles with Westinghouse Electric’s global power generation group. Mr. Daul has served on the Wind Energy Foundation’s Board of Directors since early 2013 and is a Senior Advisor for Equilibrium Capital. Mr. Daul has also served as a member of the board of directors of North Wood Flooring, LLC since 2004. Mr. Daul holds a Bachelor of Science degree in Mechanical Engineering from the University of Washington and a Master’s degree in Business Administration from Texas A&M University. Mr. Daul’s extensive experience in engineering, marketing and business development in the renewable energy industry makes him well qualified to serve as a member of the board of directors of our general partner.

Mr. Thomas C. O’Connor serves as an independent director of the board of directors of our general partner. Since May 2011, Mr. O’Connor has served as a member of the board of directors of the general partner of Tesoro Logistics LP. 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. In addition, Mr. O’Connor also serves on the board of directors of Keyera Corporation, and previously served on the board of directors of QEP Resources, Inc. from January 2014 to January 2015. He has also previously served as a member of the board of directors of the Denver branch of the American Heart Association. 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. 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 of directors of our general partner.

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Mr. Norman J. Szydlowski serves as an independent director of the board of directors of our general partner. 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 September 2014, Mr. Szydlowski managed his personal investments as a private investor. Since November 2014, Mr. Szydlowski has 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. 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 of directors of our general partner.

Mr. Michael W. Yackira serves as an independent director of the board of directors of our general partner. 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 has also served as a member of the board of directors of the Smith Center for the Performing Arts since 2014 and as Chairman of the UNLV Foundation Board of Trustees since 2014. Mr. Yackira also served as a member of the board of directors of Opportunity Village. 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. Mr. Yackira’s extensive experience in the electric service industry makes him well qualified to serve as a member of the board of directors of our general partner.

Board Leadership Structure

As described in our corporate governance guidelines, our general partner’s board of directors 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 general partner’s board of directors’ 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 will initially be 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 an affiliated person 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 general partner’s board of directors. Compliance by audit committee members with these requirements is separately assessed by our general partner’s board of directors.

Based on its review and the NASDAQ standards, our general partner’s board of directors has determined that upon joining our general partner’s board of directors 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.

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Board Role in Risk Oversight

Our corporate governance guidelines provide that our general partner’s board of directors 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.

Committees of the Board of Directors

The standing committees of our general partner’s board of directors 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 will conduct 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 Transition 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

Our general partner’s board of directors have an audit committee composed of three directors, all of whom meet the independence standards and all of whom meet the 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 of directors has designated all three members of the audit committee as financial experts. The audit committee assists the board of directors 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 2015, 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. The audit committee recommended to our board of directors that the audited financial statements be included in the Partnership’s Transition Report on Form 10-K for the 2015 fiscal year.

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 our general partner’s board of directors, 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

Our general partner’s board of directors has a project operations committee composed of two directors, one designated by each Sponsor. The project operations committee is composed of Joseph G. Kishkill and Ty P. Daul. Unless otherwise prescribed by the

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general partner’s board of directors 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 of directors of our general partner.

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.

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.

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 10 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 10 percent of a registered class of our equity securities has complied with the Section 16 reporting requirements for transactions in our securities during the fiscal year ended November 30, 2015.

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 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 8point3 General Partner, LLC Long-Term Incentive Plan (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 January 22, 2016, 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 common units granted in 2015 to the non-employee directors.

 

Compensation Committee Report

 

The board of directors of our general partner does not have a compensation committee. The board of directors of our general partner, acting in lieu of a compensation committee, has reviewed and discussed the Compensation Discussion and Analysis with

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management. Based on this review and discussion, the board of directors of our general partner recommended that the Compensation Discussion and Analysis be included in this Transition Report on Form 10-K.

 

Compensation Committee Interlocks and Insider Participation

 

As discussed above, the board of directors of our general partner 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 of directors of our general partner 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 of directors of our general partner during fiscal 2015.

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 with the initial payment pro-rated from the date of our IPO.

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 of directors of our general partner for fiscal 2015:

 

 

(a)  Mr. Yackira was granted 2,427 of the Class A shares in 2015 with a grant date fair value of $37,500.

(b)  Mr. O’Connor was granted 2,427 of the Class A shares in 2015 with a grant date fair value of $37,500.

(c) Mr. Szydlowski was granted 2,427 of the Class A shares in 2015 with a grant date fair value of $37,500.

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 of directors of our general partner, unless the full board of directors 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 of directors or the committee may authorize a committee of one or more members of the board of directors to grant awards pursuant to such conditions or limitations as the board of directors 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.

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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, 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 of directors of our general partner 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 of directors or the committee, 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 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.

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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 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, 2015.

 

 

The following table sets forth the beneficial ownership of our Class A shares as of January 22, 2016, held by:

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 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

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footnote, the persons named in the table below have sole voting and investment power with respect to all of the Class A 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 20,007,281 Class A shares outstanding as of January 22, 2016. Percentage of total Class B shares beneficially owned is based on 51,000,000 Class B shares outstanding as of January 22, 2016.

 

 

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Item 13. Certain Relationships and Related Transactions, and Director Independence.

 

Certain Relationships and Related Party Transactions

As of November 30, 2015, 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 71.8% 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 and Mr. Widmar serves as an executive officer of both First Solar 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, 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; provided that for fiscal 2016 the maximum amount of such annual distribution would be approximately $32.1 million as a result of the distribution forbearance that our Sponsors agreed to in connection with the IPO.  Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Distributions of Available Cash—Distributions of Available Cash by OpCo—Forbearance Period”.

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 $600,000, in the case of the First Solar MSA, and $1,100,000, in the case of the SunPower MSA (as defined below), which amounts shall be adjusted annually for inflation. Between December 1, 2015 and November 30, 2016, each Service Provider has a one-time right to increase the management fee by an amount not to exceed 15% in the event such Service Provider’s cost to provide the services under its MSA exceeds the amount of the management fee. 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

In connection with the IPO, we, OpCo and our general partner entered into various agreements with our Sponsors. The following describes these agreements.

O&M Agreements

First Solar Projects

Lost Hills Blackwell Project

The Lost Hills Project Entity and the Blackwell Project Entity each entered into an Operation & Maintenance Agreement dated as of April 15, 2015 (the “Lost Hills O&M Agreement” and the “Blackwell O&M Agreement”, respectively, and together, the “Lost Hills Blackwell O&M Agreements”) with FSEC. FSEC’s obligations under the Lost Hills Blackwell O&M Agreements are supported by a parent guaranty agreement issued by First Solar for the benefit of the relevant Project Entity party thereto.

Term.    The Lost Hills Blackwell O&M Agreements each have a term of 10 years, which may be renewed for up to two additional five-year periods upon the mutual agreement of the parties thereto.

Services.    Under the Lost Hills Blackwell O&M Agreements, FSEC provides day-to-day facility and O&M services, including:

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Pursuant to the Lost Hills Blackwell O&M Agreements, FSEC is required to propose an annual budget which sets forth certain anticipated services related to the Lost Hills Project or the Blackwell Project, as appropriate, not otherwise covered by the fixed-fee scope of the respective agreement.

Compensation.    As consideration for the performance of O&M services under the Lost Hills O&M Agreement and the Blackwell O&M Agreement, FSEC receives an annual service fee, paid in quarterly installments, subject to an escalator. Additionally, each of the Lost Hills Project Entity and the Blackwell Project Entity is required to pay FSEC a one-time mobilization fee under its O&M agreement.

Termination.    Each party to the Lost Hills Blackwell O&M Agreements has the right to terminate the relevant O&M agreement if any of the following events occur:

Additionally, each party to the Lost Hills Blackwell O&M Agreements has the right to terminate the applicable O&M agreement if any of the following events shall occur with respect to the other party (or, in the case of the Lost Hills Project Entity or the Blackwell Project Entity, to First Solar, in its capacity as guarantor of FSEC under such agreements):

The Lost Hills Project Entity and the Blackwell Project Entity may also terminate the applicable O&M agreement:

Either party may also terminate the relevant Lost Hills Blackwell O&M Agreement if FSEC is prevented from performing its obligations for a period of 12 consecutive months due to the occurrence of certain events related to changes in law, industry standards, federal requirements, amendments to project agreements, curtailment of the Lost Hills Project or the Blackwell Project, as appropriate, or the unavailability of spare parts.

North Star Project

The North Star Project Entity entered into an Operation & Maintenance Agreement dated as of April 30, 2015 (the “North Star O&M Agreement”), with FSEC. Similar to the Lost Hills Blackwell O&M Agreements, FSEC’s obligations under the North Star O&M Agreement are supported by a parent guaranty agreement issued by First Solar for the benefit of the North Star Project Entity.

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The North Star O&M Agreement reflects terms and conditions similar to those with respect to the Lost Hills Blackwell O&M Agreement, as described above.

Solar Gen 2 Project

The Solar Gen 2 Project Entity and FSEC entered into an Operation & Maintenance Agreement (the “Solar Gen 2 O&M Agreement”), as of October 22, 2014. FSEC’s obligations under the Solar Gen 2 O&M Agreement are supported by a parent guaranty agreement issued by First Solar for the benefit of the Solar Gen 2 Project Entity. The Solar Gen 2 O&M Agreement reflects terms and conditions similar to those described above with respect to the Lost Hills Blackwell O&M Agreements.

SunPower Projects

Quinto Project

The Quinto Project Entity entered into an Operation & Maintenance Agreement (the “Quinto O&M Agreement”), dated as of October 6, 2014, with SunPower Systems (“Quinto Operator”), an affiliate of the Quinto Project Entity.

Term.    The Quinto O&M Agreement has a term of five years, which is renewable for three additional five-year periods, at the option of the Quinto Project Entity, unless the Quinto Project Entity has defaulted under the agreement or there is a pending dispute under the agreement between the parties thereto.

Services.    Quinto Operator provides all day-to-day facility and O&M services, including:

Quinto Operator must provide a proposed budget to the Quinto Project Entity, with respect to any additional services related to the Quinto Project that are not covered by the Quinto O&M Agreement.

Compensation.    In consideration for the performance of O&M services, the Quinto Operator receives a fixed annual fee paid in quarterly installments. The Quinto Project Entity is also responsible for paying the Quinto Operator for any additional services and emergency services.

Termination.    Either party may terminate the Quinto O&M Agreement if (i) there is a material default thereunder by the other party that is not cured during the applicable cure period, (ii) the Quinto EPC Contract (as defined below under “—Performance and Limited Warranties”) is terminated prior to the substantial completion date or (iii) a force majeure event occurs which prevents Quinto Operator from providing a material part of the services that Quinto Operator is required to perform under the Quinto O&M Agreement

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for a continuous period of at least 180 days. In addition, Quinto Operator may terminate the Quinto O&M Agreement if any of the following events occur:

The Quinto Project Entity may also terminate the agreement if any of the following events occur:

UC Davis Project

On June 19, 2015, the UC Davis Project Entity has entered into an Operation & Maintenance Agreement (the “UC Davis O&M Agreement”), with SunPower Systems (“UC Davis Operator”), an affiliate of the UC Davis Project Entity.

Term.    The UC Davis O&M Agreement has a term of five years, which will be automatically extended for one additional five-year period, unless the UC Davis Project Entity provides written notice no later than six months prior to the expiration of the initial term that the UC Davis Project Entity does not extend the term.

Services.    UC Davis Operator provides all day-to-day facility and O&M services, including:

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UC Davis Operator also provides additional operational and maintenance services not included in the subscription services on a transactional basis. If the UC Davis Project Entity requests that UC Davis Operator provide additional transactional services, UC Davis Operator and the UC Davis Project Entity will discuss the scope of services and execute a purchase order for such services.

Compensation.    In consideration for the performance of O&M services, UC Davis Operator receives a fixed annual fee paid in equal quarterly installments. The UC Davis Project Entity is also responsible for paying the UC Davis Operator for any additional services and emergency services.

Termination.    The UC Davis Project Entity may terminate the UC Davis O&M Agreement without cause by giving UC Davis Operator ninety days written notice. Either party may terminate if the other party defaults in the performance of any obligation under the UC Davis O&M Agreement and the default is not cured during a thirty-day cure period after written notice of default; provided that if the default cannot reasonably be remedied within such thirty day period and the defaulting party exercises diligent efforts to cure the default the cure period may be extended up to ninety days. Either party may suspend performance under the UC Davis O&M Agreement if the other party fails to pay any amounts due within three business days after notice and either party may terminate if the other party fails to pay any amounts due if such failure remains uncured for thirty days following notice. The UC Davis O&M Agreement terminates immediately upon (i) the dissolution or termination of the corporate or partnership existence of a party or (ii) the bankruptcy, insolvency, receivership, or assignment for the benefit of the creditors of a party, or any general partner of such party that remains undismissed or unstayed for a period of sixty days. Termination of the UC Davis O&M Agreement will not affect any rights or obligations between the parties accruing prior to the date of such termination or which expressly or by implication are intended to survive termination.

Warranties.    For services performed during the final year of the initial term and, if applicable, the final year of each renewal term, the UC Davis Operator 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.

Macy’s Project

On June 19, 2015, the Macy’s Project Entities entered into an Operation & Maintenance Agreement with SunPower Systems, an affiliate of the Macy’s Project Entities, under terms and conditions similar to those described above with respect to the UC Davis O&M Agreement.

RPU Project

On June 8, 2015, the RPU Project Entity entered into an Operation & Maintenance Agreement with SunPower Systems, an affiliate of the RPU Project Entity, under terms and conditions similar to those described above with respect to the UC Davis O&M Agreement.

Residential Portfolio

On May 4, 2015, our Residential Portfolio entered into a Maintenance Services Agreement (the “Residential Portfolio Maintenance Agreement”) with SunPower Systems, an affiliate of the Residential Portfolio Project Entity. Under the Residential Portfolio Maintenance Agreement, SunPower Systems maintains the projects under each customer lease and guarantees that each

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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.

Term.    The term is concurrent with each customer lease in the Residential Portfolio.

Services.    SunPower Systems provides the following maintenance services:

Compensation.    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 Maintenance Services 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. The fee will be based on the year during the term of the Maintenance Services Agreement in which the lease agreement is executed for each PV system.

Warranty Claims.    To the extent that manufacturer warranties cover replacement and/or repair of covered equipment during the term, SunPower Systems is required to use commercially reasonable efforts to submit, process and pursue, at SunPower Systems’ sole cost and expense, warranty coverage; provided, however, that if the Residential Portfolio Project Entity is required to submit warranty claims in its own name, the Residential Portfolio Project Entity shall provide such full and complete cooperation as SunPower Systems may reasonably require in connection with the submission, processing and pursuit of warranty coverage.

Termination.    The Residential Portfolio Project Entity may terminate the agreement at any time by giving 90 calendar days written notice.

The Residential Portfolio Project Entity may terminate the agreement, in whole or in part with respect to one or more projects in the Residential Portfolio, if any of the following occurs: (i) SunPower Systems becomes insolvent; (ii) a material deterioration of the financial situation/solidity of SunPower Systems occurs, as evidenced by a failure to pay substantial amounts to other creditors for a material period of time or a serious threat that a petition in bankruptcy will be filed against SunPower Systems; (iii) any failure by SunPower Systems to perform any of its material obligations under the agreement, which failure is not remedied within the cure period; (iv) a force majeure event occurs which prevents SunPower Systems from providing a material part of the services for a continuous period of at least 180 calendar days and the Residential Portfolio Project Entity reasonably concludes that prevention is not reasonably likely to be remedies within a further period of 180 calendar days; (v) SunPower Systems ceases to be engaged in the business of providing, servicing, monitoring and maintenance of PV systems; and (vi) any representation, warranty or covenant of SunPower Systems is incorrect in any material respect and results in a material adverse effect with respect to a material portion of the PV systems or SunPower Systems.

SunPower Systems may terminate the agreement if (i) the Residential Portfolio Project Entity becomes insolvent; or (ii) a material breach by the Residential Portfolio Project Entity of any of its obligations under the agreement which, if not a payment breach, is not remedied within the cure period.

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Asset Management Agreements

First Solar Projects

On June 17, 2015, certain First Solar Project Entities entered into separate AMAs, with First Solar Asset Management, LLC (“FSAM”), a wholly-owned direct subsidiary of First Solar. An AMA was entered into between FSAM and each of the Maryland Solar Project Entity, FSAM Lost Hills Blackwell Holdings, LLC, FSAM NS Holdings, LLC and FSAM SG2 Holdings, LLC. Each AMA is effective for an initial term of one year and, unless otherwise terminated, will extend automatically thereafter. 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):

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 is subject to an escalator.

SunPower Projects

Quinto Project

The Quinto Project Entity entered into a management agreement (the “Quinto Management Agreement”), dated as of October 6, 2014, with SunPower Capital Services, LLC (“SunPower Capital”), an affiliate of the Quinto Project Entity.

Term.    The Quinto Management Agreement has a term of five years, which may be renewed for three additional five-year periods, at the option of the Quinto Project Entity unless the Quinto Project Entity has defaulted under the agreement or there is a pending dispute under the agreement between the parties thereto.

Services.    SunPower Capital shall provide management services to the Quinto Project Entity, including the following:

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Budget.    SunPower Capital must provide a proposed annual budget to the Quinto Project Entity for its review no later than 90 days prior to the end of each fiscal year. Such budget is agreed upon between the Quinto Project Entity and SunPower Capital.

Compensation.    In consideration for the performance of the Quinto Management Agreement, SunPower Capital receives a fixed annual fee paid in quarterly installments. In addition to the fixed annual fee, SunPower Capital is entitled to be reimbursed for costs actually incurred by SunPower Capital in the performance of its duties in accordance with the approved budget, including overhead and internal expense and amounts due to subcontractors.

Termination.    Either party may terminate the Quinto Management Agreement if there is a material default thereunder by the other party that is not cured during the applicable cure period. In addition, the Quinto Project Entity may terminate the Quinto Management Agreement if any of the following events occur:

SunPower Capital may also terminate the agreement if any of the following events occur:

UC Davis Project

On June 19, 2015, the UC Davis Project Entity entered into a management agreement (the “UC Davis Management Agreement”) with SunPower Capital, an affiliate of the UC Davis Project Entity.

Term.    The term of the UC Davis Management Agreement continues until the termination or expiration of the UC Davis PPA.

Services.    SunPower Capital provides management services to the UC Davis Project Entity, including the following:

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Budget.    SunPower Capital is required to provide a proposed annual budget to the UC Davis Project Entity for its review no later than 90 days prior to the end of each calendar year. Such budget is to be agreed upon between the UC Davis Project Entity and SunPower Capital.

Compensation.    In consideration for the performance of management services, SunPower Capital receives a fixed annual fee paid in equal quarterly installments. Beginning on the fifth full quarter of the term, the service fee will be increased annually by the greater of two and one half percent (2.5%) or the increase in the U.S. Department of Labor’s Employment Cost Index. The UC Davis Project Entity is also responsible for reimbursing SunPower Capital for actual costs reasonably incurred in performance of its duties in accordance with the approved budget, including overhead and internal expense and amounts.

Termination.    Either party is permitted to terminate the agreement for convenience upon giving not less than 180 days prior written notice. In addition, the UC Davis Project Entity is permitted to terminate the management services agreement if:

In addition, SunPower Capital is permitted to terminate the management services agreement if:

Macy’s Project

On June 19, 2015, the Macy’s Project Entities entered into a management agreement with SunPower Capital under terms and conditions similar to those described above with respect to the UC Davis Management Agreement. In consideration for the performance of management services, SunPower Capital receives a fixed annual fee paid in equal quarterly installments. Beginning on the fifth full quarter of the term, the service fee will be increased annually by the greater of two and one half percent (2.5%) or the increase in the U.S. Department of Labor’s Employment Cost Index.

RPU Project

The RPU Project Entity entered into a management agreement with SunPower Capital, an affiliate of the RPU Project Entity, under terms and conditions similar to those described above with respect to the UC Davis Management Agreement. In consideration for the performance of management services, SunPower Capital receives a fixed annual fee paid in equal quarterly installments.

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Beginning on the fifth full quarter of the term, the service fee will be increased annually by the greater of three percent (3%) or the increase in the U.S. Department of Labor’s Employment Cost Index.

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 (“Residential Portfolio Operator”), an affiliate of the Residential Portfolio Project Entity. Under the Residential Portfolio Servicing Agreement, Residential Portfolio Operator will perform services to administer each customer lease in our Residential Portfolio, which includes billing, accounting, and enforcement of the customer leases.

Term.    The term is concurrent with each customer lease in the Residential Portfolio.

Services.    Residential Portfolio Operator provides services related to the billing, collection and enforcement of customer leases, including the following:

Compensation.    The Residential Portfolio Project Entity compensates Residential Portfolio Operator for the 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.

Termination.    The Residential Portfolio Project Entity may terminate the lease servicing agreement at any time upon providing 90 days notice. Either party may terminate if the other party becomes insolvent or a material breach of any obligation under the lease servicing agreement occurs that is not cured within the applicable cure period. Additionally, the Residential Portfolio Project Entity may terminate the lease servicing agreement if any of the following occurs: (i) a material deterioration of the financial situation/solidity of Residential Portfolio Operator occurs, as evidenced by a failure to pay substantial amounts to other creditors for a material period of time or a serious threat that a petition in bankruptcy will be filed against Residential Portfolio Operator; (ii) any failure by the Residential Portfolio Operator to perform any of its material obligations under the lease servicing agreement, which failure is not remedied within the cure period; (iii) the Residential Portfolio Operator ceases to be engaged in the business of providing customer support and administrative services for PV systems; and (iv) any representation, warranty or covenant of the Residential Portfolio Operator is incorrect in any material respect and results in a material adverse effect with respect to a material portion of the PV systems or the Residential Portfolio Operator.

Performance and Limited Warranties

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First Solar Projects

North Star Project

The North Star Project Entity and First Solar entered into a limited warranty agreement (the “North Star Limited Warranty Agreement”), as of April 30, 2015. Under the North Star Limited Warranty Agreement, First Solar has issued certain warranties regarding the North Star Project’s solar modules.

Workmanship Warranty.    Under the North Star Limited Warranty Agreement, First Solar provides a ten-year limited warranty that (i) each module will be new and unused when originally installed at the North Star Project pursuant to the North Star EPC Contract and (ii) each module will be free from defects in materials and workmanship, excluding degradation-related power output defects.

System Performance Warranty.     In addition, First Solar will provide a 25-year limited warranty that actual energy performance shall meet or exceed the projected energy output of the North Star 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 the North Star 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 North Star Project Entity liquidated damages.

Solar Gen 2 Project

The Solar Gen 2 Project Entity and First Solar entered into a limited warranty agreement (the “Solar Gen 2 Limited Warranty Agreement”), as of October 22, 2014. The Solar Gen 2 Limited Warranty Agreement reflects terms and conditions similar to those described above with respect to the North Star Limited Warranty Agreement.

SunPower Projects

Quinto Project

The Quinto Project Entity entered into a performance warranty agreement (the “Quinto Performance Agreement,”) dated as of October 6, 2014, with Quinto Operator, an affiliate of the Quinto Project Entity.

Term and Termination.    The Quinto Performance Agreement automatically terminates concurrent with the termination of the Quinto O&M Agreement.

Guaranty.     Quinto Operator guarantees to the Quinto Project Entity that the actual solar energy generation during each 24-month period shall not be less than 95% of the Quinto Project’s expected (ac) electricity generation for such period.

Compensation.     To the extent that the Quinto Project generates less than the expected amount of electricity, Quinto Operator must compensate the Quinto Project Entity for performance liquidated damages.

The Quinto Project Entity entered into an engineering, procurement and construction agreement (the “Quinto EPC Contract”), dated as of October 6, 2014, with SunPower Systems (the “Quinto Contractor”).

Warranties.     Under the Quinto EPC Contract, the Quinto Contractor provides a limited warranty that the Quinto 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 Quinto Project facility); (iii) in substantial conformance with the technical specifications set forth in the Quinto 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:

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If the Quinto Project manifests a defect during the warranty period, the Quinto Contractor, at its own cost and expense, shall refinish, repair or replace, at its option, such non-conforming or defective part of the Quinto Project as promptly as practical.

Additionally, pursuant to the Quinto EPC Contract, SunPower has provided a limited module warranty that (i) the solar modules delivered pursuant to the Quinto EPC Contract 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 shall begin on the substantial completion date of the Quinto Project.

The module warranty does not apply to:

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 Quinto Project Entity.

Further, the Quinto Contractor has agreed to pass through to the Quinto Project Entity warranties from identified third-party manufacturers, including an inverter warranty with a warranty term of five years following the substantial completion date.

Macy’s Project

The Macy’s Project Entities entered into a performance warranty agreement (the “Macy’s Performance Agreement”), dated as of June 19, 2015, with SunPower Systems, an affiliate of the Macy’s Project Entities, under terms and conditions similar to those described above with respect to the Quinto Performance Agreement.

The Macy’s Project Entities entered into an engineering, procurement and construction agreement (the “Macy’s EPC Contract”), dated as of August 8, 2014, with SunPower Systems, an affiliate of the Macy’s Project Entities (the “Macy’s Contractor”). Pursuant to

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this Macy’s EPC Contract, the Macy’s Contractor provided a system warranty against defects in materials, construction, fabrication and workmanship.

Warranty.    Under the Macy’s EPC Contract, the Macy’s Contractor warrants that (i) materials and equipment will be new and unused as of the date of installation, (ii) on the substantial completion date, the Macy’s Project will conform to the project specifications set forth in the scope of work attached as an exhibit to the Macy’s EPC Contract and (iii) the Macy’s Project is free from defects in materials and workmanship under normal operating conditions for a period of 10 years after the substantial completion date. The warranty does not apply to damage, malfunction or degradation of the Macy’s Project to the extent:

Upon a breach of the warranty during the warranty term and upon notice from the Macy’s Project Entities of a valid warranty claim, the Macy’s Contractor, at its sole option, will either repair or replace any defective parts.

The Macy’s Contractor has further agreed to assign to the Macy’s Project Entities the applicable pass-through warranties from the Macy’s Contractor’s manufacturers, including solar modules and inverters, as identified in the design submittal prepared by the Macy’s Contractor and approved by the Macy’s Project Entities in connection with the Macy’s Project. The Macy’s Contractor warrants that materials and equipment subject to warranties of such other manufacturers have been installed in accordance with the requirements of such warranties.

Pursuant to the Macy’s EPC Contract, SunPower has provided a pass-through module warranty similar to the terms and conditions described above with respect to the Quinto Project.

UC Davis

The UC Davis Project Entity entered into a performance warranty agreement (the “UC Davis Performance Agreement”), dated as of June 19, 2015, with SunPower Systems, an affiliate of the UC Davis Project Entity, under terms and conditions similar to those described above with respect to the Quinto Performance Agreement.

The UC Davis Project Entity entered into an engineering, procurement and construction agreement (the “UC Davis EPC Contract”), dated as of May 7, 2015 with SunPower Systems, an affiliate of the UC Davis Project Entity (the “UC Davis Contractor”). Pursuant to this UC Davis EPC Contract, the UC Davis Contractor provided a system warranty against defects in materials, construction, fabrication and workmanship.

Warranty. Under the UC Davis EPC Contract, the UC Davis Contractor warrants that (i) materials and equipment will be new and unused as of the date of installation, (ii) on the substantial completion date, the UC Davis Project will conform to the project specifications set forth in the scope of work attached as an exhibit to the UC Davis EPC Contract and (iii) the UC Davis Project is free from defects in materials and workmanship under normal operating conditions for a period of two years after the substantial completion date. The warranty does not apply to damage, malfunction or degradation of the UC Davis Project to the extent:

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This warranty applies solely to the UC Davis Project and does not include (i) roof repair or maintenance or (ii) site work, including but not limited to, grading and landscape maintenance, if applicable.

Upon a breach of the warranty during the warranty term and upon notice from the UC Davis Project Entity of a valid warranty claim, the UC Davis Contractor, at its sole option, will either repair or replace any defective parts.

The UC Davis Contractor has further agreed to assign to the UC Davis Project Entity the applicable pass-through warranties from the UC Davis Contractor’s manufacturers, including solar modules and inverters, as identified in the design submittal prepared by the UC Davis Contractor and approved by the UC Davis Project Entity in connection with the UC Davis Project. The UC Davis Contractor warrants that materials and equipment subject to warranties of such other manufacturers have been installed in accordance with the requirements of such warranties.

RPU

The RPU Project Entity entered into a performance warranty agreement (the “RPU Performance Agreement”), dated June 8, 2015, with SunPower Systems, an affiliate of the RPU Project Entity. The terms and conditions of the RPU Performance Agreement are similar to those described above with respect to the Quinto Performance Agreement.

The RPU Project Entity entered into an engineering, procurement and construction agreement (the “RPU EPC Contract”), dated as of May 8, 2015 with SunPower Systems, an affiliate of the RPU Project Entity (the “RPU Contractor”). Pursuant to this RPU EPC Contract, the RPU Contractor provided a system warranty against defects in materials, construction, fabrication and workmanship.

Warranty. Under the RPU EPC Contract, the RPU Contractor warrants that (i) materials and equipment will be new and unused as of the date of installation, (ii) on the substantial completion date, the RPU Project will conform to the project specifications set forth in the scope of work attached as an exhibit to the RPU EPC Contract and (iii) the RPU Project is free from defects in materials and workmanship under normal operating conditions for a period of five years after the substantial completion date. The warranty does not apply to damage, malfunction or degradation of the RPU Project to the extent:

This warranty applies solely to the RPU Project and does not include (i) roof repair or maintenance or (ii) site work, including but not limited to, grading and landscape maintenance, if applicable.

Upon a breach of the warranty during the warranty term and upon notice from the RPU Project Entity of a valid warranty claim, the RPU Contractor, at its sole option, will either repair or replace any defective parts.

The RPU Contractor has further agreed to assign to the RPU Project Entity the applicable pass-through warranties from the RPU Contractor’s manufacturers, including solar modules and inverters, as identified in the design submittal prepared by the RPU Contractor and approved by the RPU Project Entity in connection with the RPU Project. The RPU Contractor warrants that materials and equipment subject to warranties of such other manufacturers have been installed in accordance with the requirements of such warranties.

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Additionally, pursuant to the RPU EPC Contract, SunPower Corporation has provided a 25-year limited pass-through module warranty similar to the terms and conditions described above with respect to the Quinto Project.

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 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:

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

North Star Project

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, and the Lessee is obligated to pay a fixed amount of rent.

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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 Maryland Solar PPA, the Maryland Solar O&M Agreement and the 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 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 Maryland Solar PPA 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. In addition, either party has the right to terminate the MD Solar Lease Agreement upon the occurrence of certain specified events of default, including:

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 entered into an MSA with an affiliate of SunPower and a separate, but similar, MSA with an affiliate of First Solar (collectively, the “MSAs,” and each of SunPower and First Solar, under its respective MSA, a “Service Provider”). 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”).

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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:

These activities are subject to the supervision by the governing body of the relevant Service Recipient.

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Under its MSA, the First Solar Service Provider provides, or arranges for an appropriate service provider to provide, the following services:

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, initially pays each Service Provider an annual management fee equal to $550,000 and $50,000, respectively, in the case of the First Solar MSA, and $1,050,000 and $50,000, respectively, in the case of the SunPower MSA, which amounts shall be adjusted annually for inflation. Between December 1, 2015 and November 30, 2016, each Service Provider has a one-time right to increase the management fee by an amount not to exceed 15% in the event such Service Provider’s cost to provide the services under its MSA exceeds the amount of the management fee. The management fee is paid in monthly installments.

In August 2015, the MSAs were amended to correct an error in the calculation of the annual management fee payable to each Service Provider. Pursuant thereto, the initial annual management fee payable by OpCo under the First Solar MSA was amended to $600,000 and the initial annual management fee payable by OpCo under the SunPower MSA was amended to $1,100,000.

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.

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Such out of pocket fees, costs and expenses include, among other things:

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 of directors.

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Each Service Provider may terminate its applicable MSA, effective 30 days after written notice:

Omnibus Agreement

We entered into an omnibus agreement (the “Omnibus Agreement”), with First Solar, SunPower, our general partner, OpCo and Holdings. Pursuant to the Omnibus Agreement, (i) each Sponsor was granted 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 closing of the IPO, 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, (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. Moreover, 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 contributed Project Entity of 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 our general partner’s board of directors 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.

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Undertakings Related to Commercial Operation; Liquidated Damages

Pursuant to the Omnibus Agreement, to the extent any project in the Portfolio has not achieved commercial operation, 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. The Omnibus Agreement also provides that, if a project in the Portfolio fails to achieve commercial operation on or prior to an agreed deadline (to be set forth in the Omnibus Agreement), the applicable contributing Sponsor is required to pay OpCo delay liquidated damages, the amount of which will be 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.

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 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 August 2015, the Omnibus Agreement was amended to provide that, 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 project at the time of contribution 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.  In addition, in November 2015, the Omnibus Agreement was further amended to revise the existing indemnity for energy produced prior to commercial operation owed by each Sponsor to OpCo to calculate such indemnity on an aggregate basis with respect to all projects contributed by such Sponsor in connection with IPO, rather than on a project-by project basis.

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 First Solar Project Entities or the SunPower Project Entities, as applicable:

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The Exemption Loss Indemnity and the Reassessment Indemnity will cease to apply to the Residential Portfolio as of the third anniversary of the completion of the IPO. 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 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 will be 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.

In addition, in August 2015, the Omnibus Agreement was amended to provide that SunPower will indemnify OpCo for certain costs it may incur in connection with the termination of certain tax equity financing arrangements relating the contributed residential lease portfolios, which occurred before the IPO.

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 a Promissory Note to First Solar in the principal amount of $1,964,148.48 (the “Note”), 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 that is expected to be completed by the end of the first quarter of fiscal 2016 (each, a “Specified Payment”), OpCo is obligated to repay a portion of the principal amount of the Note equal to such Specified Payment and the unpaid balance of all interest accrued under the Note to and including the date of such repayment. Interest will accrue at a rate of 1% on the portion of the principal of the Note equal to the amount of each Specified Payment from the date SDG&E remits such payment to the Solar Gen 2 Project Entity through the date that OpCo repays such amount to First Solar in accordance with the previous sentence. OpCo is permitted to prepay the Note at any time without penalty or premium.

ROFO Agreements

OpCo entered into a ROFO Agreement with each of First Solar and SunPower. Under its ROFO Agreement, the applicable Sponsor granted OpCo a right of first offer to purchase any of its ROFO Projects in the event of any proposed sale, transfer or other disposition of such ROFO Projects, or any portion thereof, for a period of five years following the completion of the IPO.

Prior to engaging in any negotiation regarding any disposition, sale or other transfer of any ROFO Project, or any portion thereof, to a third party, the applicable Sponsor will deliver a written notice to OpCo setting forth the material terms and conditions of the proposed transaction. During the 45-day period commencing with delivery of such notice, if OpCo exercises its right, OpCo and such Sponsor will negotiate in good faith to reach an agreement on a transaction with respect to such ROFO Project. If an agreement is not reached within such 45-day period, such Sponsor will be permitted, within the next 180 days, to sell, transfer or otherwise dispose of such ROFO Project to a third party (or agree in writing to undertake such transaction) on terms generally no less favorable to such Sponsor, and at a price no less than the price offered, under the original written notice.

Notwithstanding the above, certain sales and transfers of the ROFO Projects by the applicable Sponsor are exempt from OpCo’s right of first offer. These exceptions include:

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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 ROFO Project from the Sponsor or its affiliate in accordance with the terms of the applicable ROFO Agreement if and when the Sponsor elects to sell, transfer or otherwise dispose of such ROFO Project to a third party.

Under each ROFO Agreement, the applicable Sponsor is not obligated to sell its respective 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 the applicable Sponsor may not reach an agreement on the terms for the sale of the applicable ROFO Project.

Commencing July 1, 2016, each Sponsor shall have the right to remove a ROFO Project from their respective ROFO Agreement, to the extent such applicable Sponsor sells or contributes a non-ROFO Project to OpCo for which forecasted distributed cash is projected to equal or exceed the forecasted distributed cash of such ROFO Project proposed for removal. Under the ROFO Agreements, OpCo has a 30-day period to review the calculation of forecasted distributed cash for such replacement ROFO Project. At the end of this period, if OpCo disputes items in the calculation, then the applicable Sponsor and OpCo will attempt to resolve any disputed items in good faith. Failing such resolution, an independent valuation expert shall be engaged to resolve such dispute.

The applicable Sponsor or OpCo, as the case may be, may terminate the applicable ROFO Agreement (i) upon written notice, if the other party materially breaches or defaults in the performance of its obligations under the ROFO Agreement, or (ii) with respect to any ROFO Project, if the other party materially breaches or defaults in the performance of its obligations under any transaction agreement for the sale of such ROFO Project to OpCo, provided that, in each case, the breach or default remains unremedied for 30 days. The Sponsor also has the right to terminate the ROFO Agreement at any time after (i) our general partner withdraws, (ii) our general partner is removed from such position and no shares held by either Sponsor or their affiliates voted in favor or such removal or (iii) such Sponsor fails to own, directly or indirectly, at least 50% of the management units of Holdings.

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 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 it acquires.

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Equity Purchase Agreement

We have entered into the Equity Purchase Agreement with OpCo, under which we used all of the net proceeds from the IPO to purchase 20,000,000 of OpCo’s common units from OpCo and OpCo issued a non-economic managing member interest to us. OpCo used, or will use, the funds it received under the Equity Purchase Agreement to make distributions to our Sponsors and for general purposes, including to fund future acquisition opportunities.

Master Formation Agreement

First Solar and SunPower entered into a master formation agreement to form a joint venture to indirectly own, operate and acquire solar energy systems. Such master formation agreement provided for the formation of Holdings, the principal joint venture entity, us, our general partner and OpCo, including the respective organizational documents. In addition, the master formation agreement provided for the initial contributions of the First Solar Project Entities and the SunPower Project Entities by our Sponsors. As part of such contributions, our Sponsors made standard representations and warranties to each other regarding their respective Project Entities and agreed to indemnify each other for certain matters.

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 our general partner’s board of directors. If, after applying these standards, management determines that a proposed transaction is a related person transaction, management must present the proposed transaction to our general partner’s board of directors for review. The board must then either approve or reject the transaction in accordance with the terms of our Partnership Agreement. The board of our general partner may, but is not required to, seek the approval of the conflicts committee for the resolution of any related person transaction.

Item 14. Principal Accounting Fees and Services.

The following table presents fees for professional accounting and other related services rendered by PricewaterhouseCoopers LLP for the eleven months ended November 30, 2015.

 

 

In accordance with the requirements of the Sarbanes-Oxley Act, the audit committee charter and the audit committee’s pre-approval policy for services provided by the independent registered public accounting firm, all services performed by PricewaterhouseCoopers LLP are approved in advance by the audit committee. In addition, the audit committee approves all services other than audit and audit-related services performed by PricewaterhouseCoopers LLP in advance of the commencement of such work. 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.

 

 

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PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) The following documents are filed as a part of this Transition Report on Form 10-K.

(1) Financial Statements:

Report of Independent Registered Public Accounting Firm

Financial Statements: See Index to Financial Statements below.

(2) Financial Statement Schedule:

The consolidated financial statements of SG2 Holdings and North Star Holdings, 49% owned equity method investees, 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, 2016. These financial statements will be audited as of December 31, 2015 and prepared in accordance with GAAP.

(3) Exhibits: See Item 15(b) below.

 

(b) Exhibits: The exhibits listed on the accompanying Index to Exhibits on this Transition Report on Form 10-K are filed, furnished, or incorporated into this Transition Report on Form 10-K by reference, as applicable.

 

(c) Financial Statement Schedule: See Item 15(a) above.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

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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 sheet and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity and cash flows present fairly, in all material respects, the financial position of 8point3 Energy Partners LP and its subsidiary (the "Company") at November 30, 2015, and the results of their operations and their cash flows for 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 Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these 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 audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

 

San Jose, California

January 27, 2016

 

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Report of Independent Registered Public Accounting Firm

 

 

To Management of SunPower Corporation:

 

We have audited the accompanying combined carve-out balance sheets of Select Project Entities and Leases of SunPower Corporation (Predecessor) as of December 28, 2014, and the related combined carve-out statements of operations and comprehensive loss, changes of equity and cash flows for the years ended December 28, 2014 and December 29, 2013. These financial statements are the responsibility of the management of SunPower Corporation. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits 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. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Predecessor’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the statements referred to above present fairly, in all material respects, the combined financial position of Select Project Entities and Leases of SunPower Corporation at December 28, 2014, and the combined results of their operations and their cash flows for each of the two years in the period then ended, in conformity with U.S. generally accepted accounting principles.

 

Ernst & Young LLP

 

San Jose, CA

March 10, 2015

 

 

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8point3 Energy Partners LP

Consolidated Balance Sheets

(In thousands, except share data)

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

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8point3 Energy Partners LP

Consolidated Statements of Operations

(In thousands, except share data)

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

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8point3 Energy Partners LP

Consolidated Statements of Comprehensive Income (Loss)

(In thousands, except share data)

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

 

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8point3 Energy Partners LP

Consolidated Statements of Shareholders’ Equity

(In thousands, except share data)

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

 

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8point3 Energy Partners LP

Consolidated Statements of Cash Flows

(In thousands, except share data)

 

 

 

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 and Summary of Significant Accounting Policies

The Partnership

8point3 Energy Partners LP (together with its subsidiaries, the “Partnership”) is a limited partnership formed on March 10, 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 initial public offering (the “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, 2015, 8point3 Energy Partners LP owned a controlling non-economic managing member interest in 8point3 Operating Company, LLC (“OpCo”) and a 28.2% limited liability company interest in OpCo and the Sponsors collectively owned a noncontrolling 71.8% limited liability company interest in OpCo.

The following table provides an overview of the assets that comprise the Partnership’s portfolio (the “Portfolio”):

 

 

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements — Continued

 

Basis of Presentation and Preparation

The direct and indirect contributions of the Project Entities (as defined below) by the Sponsors to OpCo in connection with the IPO resulted in a business combination for accounting purposes with the SunPower Project Entities (as defined below) being considered the acquirer of the interests contributed by First Solar in the First Solar Project Entities (as defined below). Therefore, the SunPower Project Entities constitute the “Predecessor.” As used herein, the term “Project Entities” refers to:

In connection with the IPO, SunPower contributed a nearly 100% interest in each of the SunPower Project Entities to OpCo, subject, in the case of the Quinto Project, the RPU Project, the UC Davis Project and the Macy’s 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.

The consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (“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. All significant inter-entity accounts and transactions have been eliminated in consolidation.

For all periods prior to the IPO, the accompanying consolidated financial statements and the notes thereto represent the results of the condensed combined carve-out statements of the Predecessor and were prepared using SunPower’s historical basis in assets and

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements — Continued

 

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 condensed combined carve-out financial statements, the Predecessor did not exist as a separate, legally constituted entity. The Predecessor’s condensed 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.

Reclassifications

Certain prior period balances have been reclassified to conform to the current period presentation in the Partnership's consolidated financial statements and the accompanying notes. Such reclassifications had no effect on previously reported results of operations or accumulated earnings (deficit).

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. Its 2014 fiscal year ended on December 28, 2014 and its 2013 fiscal year ended on December 29, 2013, each of which were 52-week fiscal years. Each of the fiscal quarters in the fiscal years 2014 and 2013 comprised 13 weeks. The first quarter and second quarter of fiscal 2015 ended on March 29, 2015 and June 28, 2015, respectively, and comprised 13 weeks. The third quarter of fiscal 2015 includes the period from June 1, 2015 to August 31, 2015, and the fourth quarter of fiscal 2015 includes the period from September 1, 2015 to November 30, 2015, consistent with the Partnership’s November 30 fiscal year end.

The accompanying consolidated financial statements cover the period from December 29, 2014 through November 30, 2015, representing the entire eleven-month period of the Partnership’s recently adopted fiscal year. The prior year’s comparable twelve-month periods cover the periods from December 30, 2013 through December 28, 2014 and is reported on the basis of the previous fiscal year end of the Partnership’s Predecessor. 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 eleven months ended November 30, 2014 and November 30, 2013 have not been included in this Form 10-K for the following reasons: (i) the years ended December 28, 2014 and December 29, 2013 provide as meaningful a comparison to the eleven months ended November 30, 2015 as would the eleven months ended November 30, 2014 and November 30,2013; (ii) we believe that there are no significant factors, seasonal or other, that would impact the comparability of information if the results for the eleven months ended November 30, 2014 and November 30, 2013 were presented in lieu of results for the years ended December 28, 2014 and December 29, 2013; 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, including: allowances for doubtful accounts related to accounts receivable and financing receivables; estimates for future cash flows and economic useful lives of property and equipment; the fair value and residual value of leased solar energy systems; fair value of financial instruments; valuation of certain accrued liabilities such as accrued warranty and asset retirement obligation; 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 condensed consolidated balance sheets. 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 our 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.

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements — Continued

 

For the eleven months ended November 30, 2015, $2.5 million has been deferred and capitalized, and $1.6 million has been expensed as part of selling, general and administrative (“SG&A”) expenses.

 

 

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 the year ended December 28, 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 are excluded from earnings and reported as a component of accumulated other comprehensive loss in the condensed consolidated balance sheets. The ineffective portion of derivatives financial instruments are included in other expense (income), net in the condensed 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 the eleven months ended November 30, 2015, no impairment losses were recorded related to the Partnership’s equity method investments.

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, 2015. Highly liquid investments with original or remaining maturities of 90 days or less at the time of purchase are considered cash equivalents.

Accounts Receivable and Financing Receivable

Accounts receivable:    Accounts receivable are reported on the condensed 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 November 30, 2015 and December 28, 2014, no allowance for doubtful accounts related to operating leases had been recorded.

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements — Continued

 

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 energy 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 bases such reserves on several factors, including consideration of historical credit losses. As of November 30, 2015 and December 28, 2014, $0.3 million and zero, respectively, had been recorded as allowance for losses on financing receivables.

Property and Equipment

Property and equipment, including photovoltaic (“PV”) solar power systems, are stated at cost, less accumulated depreciation. Leased solar energy systems are depreciated to their estimated residual value using the straight-line method over the lease term of 20 years. Any energy generated by PV 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. Depreciation expense for PV 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 energy systems is 30 years and all systems are physically located in the United States. Depreciation expense for the eleven months ended November 30, 2015 was $4.3 million, and was $2.3 million and $3.2 million for the years ended December 28, 2014 and December 29, 2013, respectively. Repairs and maintenance costs are expensed as incurred.

Construction-in-Progress

Projects comprised of solar energy systems yet to be leased to residential homeowners and 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 energy systems include lease asset depreciation expense greater than associated operating revenue, decrease in the estimated residual value of the leased solar energy 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 energy 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 either quoted market prices, if available, or discounted cash flow analyses.

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 or the selling price of the electricity to decrease.

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 during the eleven months ended November 30, 2015 was $6.5 million, and during the years ended December 28, 2014 and December 29, 2013, was $2.8 million and $0.9 million, respectively.

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements — Continued

 

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 energy systems at the end of the term of the agreement. The Partnership accounts for such legal obligations or asset retirement obligations (“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, plant 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 $10.0 million as of November 30, 2015. The Predecessor had not accrued any AROs as of December 28, 2014 since it had not significantly commenced construction on any of the projects on the sites.

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 operations and maintenance (“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, 2015, the Partnership recorded $0.9 million 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.

Product Warranties

The Sponsors as the manufacturers generally warrant the performance of the solar panels that they manufacture at certain levels of power output for 25 years. In addition, long-term warranties from the original equipment manufacturers of certain system components, such as inverters, are passed through to customers. Warranties of 25 years from solar panel suppliers are standard in the solar industry, while inverters typically carry warranty periods ranging from five to 10 years. In addition, the Sponsors as providers of engineering, procurement and construction (“EPC”) services generally warrant the workmanship on installed systems for periods ranging up to 10 years, and the Sponsors as providers of O&M services pursuant to the O&M agreements also provide system output performance warranties or availability guarantees. The Predecessor recorded product warranty reserve in connection with the sales-type leases based on its best estimate of such costs and recognized it as a cost of operations. Since the Partnership receives product warranties from its original equipment manufacturers, it no longer records product warranties on its consolidated financial statements as of November 30, 2015.

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.

All operating revenues for the eleven months ended November 30, 2015 and the years ended December 28, 2014 and December 29, 2013 were from customers located in the United States. Operating revenues from a customer accounted for 21% of total operating revenues for the eleven months ended November 30, 2015.

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Revenue Recognition

Power Purchase Agreements:    Revenue is generated from the sale of energy to various non-affiliated parties under long-term PPAs. Amounts are recognized as revenue based on rates stipulated in the respective PPAs when energy and any related renewable energy attributes are delivered.

Sales-type leases:    Certain residential leased solar energy systems are classified as sales-type leases because the net present value (“NPV”) of the minimum lease payments per the contract, excluding the portion of payments representing executory costs, equals or exceeds 90% of the excess of the fair value of the leased property to the lessor at lease inception. For such solar energy systems, the NPV of the minimum lease payments, net of executory costs, is recognized as revenue when the lease is placed in service. This NPV includes fixed and determinable state or local rebates defined in the minimum lease payments under the lease but excludes performance-based incentives (“PBI Rebates”) because these rebates are not fixed and determinable as they relate to the generation of electricity from the leased solar energy system, and therefore represent contingent revenue recognized upon cash receipt. This NPV, as well as that of the residual value of the lease at termination, are recorded as financing receivables in the condensed consolidated balance sheets. The difference between the initial net amounts and the 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 energy system is recognized on a straight-line basis over the 20-year lease term. The residual values of solar energy systems are determined at the inception of the lease applying an estimated system fair value at the end of the lease term. As all the leases owned by the Predecessor have been placed into service before fiscal 2015, all revenue related to the NPV of the minimum lease payments has been recognized as of December 28, 2014. Accordingly, other than interest revenue, there was no sales-type lease revenue recognized on the consolidated financial statements for the eleven months ended November 30, 2015.

Operating leases:    For those residential systems classified as operating leases, revenue associated with renting the solar energy 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 condensed 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. 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. Revenue generated primarily from various non-affiliated parties under long-term PPA contracts are accounted for as operating leases.

Operating revenues to date are comprised of revenues generated from power purchase agreements, solar energy systems leased to residential customers and lease revenue from the Maryland Solar Project. The Partnership is the lessor while the residential customers and an affiliate of First Solar are the lessees.

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 Sponsor’s 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 hypothetical liquidation at book value method (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 condensed consolidated balance sheets. 

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 energy system is placed in service or sold. Cost recognized on sales-type leases includes initial direct

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costs to complete a leased solar energy system, such as costs for constructing a solar energy system inclusive of dealer payments, freight charges and direct lease costs.

Income Taxes

Deferred tax assets and liabilities are recognized for temporary differences between financial statement and income tax bases of assets and liabilities. 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.

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 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.

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.

The Partnership records uncertain tax positions in accordance with ASC 740, Income Taxes, 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 acquired assets and liabilities 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 costs that are not part of the consideration to SG&A expense as they are incurred. These costs typically include transaction and integration costs, such as legal, accounting, and other professional fees.

Share-Based Compensation Expense

The Partnership measures compensation expense for all share-based payment awards based on estimated 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, less estimated forfeitures. Share-based compensation expense for the eleven months ended November 30, 2015 were $0.1 million and were included in SG&A expense.

Recent Accounting Pronouncements

In November 2015, the Financial Accounting Standards Board (the “FASB”) issued an update which requires entities that present a classified balance sheet to classify all deferred taxes as noncurrent assets or noncurrent liabilities. The new guidance is

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effective for the Partnership for annual periods beginning after December 15, 2016. Early adoption of this standard is permitted. The Partnership is evaluating the potential impact of this standard on its consolidated financial statements and disclosures.

 

In September 2015, the FASB issued an update to the business combination standards to eliminate the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. Instead, an acquirer must recognize measurement-period adjustments during the period in which it determines the amounts, including the effect on earnings of any amounts that would have been recorded in previous periods if the accounting had been completed at the acquisition date.  The new guidance is effective for the Partnership no later than the first quarter of fiscal 2016 and requires a prospective approach to adoption.  Early adoption of this standard is permitted. The Partnership adopted the standard effective January 1, 2016 and the adoption of this standard did not impact the Partnership's results of operations, cash flows or financial position.

 

In April 2015, the FASB issued an update to the standards for the presentation of debt issuance costs to reduce complexity in accounting standards and to align with International Financial Reporting Standards. The updated standard requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. U.S. GAAP previously required debt issuance costs to be reflected as an asset on the Partnership’s balance sheet. The new debt issuance cost guidance is effective for the Partnership no later than the first quarter of fiscal 2016 and requires a retrospective approach to adoption. The Partnership has elected early adoption of the updated accounting standard, effective in the second quarter of fiscal 2015. There is no reclassification required as there was no debt issuance cost that was recorded as an asset in the prior periods.

In February 2015, the FASB issued a new standard which modifies existing consolidation guidance for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The new consolidation guidance is effective for the Partnership in the first quarter of 2016 and requires either a retrospective or a modified retrospective approach to adoption. Early adoption of this standard is permitted. The Partnership adopted the standard effective January 1, 2016 and the adoption of this standard did not impact the Partnership's results of operations, cash flows or financial position.

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. In August 2015, the FASB deferred the effective date of this standard for all entities by one year. The new revenue recognition standard becomes effective for the Partnership in the first quarter of fiscal 2019, and is to be applied retrospectively using one of two prescribed methods. The Partnership is evaluating the application method and impact on its consolidated financial statements and disclosures.

 

 

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. For the acquisitions completed during the eleven months ended November 30, 2015, the Partnership obtained valuations from a third-party valuation specialist. The valuations calculated from these estimates were based on information available at the acquisition date. Therefore, the Partnership’s purchase price allocations are final and not subject to revision.

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, each of which is described in more detail below:

Maryland Solar

The Maryland Solar Project, located in Maryland, is a fully operational 20 MW grid-connected system contracted to serve a 20-year PPA with FirstEnergy Solutions, a subsidiary of FirstEnergy Corp.

Solar Gen 2

The Solar Gen 2 Project, located in California, is a fully operational 150 MW grid-connected system spanning three separate 50 MW sites. Electricity generated by the three separate systems is contracted to serve a 25-year PPA with San Diego Gas & Electric Company (“SDG&E”), a subsidiary of Sempra Energy.

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North Star

The North Star Project, located in California, is a fully operational 60 MW grid-connected system contracted to serve a 20-year PPA with Pacific Gas and Electric Company, a subsidiary of PG&E Corporation.

Lost Hills Blackwell

The Lost Hills Blackwell Project, located in California, is a fully operational 32 MW grid-connected system contracted to serve a 25-year PPA with Pacific Gas and Electric Company, a subsidiary of PG&E Corporation, starting in 2019. Lost Hills Blackwell is also contracted to serve a short-term PPA with the City of Roseville, California prior to the system’s PPA with Pacific Gas and Electric Company.

The purchase allocation for the acquired assets and liabilities of the above Project Entities is as follows. The purchase price 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.

 

 

The following unaudited pro forma supplementary data gives effect to the acquisitions as if the transactions had occurred on December 30, 2013. The unaudited pro forma supplementary data is provided for informational purposes only and should not be construed as indicative of the Partnership’s results of operations had the acquisitions been consummated on the date assumed or of the Partnership’s results of operations for any future date.

 

 

 

Note 4. Investment in Unconsolidated Affiliates

The Partnership obtained the fair values of its investments in unconsolidated affiliates based on an external valuation report as of the date of the IPO.

The Partnership’s investments in its unconsolidated affiliates as of November 30, 2015 are as follows:

 

 

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The following table presents summarized financial information for SG2 Holdings, LLC (“SG2 Holdings”) and NS Solar Holdings, LLC (“North Star Holdings”), significant investees, as derived from the unaudited consolidated financial statements of SG2 Holdings and North Star Holdings for the eleven months ended November 30, 2015, for the years ended December 31, 2014 and 2013, and as of November 30, 2015 and December 31, 2014:

 

 

 

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:

 

 

 

The movement in the Partnership’s allowance for losses on financing receivables is as follows:

 

 

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Current and Non-current Assets

 

 

 

Deferred revenue, net of current portion

Deferred revenue, net of current portion was $0.7 million and $10.6 million as of November 30, 2015 and December 28, 2014, respectively. Deferred rebate revenue related to state rebates as of December 28, 2014 was not carried over from the Predecessor to the Partnership.  

 

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Current and Non-current Liabilities

 

 

 

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 $1.1 million in the eleven months ended November 30, 2015, and $1.2 million and zero in the years ended December 28, 2014 and December 29, 2013, respectively, and is classified as SG&A expenses when the projects are in the construction phase and as costs of operations when the projects have commenced operations in the Partnership’s accompanying condensed consolidated statements of operations.

The total minimum lease and easement commitments at November 30, 2015 under these land use agreements are as follows:

 

 

Product Warranties 

As of November 30, 2015 and December 28, 2014, product warranties were zero and $0.8 million, respectively. These product warranties are included in the Predecessor’s combined balance sheets represent the estimate of the costs that could result from these warranties provided in connection with the sales-type leases.  Due to the pass-through nature of the warranty from SunPower as the original equipment manufacturer, warranty reserves on sale-type leases that had been allocated to the Predecessor on a carve-out basis are no longer reflected on the Partnership’s financial statements as they are an obligation of SunPower.

Solar Energy 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 $0.2 million and $0.5 million as of November 30, 2015 and December 28, 2014, respectively. The Partnership has also recorded in “Other current

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assets” amounts of $0.9 million and zero as of November 30, 2015 and December 28, 2014, respectively, relating to anticipated performance warranty reimbursements from the O&M provider.

The following table summarizes accrued solar energy systems warranty activity for the eleven months ended November 30, 2015 and year ended December 28, 2014:

 

 

Asset Retirement Obligations

The Partnership’s AROs are based on estimated third-party costs associated with the decommissioning of the applicable project assets. 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 are made over a period of time commencing at the end of the system’s life.

The following table summarizes ARO activity for the eleven months ended November 30, 2015 and the year ended December 28, 2014, respectively:

 

 

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 the eleven months ended November 30, 2015 and the years ended December 28, 2014 and December 29, 2013, there were no known environmental contingencies that required the Partnership to recognize a liability.

 

 

Note 7. Lease Agreements and Power Purchase Agreements

Lease Agreements

As of November 30, 2015, the Partnership’s consolidated financial statements include approximately 5,900 residential lease agreements which have original terms of 20 years and are classified as either operating or sales-type leases. In addition, the lease

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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, 2015:

 

 

As of November 30, 2015, future maturities of net financing receivables for sales-type leases are as follows:

 

 

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 are accounted for as operating leases, have no minimum lease payments and all of the rental income under these leases is recorded as revenue when the electricity is delivered.

 

 

Note 8. Debt and Financing Obligations

Term Loan and Revolving 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. OpCo borrowed $300.0 million under the term loan facility on June 5, 2015, which indebtedness will mature on the fifth anniversary of its issuance, at which point all amounts outstanding under the term loan facility will become due and payable. There will be no principal amortization over the term of the facility. The discount and incremental debt issuance costs associated with these borrowings were $3.1 million, which included $1.7 million of debt issuance costs paid with a portion of the proceeds and $1.4 million related to a reclassification of capitalized issuance costs on the Predecessor’s historical financial statements, and were reported as a direct deduction from the face amount of the note. The Partnership used the net proceeds of the term loan facility to pay distributions of $129.4 million to First Solar and $168.9 million to SunPower.

As of November 30, 2015, the full amount of the $300.0 million term loan facility and approximately $48.8 million of letters of credit under the revolving credit facility are outstanding. The remaining portion of the revolving credit facility and the delayed draw term loan facility are undrawn.

OpCo’s credit facility is collateralized by a pledge of the equity of OpCo and certain of its domestic subsidiaries. The Partnership and each of OpCo’s domestic subsidiaries, other than certain non-guarantor subsidiaries, have guaranteed the obligations of OpCo under the credit facility. For more details, please read Part I, Item 1A. “Risk Factors—Risks Related to Our Financial Activities”.

Loans outstanding under the credit facility will 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. The unused portion of the revolving credit facility and delayed draw

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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. Subject to certain conditions, the credit facility includes conditional borrowing capacity for incremental commitments to increase the term loan facility and the revolving credit facility by $250 million, with any increase in the revolving credit facility not to exceed $100.0 million. The term loan bears an interest rate of approximately 2.41% per annum as of November 30, 2015. OpCo has entered into interest rate swap agreements to hedge the interest rate on the borrowings under the term loan facility. For more details, please read “—Note 9. Fair Value”.

This credit facility contains covenants, including among others, requiring the Partnership to maintain the following financial ratios beginning in the fiscal quarter ending August 31, 2015: (i) a debt to cash flow ratio of not more than (a) 7.00 to 1.00 for the fiscal quarters ending August 31, 2015 through May 31, 2016, (b) 5.50 to 1.00 for the fiscal quarters ending August 31, 2016 through May 31, 2017, and (c) 5.00 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. In addition, this 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. As of November 30, 2015, the Partnership was in compliance with the debt covenants.

The following table summarizes the Partnership’s Term Loan:

 

 

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. On October 17, 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.

As of December 28, 2014, the Predecessor had outstanding borrowings of $61.5 million, and outstanding letters of credit of $3.2 million. The fee paid under the Quinto Credit Facility for the letters of credit was immaterial during the eleven months ended November 30, 2015 and the year ended December 28, 2014, respectively, and was recognized as interest expense in the condensed consolidated statement of operations.

Residential Lease Financing

The Predecessor entered into two financing arrangements under which leased solar energy 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. Non-cash interest expense is recognized on the Partnership’s condensed consolidated statements of operations using the effective interest rate method calculated at a rate of approximately 14%-15%.

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As of December 28, 2014, the Predecessor’s accrued financing fee was $1.9 million due for the undrawn commitment of the outstanding financing arrangement which is recorded in accounts payable and other accrued liabilities in the Predecessor’s balance sheet.

On January 30, 2015, the Predecessor entered into an agreement with the third-party investor for one of the residential lease financing arrangements that terminated such financing arrangement. In conjunction with the termination of the arrangement, the Predecessor paid $10.8 million to terminate the $10.1 million outstanding financing obligation.

On January 23, 2015, the Predecessor entered into an agreement with the third-party investor for the other residential lease financing arrangement that allowed the Predecessor to repay the outstanding financing obligation and terminate the associated agreements on or before September 30, 2015. This repayment was exercised on May 4, 2015. The Predecessor paid $29.0 million to terminate the $21.1 million outstanding financing obligation and $1.9 million accrued financing fee.

August 2011 Letter of Credit Facility with Deutsche Bank

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, 2015 and December 28, 2014, letters of credit issued and outstanding under the August 2011 letter of credit facility with Deutsche Bank which is available to SunPower totaled $30.7 million and $38.3 million, respectively. The associated fees incurred for the letters of credit to Deutsche Bank were $0.4 million, $0.7 million, and $0.3 million, respectively, during the eleven months ended November 30, 2015 and years ended December 28, 2014 and December 29, 2013, respectively, and were recognized as interest expense in the consolidated statements of operations.  Pursuant to the Omnibus Agreement, SunPower as the Sponsor who contributed the projects before construction was completed continued to maintain the letters of credit for these projects under this credit facility and bore the associated fees until the projects achieved COD. Since all of the SunPower contributed projects have achieved COD by November 30, 2015, SunPower is in the process of terminating the letters of credit, and the Partnership has issued the required letters of credit under its revolving credit facility.

 

 

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):

The first two levels in the hierarchy are considered observable inputs and the last is considered unobservable.  The Partnership’s cash and cash equivalents, which were held in operating bank accounts, are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the Partnership’s assets and liabilities measured at estimated fair value on a recurring basis, categorized in accordance with the fair value hierarchy:

 

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Notes to Consolidated Financial Statements — Continued

 

 

On July 17, 2015, OpCo entered into interest swap agreements intended to hedge the interest rate risk on the outstanding and forecasted future borrowings under the term loan with an aggregate notional value of $240.0 million. Under the interest rate swap agreements, OpCo will pay a fixed swap rate of interest of 1.55% and the counterparties to the agreements will pay a floating interest rate based on three-month LIBOR at quarterly intervals through the maturity date of August 31, 2018. OpCo also has 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. As of November 30, 2015, these interest rate swap agreements had not been designated as cash flow hedges. The fair value of these interest rate swap agreements have been presented in other current liabilities on the consolidated balance sheet since OpCo has the right to cancel the swap agreements within one year of the balance sheet date. During the eleven months ended November 30, 2015, the Partnership recorded a change in fair value of $0.6 million within other expense.  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 the period.

The Predecessor entered into interest rate swap agreements, designated as cash flow hedges, in the fourth quarter of the year ended December 28, 2014 on the outstanding and forecasted future borrowings under the Quinto Credit Facility to reduce the impact of changes in interest rates. As of November 30, 2015 and December 28, 2014, the Predecessor had interest rate swap agreements designated as cash flow hedges with an aggregate notional value of zero and $238.0 million, respectively. These swap agreements allowed the Predecessor to effectively convert floating-rate payments into 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 three months ended March 28, 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 the eleven months ended November 30, 2015. During the eleven months ended November 30, 2015, $5.4 million was reclassified into loss on cash flow hedges within other expense, net in the condensed consolidated statement of operations, as the transaction was terminated. During each of the years ended December 28, 2014 and December 29, 2013, zero was reclassified into loss on cash flow hedges within other expense, net in the condensed consolidated statement of operations, as the transaction was terminated.

Other Fair Value Disclosures

As of November 30, 2015, the estimated fair value of the Partnership’s long-term debt was classified within Level 2 of the fair value hierarchy and it approximated its carrying value of $297.2 million as the term loan facility is a variable rate debt with the interest rate indexed to the market and reset on a frequent and short-term basis.

 

 

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, and third-party investors under the tax equity financing facilities.  As of November 30, 2015, First Solar and SunPower had noncontrolling interests of 31.1% and 40.7%, 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 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 condensed consolidated balance sheets. As of November 30, 2015, redeemable noncontrolling interests and noncontrolling interests were $89.7 million and $11.8 million, respectively. During the eleven months ended November 30, 2015  such subsidiaries of OpCo received $203.7 million in contributions from investors under the related facilities and attributed $102.2 million in losses to the third-party investors primarily as a result of allocating certain assets, including tax credits, if any, to the investors. During the years ended December 28, 2014 and December 29, 2013, no contributions from investors were received and no losses were attributed.

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Notes to Consolidated Financial Statements — Continued

 

The following table presents the noncontrolling interest balances by entity, reported in shareholders’ equity in the consolidated balance sheets as of November 30, 2015 and December 28, 2014:

 

 

 

Note 11. Comprehensive Income (Loss)

The components of accumulated other comprehensive income (loss) and other comprehensive income (loss) excluding noncontrolling interest, are summarized as follows:

 

 

 

Note 12. 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 our 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 our 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.

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Notes to Consolidated Financial Statements — Continued

 

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. In addition, during the forbearance period, the OpCo common units, subordianted units and IDRs held by the Sponsors are not entitled to any distributions. 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 an option to purchase for 30 days after the date of the Prospectus 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 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, 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.

As of November 30, 2015, the following shares of the Partnership were outstanding:

 

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Notes to Consolidated Financial Statements — Continued

 

 

Cash Distribution

On October 15, 2015, the Partnership paid its third quarter distribution of $3.1 million to Class A shareholders for the post-IPO period from June 24, 2015 to August 31, 2015.

 

 

Note 13. 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 of directors 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).

The Partnership measures compensation expense for all share-based payment awards based on estimated 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, less estimated forfeitures. During the eleven months ended November 30, 2015, the Partnership issued an aggregate of 7,281 Class A shares to the three independent members of the board of directors. These shares were unrestricted and had no vesting period. Share-based compensation expenses for the eleven months ended November 30, 2015 were $0.1 million and were included in SG&A expense.

 

 

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Notes to Consolidated Financial Statements — Continued

 

Note 14. Net Income Per Share

Basic net income per share is computed by dividing net income from the IPO completion date of June 24, 2015 to the eleven-month period ended November 30, 2015 attributable to Class A shareholders by the weighted average number of Class A shares outstanding for the applicable periods. 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, 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 units for, subject to the approval of its conflicts committee, cash or Class A shares. If Class B shares were converted into Class A shares, the net income attributable to Class A shares would proportionately increase, resulting in no change to net income per share for the period from the IPO closing date to the eleven months ended November 30, 2015. In addition, there were no potentially dilutive securities (including any stock options, restricted stock and restricted stock units) for the eleven months ended November 30, 2015, respectively. Accordingly, basic and diluted net income per share for the eleven months ended November 30, 2015 was as follows:

 

 

 

Note 15. 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 Management Services Agreements (the “MSAs”) with affiliates of each of the Sponsors (each, a “Service Provider”). Under the MSAs, the Service Providers will 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 asset management agreements (“AMAs”) between affiliates of the Sponsors and certain of the subsidiaries of the Partnership. In August 2015, the First Solar MSA and the SunPower

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Notes to Consolidated Financial Statements — Continued

 

MSA were amended to adjust the annual management fee payable to each respective Service Provider. In the case of the First Solar MSA, OpCo will initially pay an annual management fee of $0.6 million to the First Solar Service Provider. In the case of the SunPower MSA, OpCo will initially pay an annual management fee of $1.1 million to the SunPower Service Provider. These payments are subject to annual adjustments for inflation. Between December 1, 2015 and November 30, 2016, each Service Provider will have a one-time right to increase the management fee by an amount not to exceed 15%.

Costs incurred for these services were $0.7 million for the eleven months ended November 30, 2015.

Engineering, Procurement and Construction Agreements

Various projects are designed, engineered, constructed and commissioned pursuant to EPC agreements with affiliates of the Sponsors, which may include a two- to 10-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, 2015, all of the projects have achieved COD. All the associated costs to complete the projects are obligations of the Sponsor who contributed the projects that did not achieve COD as of the IPO closing pursuant to the Omnibus Agreement.

Operations and Maintenance 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 fixed annual fees, which are subject to certain adjustments.

O&M services to the leased solar energy 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 $0.7 million for the eleven months ended November 30, 2015, and $0.9 million for each of the years ended December 28, 2014 and December 29, 2013.

Omnibus Agreement

In connection with the IPO, the Partnership entered into an omnibus agreement (the “Omnibus Agreement”), with its Sponsors, the General Partner, OpCo and Holdings, under which (i) 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, (ii) with respect to any project in the Portfolio that did not achieve commercial operation as of the closing of the IPO, the Sponsor who contributed such project will 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, (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 any 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.

In August 2015, the Omnibus Agreement was amended to provide that (i) with respect to each of the North Star Project and the Quinto Project, which were contributed to the Partnership by First Solar and SunPower, respectively, 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 project at the time of contribution 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; and (ii) SunPower agreed to indemnify OpCo for certain costs it may incur in connection with the termination of certain tax equity financing arrangements relating to the contributed residential lease portfolios, which occurred before the Partnership’s IPO.

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Notes to Consolidated Financial Statements — Continued

 

On November 30, 2015, the Partnership entered into Amendment No. 2 to the Omnibus Agreement with the General Partner, Holdings, its Sponsors and OpCo. The Omnibus Amendment amends the terms of the parties’ existing Omnibus Agreement to provide that the indemnity for energy produced prior to commercial operation owed by each Sponsor to OpCo will be calculated on an aggregate basis with respect to all projects contributed by such Sponsor in connection with the Partnership’s IPO, rather than on a project-by-project basis. As a result of this indemnity, the Partnership received $3.9 million as an indemnity payment from SunPower for a test energy shortfall associated with the Quinto project.  

 

Promissory Note

On November 25, 2015, OpCo, issued a Promissory Note to First Solar in the principal amount of $2.0 million (the “Note”), 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 that is expected to be completed by the end the first quarter of fiscal 2016 (each, a “Specified Payment”), OpCo is obligated to repay a portion of the principal amount of the Note equal to such Specified Payment and the unpaid balance of all interest accrued under the Note to and including the date of such repayment. Interest will accrue at a rate of 1% on the portion of the principal of the Note equal to the amount of each Specified Payment from the date SDG&E remits such payment to the Solar Gen 2 Project Entity through the date that OpCo repays such amount to First Solar in accordance with the previous sentence. OpCo is permitted to prepay the Note at any time without penalty or premium.

Purchase and Sale Agreements

Prior to the closing of the IPO, each of (i) SSCA XIII Holding Company, LLC, an indirect subsidiary of OpCo and the holder of the Quinto Project Entity (“Quinto Holdings”), (ii) SSCA XXXI Holding Company, LLC, an indirect subsidiary of OpCo and the indirect holder of the RPU Project Entity (“RPU Holdings”), and (iii) SunPower Commercial Holding Company I, LLC, an indirect subsidiary of OpCo and the holder of the UC Davis Project Entity and the Macy’s Project Entities (“C&I Holdings,” and together with Quinto Holdings and RPU Holdings, the “SP Holding Companies”), entered into purchase and sale agreements (collectively, the “PSAs”) with affliates of SunPower in connection with SunPower’s contribution of the SP Holding Companies to OpCo, and also entered into certain tax equity financing arrangements with third party investors to finance the purchases of the SP Holding Companies. Pursuant to the PSAs, the purchase prices were paid in installments. The purchase price payments remaining as of the IPO have been funded by the tax equity investors’ capital contributions, which were made when the projects met certain construction milestones, with final installment payments due upon COD.

During the eleven months ended November 30, 2015, the SP Holding Companies received as capital contributions from tax equity investors a total amount of $203.7 million, and transferred an equal amount to affiliates of SunPower as delayed purchase price payments. As of November 30, 2015, all contributions from the tax equity investors that were received by the Partnership were transferred to affiliates of SunPower for the remaining purchase price payments.

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 plant. The lease agreement will expire on December 31, 2019.

Operating Expense Allocations

The Predecessor’s condensed 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 energy 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, $4.8 million, and $4.3 million in the eleven months ended November 30, 2015 and in the years ended December 28, 2014 and December 29, 2013, respectively, and are disclosed as SG&A expenses on the condensed consolidated statement of operations.

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements — Continued

 

SunPower Investment prior to IPO

Certain of the Predecessor’s expenses were paid by SunPower and are reflected as “SunPower Investment prior to IPO” on the condensed consolidated balance sheets.

 

 

Note 16. 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, valuation allowances during the Predecessor period, the tax impact of noncontrolling interest, and state tax rates (net of federal benefit) in various jurisdictions, most significantly California. All tax expense 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, it will have no taxable income in 2015.  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 previous tax year-end date and the current financial reporting year-end date.  Since 2015 is the initial year, any amounts recorded for income tax provision (benefit) following the IPO primarily represent deferred income taxes being provided on the net income before taxes of OpCo that 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 (benefit) consists of the following:

 

 

The current state tax expense of $12,000 is related to minimum state income taxes from the Predecessor period. There were no current tax expenses generated in the post-IPO period.

 

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Notes to Consolidated Financial Statements — Continued

 

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:

 

 

The Predecessor’s loss subsequent to the IPO was approximately $20.1 million or $7.0 million tax-effected. Based on the absence of sufficient positive objective evidence, a valuation allowance for the full $7.0 million has been recorded. Factors considered in providing a valuation allowance include the lack of a significant history of consistent profits, the lack of carryback capacity to realize these assets and other factors.

 

The income tax effects of temporary differences giving rise to the Partnership's deferred income tax liabilities and assets are as follows:

 

 

The net operating loss carryforward of $41,000 relates to the Partnership’s corporate activity from the IPO through November 30, 2015. The $41,000 loss was generated at the entity level, therefore, deferred taxes were provided on it as part of the November 30, 2015 tax provision. This net operating loss is not related to income (loss) from the Partnership’s investment in OpCo, which has a December 31, 2015 year-end as described above and will be included in the 2016 tax provision as a discrete period calculation.  No valuation allowance was established to offset the net operating loss carryforward since the Partnership expects to fully be able to utilize the loss in future years before it expires, based on future projections, including the future reversal of existing taxable temporary differences.  No uncertain tax positions have been identified for the period ended November 30, 2015, nor does the Partnership expect there to be any uncertain tax positions to record for the tax year ended December 31, 2015.  

 

The Predecessor’s federal and state net operating loss carryforwards discussed below relate to the prior years and do not carryover as tax attributes of the Partnership since tax attributes do not carryover after an asset acquisition.  The notes below are intended only to provide an explanation of the amounts during the Predecessor period and do not apply to the current period.

 

Net operating loss carryforwards as of December 28, 2014 and December 29, 2013 represent tax benefits measured assuming the Predecessor had been a stand-alone operating company since December 30, 2012, and will not be available if the Predecessor is no

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Notes to Consolidated Financial Statements — Continued

 

longer part of the Parent’s return. As of December 28, 2014, the Predecessor had federal net operating loss carryforwards of $168.4 million for tax purposes. These federal net operating loss carryforwards will expire at various dates from 2029 to 2034. As of December 28, 2014, the Predecessor had California state net operating loss carryforwards of approximately $72.6 million for tax purposes. These California net operating loss carryforwards will expire at various dates from 2031 to 2034. The Predecessor’s ability to utilize a portion of the net operating loss and credit carryforwards is dependent upon the Predecessor being able to generate taxable income in future periods and may be limited due to restrictions imposed on utilization of net operating loss and credit carryforwards under federal and state laws upon a change in ownership.

The valuation allowance recorded as of December 28, 2014 and December 29, 2013 assumes the Predecessor had been a stand-alone operating company since January 2, 2011. The deferred tax assets were determined by assessing both positive and negative evidence. When determining whether it is more likely than not that deferred assets are recoverable the Predecessor believes that sufficient uncertainty exists with regard to the realizability of these assets such that a valuation allowance is necessary. Factors considered in providing a valuation allowance include the lack of a significant history of consistent profits, the lack of consistent profitability in the solar industry, and the lack of carryback capacity to realize these assets, and other factors. Based on the absence of sufficient positive objective evidence, the Predecessor is unable to assert that it is more likely than not that it will generate sufficient taxable income to realize these remaining net deferred tax assets. Should the Predecessor achieve a certain level of profitability in the future, it may be in a position to reverse the valuation allowance which would result in a non-cash income statement benefit.

Accounting guidelines prescribes a more-likely-than-not recognition threshold and establishes measurement requirements for financial statement reporting of income tax positions which the Predecessor has adopted. The Predecessor has assessed the impact of these accounting guidelines and has concluded there is no material impact on its carve-out financial statements. As of December 28, 2014 and December 29, 2013 there were no material uncertain tax positions. The open tax years are 2012, 2013 and 2014.

 

 

Note 17. 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.

All operating revenues for the eleven months ended November 30, 2015 and the years ended December 28, 2014 and December 29, 2013 were from customers located in the United States. Operating revenues from a customer, First Solar, accounted for 21% of total operating revenues for the eleven months ended November 30, 2015, respectively. Long-lived assets consisting of property and equipment, net, were located in the United States.

 

 

Note 18. Subsequent Events

The Partnership declared a fourth quarter distribution for its Class A shares of $0.217 per share for the period from September 1, 2015 to November 30, 2015. The fourth quarter distribution was paid on January 14, 2016 to shareholders of record as of January 4, 2016.

On January 26, 2016, OpCo entered into a Purchase, Sale and Contribution Agreement (the “Purchase Agreement”) with SunPower, pursuant to which OpCo agreed to purchase a 20.23 MWac photovoltaic solar generating project located in Kern County, CA and which consists or will consist of solar generation systems attached to fixed-tilt carports located at 27 school sites in the Kern High School District (the “Kern Project”).  The Kern Project will be effectuated in three phases, with the closing of the first phase occurring simultaneously with the execution of the Purchase Agreement. The closings of the second and third phases are expected to occur in the fiscal quarter ending August 31, 2016 and in the fiscal quarter ending November 30, 2016, respectively.  

The aggregate purchase price for the acquisition is $35.0 million in cash, of which approximately $4.9 million was paid on January 27, 2016, in connection with the closing of the first phase. The remaining balance of the approximately $30.1 million purchase price will be paid at the closing of the second and third phases based upon the MWac of the assets in such phase.

The allocation of the approximately $4.9 million purchase price for assets acquired and liabilities assumed is subject to completion of a formal valuation process and review by management, which has not yet been completed.  Pro forma results of operations for the acquisition have not been presented as the impact of the acquisition is not material to the Partnership's consolidated results of operations for the current or prior periods. The results of operations of the first phase of the Kern Project will be included in the Partnership’s consolidated results of operations beginning January 26, 2016.

 

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8point3 Energy Partners LP

Notes to Consolidated Financial Statements — Continued

 

 

Note 19. Quarterly Financial Information (Unaudited)

 

 

 

 

 

 

 

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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.

 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.