UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended June 28, 2015

OR

For the transition period from _____ to _____

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

 

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  o    No  x  

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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

 

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

As of August 3, 2015, the registrant had outstanding 20,002,679 Class A shares representing limited partner interests and 51,000,000 Class B shares representing limited partner interests.

 

 

 

 

 

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Table of Contents

 

 

 

 

 

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GLOSSARY

References in this Quarterly Report on Form 10-Q to:

“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.

“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.

“COD” refers to the commercial operation date.

“EPC” refers to engineering, procurement and construction.

“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 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 Projects” refers to, collectively, the projects set forth in the Prospectus in the chart 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 (as defined in the Prospectus under “Certain Relationships and Related Party Transactions—ROFO Agreements”) should First Solar decide to sell them.

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

“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 Quarterly Report on Form 10-Q, 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.

“Initial Portfolio” refers to, collectively, our initial 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.

“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.

 

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“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 Management Services Agreement among OpCo, the Partnership, the General Partner, Holdings and an affiliate of First Solar, and the Management Services Agreement among OpCo, the Partnership, the General Partner, Holdings and a subsidiary of SunPower. Please read “Certain Relationships and Related Party Transactions—Management Services Agreements” in the Prospectus.

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

“NASDAQ” refers to the NASDAQ Global Select Market.

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

“NOLs” refers to net operating losses.

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

“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.

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

“Partnership” refers to 8point3 Energy Partners LP and its subsidiaries.

 

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“Partnership Agreement” refers to our partnership agreement.

“PBI Rebates” refers to performance based incentives.

“PPA” refers to a power purchase agreement.

“Predecessor” refers to the SunPower Project Entities.

“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.

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

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

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

“Residential Portfolio” refers to the approximately 5,900 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 Right of First Offer Agreement between OpCo and SunPower and the Right of First Offer Agreement between OpCo and First Solar. Please read “Certain Relationships and Related Party Transactions—ROFO Agreements” in the Prospectus.

“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 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.

“SEC” refers to the Securities and Exchange Commission.

“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.

 

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“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 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 Projects” refers to, collectively, the projects set forth in the Prospectus in the chart 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 (as defined in the Prospectus under “Certain Relationships and Related Party Transactions—ROFO Agreements”) should SunPower decide to sell them.

“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.

“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.

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

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q 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 report 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. Consequently, no forward-looking statements can be guaranteed.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and 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 report and in our prospectus dated June 18, 2015 and filed with the Securities and Exchange Commission (the “SEC”) pursuant to Rule 424(b) under the Securities Act of 1933, as amended (the “Securities Act”) on June 19, 2015 (the “Prospectus”). Those risk factors and other factors noted throughout this report and in the Prospectus could cause our actual results to differ materially from those disclosed in any forward-looking statement. You should also understand that it is not possible to predict or identify all such factors and should not consider the risk factors included this report and the Prospectus to be a complete statement of all potential risks and uncertainties. Please read “Risk Factors” in Item 1A of this Quarterly Report on Form 10-Q.

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—FINANCIAL INFORMATION

 

Item 1. Financial Statements.

8point3 Energy Partners LP

Condensed Consolidated Balance Sheets

(In thousands, except share data)

(Unaudited)

 

 

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

 

 

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8point3 Energy Partners LP

Condensed Consolidated Statements of Operations

(In thousands, except per share data)

(Unaudited)

 

 

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

 

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8point3 Energy Partners LP

Condensed Consolidated Statements of Comprehensive Income (Loss)

(In thousands)

(Unaudited)

 

 

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

 

 

 

 

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8point3 Energy Partners LP

Condensed Consolidated Statements of Shareholders’ Equity

(In thousands, except share data)

(Unaudited)

 

 

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

 

 

 

 

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8point3 Energy Partners LP

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

 

 

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

 

 

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements

 

 

Note 1. Description of Business and Basis of Presentation

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 June 28, 2015, 8point3 Energy Partners LP owned a controlling non-economic managing member interest in 8point3 Operating Company, LLC (“OpCo”) and a 29.4% limited liability company interest in OpCo and our Sponsors collectively owned a noncontrolling 70.6% limited liability company interest in OpCo.

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

 

 

 

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed 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.

For all periods prior to the IPO, the accompanying unaudited condensed 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 liabilities. For all periods subsequent to the IPO, the accompanying unaudited condensed consolidated financial statements and the notes thereto, represent the results of 8point3 Energy Partners LP which consolidates OpCo through its controlling interest. All significant inter-entity accounts and transactions have been eliminated in consolidation.

 

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. generally accepted accounting principles (“U.S. GAAP”). The

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

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.

The Partnership’s unaudited condensed consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information. Accordingly, they do not include all of the information and disclosures required by U.S. GAAP for complete financial statements. Interim results are not necessarily indicative of results for a full year. In the opinion of management, the accompanying unaudited condensed consolidated financial statements include all adjustments (consisting of normal, recurring items) necessary to state fairly its financial position, results of operations and cash flows for the periods presented.

The unaudited financial statements included herein should be read in conjunction with the Prospectus, which contains the Predecessor’s audited combined carve-out financial statements and notes thereto for and as of the years ended December 28, 2014 and December 29, 2013, as well as Management’s Discussion and Analysis of Financial Condition and Results of Operations. The results shown herein are not necessarily indicative of the results to be expected in any future periods.

Fiscal Years

On June 24, 2015, in connection with the closing of the IPO, the Partnership amended its partnership agreement to include a change in the fiscal year to November 30. The Predecessor had a 52-to-53 week fiscal year that ended on the Sunday closest to December 31. 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. The third quarter of fiscal 2015 will include the period from June 1, 2015 to August 31, 2015.

 

Management Estimates

The preparation of the condensed consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying notes. Significant estimates in these condensed 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 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. For the three and six months ended June 28, 2015, $1.1 million and $2.5 million, respectively, has been deferred and capitalized, and $0.9 million and $1.6 million, respectively, 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. 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 income (expense), net in the condensed consolidated statements of operations.

 

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

Comprehensive Income (Loss)

Comprehensive income (loss) is defined as the change in equity during a period from non-owner sources. The Partnership’s comprehensive 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 condensed 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 three and six months ended June 28, 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 June 28, 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 amount for operating lease customers 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. 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 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 June 28, 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 guidelines. 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 June 28, 2015 and December 28, 2014, $0.2 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 and depreciation 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 three and six months ended June 28, 2015 was $0.8 million and $1.5

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

million, respectively, and was $0.1 million and $0.9 million for the three and six months ended June 29, 2014, 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. At June 28, 2015, the Quinto Project, the RPU Project, the UC Davis Project and the Macy’s Project remained under construction.

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 and 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 projects, the Partnership considers the project commercially viable if it is anticipated to be operated for a profit once it is fully constructed. 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 three and six months ended June 28, 2015 was $1.3 million and $2.1 million, respectively, and during the three and six months ended June 29, 2014 was $0.6 million and $1.1 million, respectively.

Asset Retirement Obligations

In some cases the Partnership operates certain projects under power purchase and other agreements that include a requirement for the removal of the solar 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 $6.7 million as of June 28, 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

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

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.

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. As the Partnership receives product warranties from its original equipment manufacturers, no more product warranties are recorded on its condensed consolidated financial statements as of June 28, 2015.

Segment Information

The Partnership is engaged in one reportable segment that operates a portfolio of solar energy generation systems. It operates as a single reportable segment based on the “management” approach. This approach designates the internal reporting used by management for making decisions and assessing performance as the source of the reportable segments.

All operating revenues for the three and six months ended June 28, 2015 and June 29, 2014 were from customers located in the United States. No operating revenues by a single customer exceeded 10% of total operating revenues in each of those reporting periods.

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 as revenue 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, all revenue related to the NPV of the minimum lease payments has been recognized as of December 28, 2014. Accordingly, there was no sales-type lease revenue recognized on the financial statements for the three and six months ended June 28, 2015.

 

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

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 as revenue 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 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 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. 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. 

Cost of Operations

Cost of operations includes operation and maintenance 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 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.

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.

 

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

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. There were no share-based awards issued for the three and six months ended June 28, 2015.

Recent Accounting Pronouncements

In April 2015, the Financial Accounting Standards Board (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 is permitted. The Partnership is evaluating the available methods and the potential impact of this standard on its financial statements and disclosure.

In May 2014, the FASB issued a new revenue recognition standard based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The new revenue recognition standard becomes effective for the predecessor in the first quarter of 2017, and is to be applied retrospectively using one of two prescribed methods. The Partnership is evaluating the application method and impact on its 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 three months ended June 28, 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, represents 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, a subsidiary of Sempra Energy.

 

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

North Star

The North Star Project, located in California, is a fully operational 60 MW grid-connected system, which commenced operations in the second quarter of 2015, 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, which commenced operations in the second quarter of 2015, 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 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 June 28, 2015 are as follows:

 

 

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

The following table presents summarized financial information for SG2 Holdings, LLC (“SG2 Holdings”), a significant investee, as derived from the unaudited consolidated financial statements of SG2 Holdings for the three and six months ended June 30, 2015 and as of June 30, 2015:

 

. 

The following table presents summarized financial information for NS Solar Holdings, LLC  (“North Star Holdings”), a significant investee, as derived from the unaudited consolidated financial statements of North Star Holdings for the three and six months ended June 30, 2015 and as of June 30, 2015:

 

 

 

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

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 condensed consolidated balance sheets is as follows:

 

 

 

 

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

 

 

 

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 $0.5 million and $0.9 million in the three and six months ended June 28, 2015, respectively, and $0.2 million and $0.5 million in the three and six months ended June 29, 2014, 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 June 28, 2015 under these land use agreements are as follows:

 

 

Product Warranties

The following table summarizes accrued warranty activity for the three and six months ended June 28, 2015 and the three and six months ended June 29, 2014:

 

 

The product warranties included in the Predecessor’s combined balance sheets represent the estimate of the expected costs that could result from these warranties provided in connection with the sales-type leases.  Due to the pass-through nature of the warranty

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

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 $0.4 million and $0.5 million as of June 28, 2015 and December 28, 2014, respectively. The Partnership has also recorded in “Other current assets” amounts of $0.4 million and zero as of June 28, 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 three and six months ended June 28, 2015 and three and six months ended June 29, 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 three and six months ended June 28, 2015 and June 29, 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 our 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 three and six months ended June 28, 2015 and the three and six months ended June 29, 2014, there were no known environmental contingencies that required the Partnership to recognize a liability.

 

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

 

Note 7. Lease Agreements and Power Purchase Agreements

Lease Agreements

As of June 28, 2015, the Partnership’s condensed 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 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 June 28, 2015:

 

 

As of June 28, 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.  

 

 

Note 8. Debt and Financing Obligations

Term Loan and Revolving Credit Facility

On June 5, 2015, OpCo entered into a $525 million 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. As of June 28, 2015, the effective cash interest rate for the new term loan facility was approximately 2.24% per annum. There will be no principal amortization over the term of the facility. The discount and incremental debt issuance costs associated with the new borrowing 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 June 28, 2015, the full amount of the $300 million term loan facility and approximately $11.5 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 new credit facility is collaterized 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.

 

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

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 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 to up to $775 million in the aggregate, with any increase in the revolving credit facility not to exceed $100 million.

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 June 28, 2015, the Partnership was in compliance with the debt covenants.

The following table summarizes the Partnership’s long-term debt:

 

 

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 three and six months ended June 28, 2015 and June 29, 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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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

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 one of the residential lease financing third-party investors that terminated the financing obligation arrangement. In conjunction with the termination of the arrangement, the Predecessor paid $10.8 million to terminate the $10.1 million outstanding financing obligation.

On January 23, 2015, the Predecessor entered into an agreement with one of the residential lease financing third-party investors 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. The letter of credit facility provides for the issuance, upon request by SunPower, of letters of credit by the issuing banks thereunder in order to support certain obligations of SunPower, in an aggregate amount not to exceed $878.0 million for the period from January 1, 2014 through December 31, 2014. As of June 28, 2015 and December 28, 2014, letters of credit issued and outstanding under the August 2011 letter of credit facility with Deutsche Bank for the Quinto Project totaled $48.8 million and $38.3 million, respectively. The associated fees paid to Deutsche Bank for the letters of credit were $0.2 million and $0.4 million, respectively, during the three and six months ended June 28, 2015 and $0.1 million and $0.3 million, respectively, during the three and six months ended June 29, 2014 and were recognized as interest expense in the condensed consolidated statements of operations. Pursuant to the Omnibus Agreement, SunPower as the Sponsor who contributed the Quinto Project will continue to maintain the letters of credit for the Quinto Project under this Credit Facility and will bear the associated fees until the Project achieves COD.

 

 

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):

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:

 

 

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 June 28, 2015 and December 28, 2014, the Predecessor had interest rate swap agreements

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

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 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 three months ended June 28, 2015 and June 29, 2014, $2.2 million and zero, respectively, 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 the six months ended June 28, 2015 and June 29, 2014, $5.4 million and zero, respectively, was reclassified into loss on cash flow hedges within other expense, net in the condensed consolidated statement of operations, as the transaction was terminated.

 

 

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 June 28, 2015, First Solar and SunPower had noncontrolling interests of 30.6% and 40.0%, 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 June 28, 2015, redeemable noncontrolling interests and noncontrolling interests were zero and $0.4 million, respectively. During the three and six months ended June 28, 2015 and June 29, 2014, such subsidiaries of OpCo received $1.0 million and zero, respectively, in contributions from investors under the related facilities and attributed $0.7 million and zero, respectively, in losses to the third-party investors primarily as a result of allocating certain assets, including tax credits, if any, to the investors.

The following table presents the noncontrolling interest balances by entity, reported in shareholders’ equity in the consolidated balance sheets as of June 28, 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:

 

 

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

 

Note 12. Shareholders’ Equity

The Partnership’s partnership agreement authorizes the issuance of an unlimited number of Class A shares. The Partnership’s Class A shareholders have only limited voting rights and are not entitled to elect the General Partner or its directors.

The Partnership’s Class A shares and Class B shares represent limited partner interests in 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. The Sponsors were issued Class B shares in connection with the IPO described below. Through their ownership of Holdings, the Sponsors hold all of the incentive distribution rights (“IDRs”) in OpCo, which represent a variable interest in distributions after certain distribution thresholds are met.

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. As a result, as of June 28, 2015, the Partnership owned a 29.4% limited liability company interest in OpCo as well as a controlling noneconomic managing member interest in OpCo. As of June 28, 2015, the Sponsors collectively owned 48,000,000 Class B shares in the Partnership, with SunPower and First Solar having owned 27,184,070 and 20,815,930 Class B shares, respectively, and together, having owned a noncontrolling 70.6% 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 June 28, 2015, the following shares of the Partnership were outstanding:

 

 

 

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. 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.

 

 

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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. There were no share-based compensation expenses for the three and six months ended June 28, 2015.    

 

 

 

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Note 14. Net Income Per Share

Basic net income per share is computed by dividing net income attributable to Class A shareholders by the weighted average number of Class A shares outstanding for the period from the IPO completion date of June 24, 2015 to the quarter ended June 28, 2015. 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 quarter ended June 28, 2015. In addition, there were no potentially dilutive securities (including any stock options, restricted stock and restricted stock units) for the three and six months ended June 28, 2015, respectively. Accordingly, basic and diluted net income per share were the same for each of the three and six months ended June 28, 2015.

 

 

 

 

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

 

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affiliates of the Sponsors and certain of the subsidiaries of the Partnership. In the case of the First Solar MSA and the SunPower MSA, OpCo will pay each Service Provider an annual management fee of $0.6 million and $1.1 million, respectively, in monthly installments, and 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 $0.02 million for each of the three and six months ended June 28, 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 June 28, 2015, certain projects contributed by SunPower are construction in progress and expected to achieve COD in the next two quarters.  SunPower as the EPC provider is required to complete the projects and pursusant to the Omnibus Agreement as described below, the Sponsor who contributed the projects that did not achieve COD as of the IPO closing will pay all costs, estimated to be approximately $160 million remaining, required to complete the projects.

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, 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 (as presented in the Prospectus). Costs incurred for these services were $0.2 million for each of the three months ended June 28, 2015 and June 29, 2014 and $0.5 million for each of the six months ended June 28, 2015 and June 29, 2014.

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 Initial 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.

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 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

 

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to the PSAs, the purchase price will be paid in installments. The purchase price payments remaining as of June 28, 2015 will be funded by the tax equity investors’ capital contributions, which will be made when the projects meet certain construction milestones, with final installment payments due upon COD.

During the three months ended June 28, 2015, the SP Holding Companies received as capital contributions from tax equity investors a total amount of $1.0 million, and transferred an equal amount to affiliates of SunPower as delayed purchase price payments. The aggregate remaining purchase price payments are estimated to be approximately $200.0 million as of June 28, 2015 and will be funded by additional capital contributions of the tax equity investors. Such contributions from the tax equity investors will be received by the Partnership and the Partnership will transfer the received funds 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 $3.0 million and $4.8 million in the three and six months ended June 28, 2015 and $0.6 million and $0.4 million in the three and six months ended June 29, 2014, respectively, and are disclosed as SG&A expenses on the condensed consolidated statement of operations.

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 valuation allowances during the Predecessor period, the tax impact of noncontrolling interest, the tax impact of equity in earnings, 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 does not expect to pay any cash taxes in the period after the IPO closing date covered by these 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 tax year-end date and the financial reporting year-end date.

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.

 

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 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

 

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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 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.

 

 

Note 17. Segment Information

The Partnership is engaged in one reportable segment that operates a portfolio of solar energy generation systems. It operates as a single reportable segment based on the “management” approach. This approach designates the internal reporting used by management for making decisions and assessing performance as the source of the reportable segments.

All operating revenues for the three and six months ended June 28, 2015 and June 29, 2014 were from the Maryland Solar Project and residential lease customers located in the United States. No operating revenues by a single residential customer exceeded 10% of total operating revenues in the each of those reporting periods. Long-lived assets consisting of property and equipment, net, were located in the United States.

 

 

Note 18. Subsequent Events

On July 14, 2015, the Partnership filed a Form S-8 for the LTIP, under which 2,679 Class A shares were issued to the three independent members of the board of directors.

On June 18, 2015, the Partnership granted the underwriters an option to purchase up to an additional 3,000,000 Class A shares representing limited partner interests in the Partnership at the IPO price less underwriting discount and structuring fee, for 30 days after the date of the prospectus. As a result of the expiration of the underwriter’s option to purchase additional shares 30 days from the date of the Prospectus, the Partnership issued additional Class B shares of 1,300,995 and 1,699,005 to First Solar and SunPower, respectively.  Therefore, as of July 19, 2015, the Partnership owns 28.2% of the limited liability company interest in OpCo and the Sponsors collectively own 71.8% of the limited liability company interests in OpCo.

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 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.

 

 

 

 

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Item 2. 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 unaudited condensed consolidated financial statements as of and for the three and six months ended June 28, 2015 and June 29, 2014, respectively and the notes thereto included elsewhere in this Quarterly Report on Form 10-Q. The unaudited financial statements included herein should be read in conjunction with the Prospectus, which contains SunPower Corporation’s Select Project Entities and Leases (“Predecessor”) audited combined carve-out financial statements and notes thereto for and as of the years ended December 28, 2014 and December 29, 2013, as well as Management’s Discussion and Analysis of Financial Condition and Results of Operations. The results shown herein are not necessarily indicative of the results to be expected in any future periods.

We own a controlling non-economic managing member interest and a 28.2% limited liability company interest in OpCo and our Sponsors collectively own a non-controlling 71.8% limited liability company interest in OpCo. Because we consolidate OpCo, our financial results are shown on a 100% basis and are not adjusted to reflect our Sponsors’ non-controlling limited liability company interest in OpCo.

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. Upon the completion of our IPO on June 24, 2015, our Initial Portfolio, which we acquired from our Sponsors, had interests in 432 MW of solar energy projects. Our primary objective is to generate predictable cash distributions that grow at a sustainable rate. We intend to achieve this objective by acquiring high-quality solar assets primarily developed by our Sponsors that generate long-term contracted cash flows and serve utility, commercial and industrial (“C&I”) and residential customers in the United States and other select markets, primarily within the countries that comprise the Organization for Economic Co-operation and Development (the “OECD”).

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 July 31, 2015, we own a 28.2% limited liability company interest in OpCo as well as a controlling non-economic managing member interest in OpCo. 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 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. As of June 28, 2015, the full amount of the term loan facility and approximately $11.5 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. Our ability to borrow under the revolving credit facility and the delayed draw term loan facility and our ability to access the debt and equity capital markets should provide us with the financial flexibility to pursue acquisition opportunities. As of June 28, 2015, we do not have any indebtedness at the Project Entities.

As of June 28, 2015, we own interests in six utility-scale solar energy projects, four of which are operational and two of which are in late-stage construction. These assets represent 87% of the generating capacity of our Initial Portfolio upon all projects attaining COD. We own interests in a portfolio of C&I and residential distributed generation solar (“DG Solar”) assets, which represent 13% of the generating capacity of our Initial Portfolio. Our Initial 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 June 28, 2015, the weighted average remaining life of offtake agreements across our Initial Portfolio was 21.9 years.

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).

 

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We used all of the net proceeds of the IPO to purchase 20,000,000 OpCo common units from OpCo, representing an approximately 28.2% limited liability company interest in 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.

Initial Portfolio

Our Initial Portfolio refers to, collectively, our initial 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 Initial Portfolio:

 

 

 

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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 Initial 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 June 28, 2015, the weighted average remaining life of offtake agreements across our Initial Portfolio was 21.9 years, with the offtake agreements of our Utility Project Entities having remaining terms ranging from 17.8 to 28.5 years and our C&I offtake agreements and residential offtake agreements having remaining terms ranging from 17.3 to 20.0 years.

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 will evaluate are EBITDA and cash available for distribution.

EBITDA.    We define EBITDA as net income plus interest expense, income tax expense, and depreciation and amortization. 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 EBITDA is net income. The presentation of EBITDA should not be construed as an inference that our future results will be unaffected by unusual or non-recurring items.

We believe 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, 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, 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. 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 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 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 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 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 operating activities.

Items Affecting the Comparability of Our Financial Results

Our 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 condensed 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 Initial Portfolio. None of the SunPower Utility and C&I Projects have yet begun operation and the First Solar Projects, which are relatively new, are not included in the Predecessor’s results of operations.

Selling, General and Administrative Expense.    Included in our 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, we will pay an annual fee, initially $1.7 million, to our Sponsors for general and administrative services. This annual management fee will be 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 (as presented in the Prospectus) do not include equity earnings from any minority-owned joint ventures. As of June 28, 2015, OpCo owns 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 will not be consolidated in our financial statements and instead will be represented as earnings from equity investments.

Financing.    The Predecessor’s historical combined carve-out financial statements (as presented in the Prospectus) 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 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. As of June 28, 2015, the full amount of the term loan facility and approximately $11.5 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. We used the proceeds of the term loan facility to pay distributions to our Sponsors.

 

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Expiration of Section 1603 Cash Grant Program.    The Predecessor’s combined carve-out financial statements (as presented in the Prospectus) reflect the effect of the federal Section 1603 cash grant program. This program has expired and going forward, we will 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.

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 to include 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, while our third quarter of fiscal 2015 will include the period from June 1, 2015 to August 31, 2015.

Significant Factors and Trends Affecting Our Business

The assets in our Initial 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 government incentives designed to promote the development and use of solar energy. These incentives include accelerated tax depreciation, Investment Tax Credits (“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 10% of eligible basis for solar projects that commence commercial operation after December 31, 2016. For more information about the risks associated with these government incentives, please read “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 Initial Portfolio are generally unaffected by the trends discussed above, given that all of the electricity to be generated by our projects will be sold under fixed-price offtake agreements, which, as of June 28, 2015, have a weighted average remaining life of approximately 21.9 years, and the limited impact that expiring U.S. federal incentives will have upon completion of our construction projects in the United States. 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. The projects in our ROFO Portfolio are also more diverse geographically than the projects in our Initial Portfolio and our Sponsors have already accounted for the impact that expiring U.S. federal incentives will have upon completion of our construction of such projects in the United States.

 

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Critical Accounting Policies & Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions in certain circumstances that affect amounts reported in our consolidated financial statements and related footnotes. In preparing these consolidated financial statements, we have made our best estimates of certain amounts included in the consolidated financial statements. Application of accounting policies and estimates, however, involves the exercise of judgment and use of assumptions as to future uncertainties and, as a result, actual results could differ from these estimates. In arriving at our critical accounting estimates, factors we consider include how accurate the estimate or assumptions have been in the past, how much the estimate or assumptions have changed and how reasonably likely such change may have a material impact. Our critical accounting policies and estimates are more fully described in the Prospectus. There have been no significant changes to our critical accounting policies and estimates since December 28, 2014.

Results of Operations

Three and Six Months Ended June 28, 2015 Compared to Three and Six Months Ended June 29, 2014

Revenues

 

Operating revenues for the three months ended June 28, 2015 included lease revenue from the Maryland Solar Project beginning after the closing of the IPO and for all periods were comprised of revenues generated from solar energy systems leased to residential customers. The 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, all revenue related to the net present value of the minimum lease payments has been recognized as of December 28, 2014. Accordingly, we had no sales-type lease revenue on our financial statements for the three and six months ended June 28, 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 three and six months ended June 28, 2015 and June 29, 2014.

Total revenues increased by 3.6% during the three months ended June 28, 2015 as compared to the three months ended June 29, 2014 mainly due to addition of the Maryland Solar Project to our portfolio, which generates quarterly rent revenue. Total revenues decreased 5.7% during the six months ended June 28, 2015 as compared to the six months ended June 29, 2014 due to no sales-type leases being placed in service in the six months ended June 28, 2015 and a decrease in PBI Rebate revenue due to the timing of collections from utilities, offset by the rent revenues generated by the Maryland Solar Project.

 

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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. 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. The 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 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 three or six months ended June 28, 2015. For the three and six months ended June 29, 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 104.5%, for the three months ended June 28, 2015 as compared to the three months ended June 29, 2014 is mainly driven by the $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 three months ended June 29, 2014.

The increase of $7.6 million, or 144.0%, for the six months ended June 28, 2015 as compared to the six months ended June 29, 2014 is mainly driven by the $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 quarter ended June 29, 2014, as well as $1.3 million of reserve recorded  for the aged rebates receivable and $0.6 million of system output performance warranty and residential lease system repairs accrual for the six months ended June 28, 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 $0.2 million for each of the three months ended June 28, 2015 and June 29, 2014. Costs incurred for these services were $0.5 million for each of the six months ended June 28, 2015 and June 29, 2014.

Selling, General and Administrative: Selling, general and administrative expense includes (i) 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 $3.3 million, or 260.4%, for the three months ended June 28, 2015 as compared to the three months ended June 29, 2014 was primarily driven by a $2.4 million higher allocation of SunPower operating expenses based on the proportional level of effort attributable to the Quinto, RPU, UC Davis and Macy’s Projects under construction, of which the Quinto Project was approximately 85% complete as of June 28, 2015, the allocation of $0.9 million of costs incurred by SunPower related to our IPO, and $0.4 million increase in the allowance for doubtful accounts related to residential lease customers, offset by approximately $0.4 million reduction in non-capitalizable project-related expenses incurred during the project development period in the prior year.

The increase of $5.9 million, or 311.5%, for the six months ended June 28, 2015 as compared to the six months ended June 29, 2014 was primarily driven by a $4.4 million higher allocation of SunPower operating expenses based on the proportional level of effort attributable to the Quinto, RPU, UC Davis and Macy’s Projects under construction, of which the Quinto Project was approximately 85% complete as of June 28, 2015, and the allocation of $1.6 million of costs incurred by SunPower related to our IPO,

 

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offset by approximately $0.2 million reduction in non-capitalizable project-related expenses incurred during the project development period in the prior year.

Depreciation: Depreciation expense reflects costs associated with depreciation of the Maryland Solar Project as well as our residential operating lease assets. 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 $0.7 million, or 663.3%, for the three months ended June 28, 2015 as compared to the three months ended June 29, 2014 is primarily a result of the recognition of certain cash grants for the three months ended June 29, 2014 related to operating leases placed in service throughout previous years, which reduces the carrying value of the assets and related depreciation expense.

The increase of $0.6 million, or 63.3%, for the six months ended June 28, 2015 as compared to the six months ended June 29, 2014 is primarily a result of the recognition of certain cash grants for the six months ended June 29, 2014 related to operating leases placed in service throughout previous years, which reduces the carrying value of the assets and related depreciation expense.

Other Expense

 

Interest expense: Non-cash interest expense 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 condensed 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 three months ended June 28, 2015 included $0.3 million of non-cash interest expense and $0.2 million of cash interest expense compared to total interest expense for the three months ended June 29, 2014 which included $1.3 million of non-cash interest expense and $0.1 million of cash interest expense. Non-cash interest expense decreased $1.0 million, or 76.9% quarter-on-quarter due to the Predecessor terminating the remaining residential lease financing obligation arrangement in May 2015.

Interest income of $1.1 million for the three and six months ended June 28, 2015 relates to 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.

Interest expense for the six months ended June 28, 2015 included $1.2 million of non-cash interest expense and $0.3 million of cash interest expense compared to total interest expense for the six months ended June 29, 2014 which included $2.5 million of non-cash interest expense and $0.3 million of cash interest expense. Non-cash interest expense decreased $1.3 million, or 52.0% quarter-on-quarter due to the Predecessor terminating one residential lease financing obligation in January 2015 and the remaining obligation in May 2015.

 

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Other expense for the three and six months ended June 28, 2015 included loss on cash flow hedges of $2.2 million and $5.4 million, respectively, and loss on termination of the residential lease financial obligation of $5.8 million and $6.5 million, respectively.

Loss on cash flow hedges: 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, 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 three months ended June 28, 2015 and June 29, 2014, $2.2 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. During the six months ended June 28, 2015 and June 29, 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 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 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 three months ended June 28, 2015 and June 29, 2014, $5.8 million and zero, respectively, was recognized as a loss on termination within other expense, net in the condensed consolidated statements of operations. During the six months ended June 28, 2015 and June 29, 2014, $6.5 million and zero, respectively, was recognized as a loss on termination within other expense, net in the condensed consolidated statements of operations.

(Provision for) Benefit from Income Taxes

 

Income Tax Expense: Our tax rate is primarily affected by the tax impact of noncontrolling interest, the tax impact of equity in earnings, 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 provision for income taxes line of the condensed consolidated statements of operations.

Our income tax expense following the IPO closing date represents federal and state taxes on net income (exclusive of income tax but after noncontrolling interest). The Predecessor’s income tax expense, which was calculated on a separate return basis for the carve-out period, was due to minimum state income taxes. The change in (provision for) benefit from income taxes as a percentage of revenues for the three months ended June 28, 2015 of (4.7)% compared to 3.6% for the three months ended June 29, 2014 is the result of higher losses before income taxes for the three months ended June 28, 2015 of $11.0 million compared to an earnings before income taxes of $4.7 million for the three months ended June 29, 2014 while our income tax expense quarter-on-quarter did not change materially.

Equity in Earnings of Unconsolidated Investees

 

 

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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, LLC (“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 three and six months ended June 28, 2015, we recognized equity in earnings of $0.2 million. We did not have any equity method investments during the three and six months ended June 29, 2014.

Cash Flows

Six Months Ended June 28, 2015 Compared to Six Months Ended June 29, 2014

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

 

Operating Activities

Net cash used in operating activities for the six months ended June 28, 2015 was $9.3 million and was primarily the result of: (i) a net loss of $20.0 million; (ii) $3.6 million increase in prepaid and other current assets, related to capitalized expenses incurred by the Predecessor for our initial public offering; and (iii) $0.5 million decrease in deferred revenue on operating leases. This was partially offset by: (i) non-cash charges of $13.7 million, including $3.2 million mark-to-market loss on cash flow hedges, $6.5 million loss upon termination of residential financing arrangement, $1.5 million depreciation of operating lease assets, $1.3 million reserve for rebates receivable, and $1.2 million interest expense for the financing arrangement of residential leased solar energy systems prior to termination; and (ii) $1.3 million increase in accounts payable and other accrued liabilities.

Net cash provided by operating activities for the six months ended June 29, 2014 was $0.6 million and was primarily the result of: (i) net income of $3.9 million; (ii) non-cash charges of $3.4 million, including $0.9 million depreciation of operating lease assets and $2.5 million interest expense for two financing arrangements of residential leased solar energy systems; (iii) $1.1 million decrease in cash grants and rebates receivable; and (iv) $0.3 million decrease in solar power systems to be leased. This was partially offset by: (i) $1.8 million increase in accounts receivable and financing receivable for rent due on sales-type and operating leases; (ii) $5.1 million decrease in accounts payable and other accrued liabilities related to recognition of deferred cash grant awards; (iii) $0.8 million increase in prepaid expense and other current assets related to prepaid land lease on the Quinto Project; and (iv) $0.4 million decrease in deferred rent revenue for operating leases.

Investing Activities

Net cash used in investing activities for the six months ended June 28, 2015 was $224.0 million related to costs incurred by the Predecessor associated with solar energy projects under construction.

Net cash used in investing activities for the six months ended June 29, 2014 was $20.7 million and was the result of $22.6 million of costs associated with solar energy projects under construction, offset by $1.9 million of cash grants received related to residential solar energy systems under operating leases.

Financing Activities

Net cash provided by financing activities for the six months ended June 28, 2015 was $271.2 million due to: (i) $393.8 million in proceeds from issuance of Class A shares, net of issuance costs; (ii) $461.2 million in proceeds from issuance of bank loans, net of issuance costs from our term loan facility as well as a financing arrangement for the Quinto Solar Project; (iii) $337.8 million in capital contributions from SunPower to fund the SunPower Project Entities before the IPO; and (iv) $1.0 million in cash contributions from noncontrolling interests associated with our tax equity financing arrangements. 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; and (iii) $264.1 million repayment of bank loans to terminate two residential lease

 

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financing arrangements prior to the IPO and the Quinto Solar Project at the IPO closing; and (vi) $3.2 million of capital distributions to SunPower made by the Predecessor before the IPO.

Net cash provided by financing activities for the six months ended June 2014, was $20.1 million due to $26.1 million of capital contributions from SunPower, partially offset by $6.0 million of capital distributions to SunPower.

Liquidity and Capital Resources

Cash Management; Bank Accounts

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 have 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.

Quarterly Distributions

We intend to pay a minimum quarterly distribution of $0.2097 per Class A share per quarter, and OpCo intends to pay a minimum quarterly distribution of $0.2097 per common and subordinated unit per quarter. In order for OpCo and us to pay such minimum quarterly distributions, OpCo will require cash available for distribution of approximately $14.9 million per quarter, or approximately $59.6 million per year in the aggregate, based on the number of common and subordinated units outstanding as of the closing of the IPO. Neither we nor OpCo have a legal obligation to pay this distribution.

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 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 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. As of June 28, 2015, the full amount of the $300 million term loan facility and approximately $11.5 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 to up to $775 million in the aggregate, with any increase in the revolving facility not to exceed $100 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 will be used for acquisitions. Amounts available under the revolving facility will 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 five years following the closing of our IPO.

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

 

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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.

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 June 28, 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.

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.

 

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Contractual Obligations

The following table summarizes our contractual obligations as of June 28, 2015:

 

 

Off-Balance-Sheet Arrangements

As of June 28, 2015, we did not have any significant off-balance-sheet arrangements.

 

 

Item 3. 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, 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 June 28, 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 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.

 

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Our interest expense would increase to the extent interest rates rise in connection with our variable interest rate borrowings. As of June 28, 2015, the outstanding principal balance of our variable interest borrowings was $300.0 million.  An immediate 10% increase in interest rates would have an increase of approximately $0.1 million of annualized interest expenses on our 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 June 28, 2015, our investment portfolio consisted of 100% in demand deposits.

 

 

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that are designed to provide reasonable assurance that information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that disclosure controls and procedures, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. Additionally, in designing disclosure controls and procedures, our management is required to apply its judgment in evaluating the cost-benefit relationship of possible disclosure controls and procedures. The design of any disclosure control and procedure also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

Based on their evaluation as of the end of the period covered by this Quarterly Report on Form 10-Q, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of June 28, 2015 at a reasonable assurance level.

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.

PART II—OTHER INFORMATION

 

 

Item 1. Legal Proceedings.

None.

 

 

Item 1A. Risk Factors.

The following risks could materially and adversely affect our business, financial condition and results of operations.

Risks Related to Our Business

OpCo may not have sufficient cash available for distribution following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements and fees to the General Partner and its affiliates, to enable it to pay the minimum quarterly distribution on all its units, and therefore we may not have sufficient cash available for distribution to pay the initial quarterly distribution to our Class A shareholders.

In order for OpCo to pay the minimum quarterly distribution of $0.2097 per common and subordinated unit, or $0.8388 per common and subordinated unit on an annualized basis, and for us to pay the initial quarterly distribution of $0.2097 per Class A share (assuming we are not required to pay federal income taxes), OpCo will require cash available for distribution of approximately $14.9 million per quarter, or $59.6 million per year, based on the number of OpCo common and subordinated units outstanding as of the completion of the IPO. OpCo may not have sufficient available cash each quarter to pay the minimum quarterly distribution or any

 

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amount to its unitholders and therefore we may not have sufficient available cash to pay the initial quarterly distribution or 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 will be 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.

Since a substantial portion of our Initial Portfolio is still under construction, we are subject to risk related to the completion of such projects until such projects achieve COD.

A substantial portion of our Initial Portfolio is still under construction. Our business plan assumes certain CODs and capacities for the projects and if one or more of the projects do not attain COD when expected or at all or if the capacity of one or more projects is less than expected, such project(s) could generate substantially less cash flow than expected. The Sponsors have agreed under the Omnibus Agreement to pay to us all costs required to complete such project and certain liquidated damages in the event such project fails to achieve COD and specified capacities pursuant to an agreed schedule. In certain circumstances, our Sponsors’ payment of liquidated damages will result in such Sponsor’s repurchase of the underperforming project. In such event, we will not be generating cash flow until we can redeploy the proceeds from the liquidated damages, and we may not ultimately find a replacement project or projects that produce the same amount of cash flow as the underperforming project or projects were expected to produce. For a discussion of other construction related risks, please read “—Risks Related to Our Acquisition Strategy and Future Growth—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.”

 

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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 Initial Portfolio are relatively new or have yet to begin operations. Two of our utility projects and two of our C&I projects are in the final stages of construction, four of our utility projects and 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. In addition, 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 in our Initial Portfolio, which have yet to achieve commercial operation, for a substantial portion of our anticipated cash flows.

We depend on certain projects in our Initial Portfolio for a substantial portion of our anticipated cash flows. One of those projects, the Quinto Project, has yet to achieve commercial operation. 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 the projects in our Initial Portfolio, 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 Initial 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, 100% of our Initial Portfolio is 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 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 Initial 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 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 projects are designed specifically for the landscape of each project site and cover a large area. As such, archaeological discoveries could occur at our projects at any time. Such discoveries could result in the restriction or elimination of our ability to operate our business at any 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 will depend 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 Initial Portfolio in which we own an interest, please read “Certain Relationships and Related Party Transactions” in the Prospectus.

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 do not own any of the land on which the projects in our Initial 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 Initial 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

 

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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.

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.

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

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

Risks Related to Our Acquisition Strategy and Future Growth

We may not be successful in implementing our growth strategy of making accretive acquisitions of additional solar energy projects.

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:

 

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

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:

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:

 

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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.

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.

Forty-four states, Washington, D.C. and Puerto Rico have a regulatory policy known as net energy metering, or net metering. Each of the states where we currently serve customers has adopted a net metering policy. Net metering typically 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 may receive solar electricity that is exported to the grid when there is no simultaneous energy demand by the customer without providing retail compensation to the customer for this generation.

Our Residential Portfolio may be adversely impacted by the failure to expand existing limits on the amount of net metering in states that have implemented it, the failure to adopt a net metering policy where it currently is not in place, 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. 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. For example, California utilities limit net metering credit to 5% of the utilities’ aggregate customer peak demand. California has adopted legislation to establish a process and timeline for developing a new net metering program with no cap on participation. If the caps on net metering in California and other jurisdictions 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.

 

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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 commercial operation of up to 30% of eligible basis. A solar energy project must commence commercial operation on or before December 31, 2016, to qualify for the 30% ITC. A solar energy project that commences commercial operation after December 31, 2016, 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 Initial 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.

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:

 

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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.

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.

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 right of first offer agreements (“ROFO Agreements”) with our Sponors 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.

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 can not 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

 

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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 Initial 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 30% multiplied by the cost of eligible assets (10% multiplied by the cost of eligible assets placed in service after December 31, 2016) 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. 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 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.

 

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

The acquisition of existing solar energy projects involves the risk of overpaying for such projects (or not making acquisitions on an accretive basis) and failing to retain the customers of such projects. In addition, upon consummation of an acquisition, such acquisition will be subject to many of the risks set forth above in “—Risks Related to Our Business.” While we will perform due diligence on prospective acquisitions, we may not discover all potential risks, operational issues or other issues in such solar energy projects. In addition, in determining to acquire attractively priced operating solar 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:

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

 

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

 

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As a result of the FPA and FERC’s regulations of transfers of control over public utilities, an investor could be required to obtain FERC approval to acquire shares that would give the investor and its affiliates indirect ownership of 10% or more in our Project Entities.

Some of our Project Entities are “public utilities” as defined in the U.S. Federal Power Act (the “FPA”). Any transfer of direct or indirect control over them requires pre-approval by FERC under FPA Section 203, either under existing blanket authorizations or by application. A violation of FPA Section 203 by us as the seller, or an investor as the purchaser of our voting securities, could subject the party in violation to civil or criminal penalties under the FPA, including civil penalties of up to $1 million per day per violation and other possible sanctions imposed by FERC under the FPA. FERC generally presumes that a direct or indirect holder of 10% or more of a public utility’s voting securities controls the public utility.

We will submit an application to FERC requesting a declaratory order under FPA Section 203 determining that our shares are passive, non-voting securities that will not allow any shareholders to exercise control over our public utility subsidiaries. Unless and until FERC grants our application, we will include restrictions in our Partnership Agreement under which an investor and its affiliates that acquire 10% or more of our shares will lose their voting rights. If FERC grants our application, the 10% restriction will automatically increase to 20%.

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 plan to implement 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 will implement 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. We expect that these offtake agreements will be 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. We expect our largest offtake counterparties to be Southern California Edison and San Diego Gas & Electric. 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 June 28, 2015, the weighted average remaining life of offtake agreements across our Initial Portfolio was 17.3 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 Initial 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 Initial 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 Initial 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 the new credit facilities of OpCo 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 June 28, 2015, the full amount of the

 

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term loan facility and approximately $11.5 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 conditions, 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

 

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

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 officers 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 10% 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 10% (20% if our FERC application is approved) 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

 

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and 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 July 31, 2015, the General Partner and its affiliates, including our Sponsors, own 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 10% (20% if our FERC application is approved) 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 June 28, 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 21.8% 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.

The price of our Class A shares may fluctuate significantly and shareholders could lose all or part of their investment.

Prior to the closing of our IPO, there was no public market for the Class A shares. At June 28, 2015, there were 20,000,000 publicly traded Class A shares. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the Class A shares and limit the number of investors who are able to buy the Class A shares.

The market price of our Class A shares may be influenced by many factors, some of which are beyond our control, including:

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, will 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 will 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, 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.

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

 

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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 Global Select Market (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.

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

We have limited history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act and related rules subsequently implemented by the SEC and the NASDAQ have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on our system of internal controls over financial reporting.

 

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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 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

In addition to reading the following risk factors, if the shareholder is a non-U.S. investor, please read “Certain U.S. Federal Income and Estate Tax Consequences to Non-U.S. Holders” in the Prospectus for a more complete discussion of certain expected U.S. federal income and estate tax consequences of owning and disposing of our Class A shares.

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 Internal Revenue Code of 1986, as amended, or 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

 

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income tax purposes. Distributions paid to non-corporate U.S. shareholders will be subject to U.S. federal income tax at preferential rates, provided that certain holding period and other requirements are satisfied. We estimate that we will have limited earnings and profits for eight or more years. However, it is difficult to predict whether we will generate earnings and profits as computed for U.S. federal income tax purposes in any given tax year, and although we expect that a portion of our distributions to Class A shareholders will exceed our current and accumulated earnings and profits as computed for U.S. federal income tax purposes and therefore constitute a non-taxable return of capital distribution to the extent of a shareholder’s basis in its Class A shares, this may not occur. In addition, although return-of-capital distributions are generally non-taxable to the extent of a shareholder’s basis in its Class A shares, such distributions will reduce the shareholder’s adjusted tax basis in its Class A shares, which will result in an increase in the amount of gain (or a decrease in the amount of loss) that will be recognized by the shareholder on a future disposition of our Class A shares, and to the extent any return-of-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 2. Unregistered Sales of Equity Securities and Use of Proceeds.

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 estimated at $7.5 million and were paid by our Sponsors. In addition, the underwriters reimbursed our Sponsors $2.0 million for certain expenses in connection with our IPO. We also agreed to reimburse the underwriters for up to $30,000 of reasonable fees and expenses of counsel related to the review by the Financial Industry Regulatory Authority, Inc. of the terms of sale of the Class A shares in the 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.

There has been no material change in our use of the net proceeds from the IPO as described in the Prospectus.

 

 

Item 3. Defaults Upon Senior Securities.

None.

 

 

Item 4. Mine Safety Disclosures.

None.

 

 

Item 5. Other Information.

None.

 

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Item 6. Exhibits.

 

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

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Exhibit Index

 

 

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