UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended August 31, 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  x    No  o  

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

Indicate by check mark 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 September 25, 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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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.

“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.

“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.

“ITCs” refers to investment tax credits.

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

 

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“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.

“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.

“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.

 

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“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 U.S. 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.

“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.

 

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

“SunPower ROFO 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 in 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 August 31, 2015, 8point3 Energy Partners LP owned a controlling non-economic managing member interest in 8point3 Operating Company, LLC (“OpCo”) and a 28.2% limited liability company interest in OpCo and the Sponsors collectively owned a noncontrolling 71.8% limited liability company interest in OpCo.

The following table provides an overview of the assets that comprise the Partnership’s 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. The December 28, 2014 balance sheet data was derived from audited financial statements of the Predecessor. 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 condensed consolidated 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.

Reclassifications

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

Fiscal Years

On June 24, 2015, in connection with the closing of the IPO, the Partnership amended its partnership agreement to include a change in the fiscal year to November 30. The Predecessor had a 52-to-53 week fiscal year that ended on the Sunday closest to December 31. Its 2014 fiscal year ended on December 28, 2014 and its 2013 fiscal year ended on December 29, 2013, each of which were 52-week fiscal years. Each of the fiscal quarters in the fiscal years 2014 and 2013 comprised 13 weeks. The first quarter and second quarter of fiscal 2015 ended on March 29, 2015 and June 28, 2015, respectively, and comprised 13 weeks. The third quarter of fiscal 2015 includes the period from June 1, 2015 to August 31, 2015, consistent with the Partnership’s November 30 fiscal year end. The corresponding third quarter for the prior year includes the Predecessor’s period from June 30, 2014 to September 28, 2014.

The accompanying unaudited condensed consolidated financial statements cover the period from December 29, 2014 through August 31, 2015, representing the first eight months of the Partnership’s recently adopted fiscal year. The prior year’s comparable nine-month period covers the period from December 30, 2013 through September 28, 2014 and is reported on the basis of the previous fiscal year end of the Partnership’s Predecessor. As a result of the change in the Partnership’s fiscal year end, the quarterly periods of its newly adopted fiscal year do not coincide with the historical quarterly periods previously reported by its Predecessor. Financial information for the three and eight months ended August 31, 2014 has not been included in this Form 10-Q for the following reasons: (i) the three and nine months ended September 28, 2014 provide as meaningful a comparison to the three and eight months ended August 31, 2015 as would the three and eight months ended August 31, 2014; (ii) the Partnership believes that there are no significant factors, seasonal or other, that would impact the comparability of information if the results for the three and eight months ended August 31, 2014 were presented in lieu of results for the three and nine months ended September 28, 2014; and (iii) it was not practicable or cost justified to prepare this information.

Management Estimates

The preparation of the unaudited condensed consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the unaudited condensed consolidated financial statements and accompanying notes. Significant estimates in these unaudited 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.

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

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 eight months ended August 31, 2015, $0.3 million and $2.5 million, respectively, has been deferred and capitalized, and $0.2 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. The Partnership has interest rate swap agreements that economically hedge the cash flows for the term loan facility, which are not designated as cash flow hedges. Therefore, the changes in fair value are recorded in other expense in the unaudited condensed consolidated statement of operations as these hedges are not accounted for under hedge accounting. In addition, the Predecessor entered into interest rate swap agreements, designated as cash flow hedges, in the fourth quarter of the year ended December 28, 2014 on the outstanding and forecasted future borrowings under the Quinto Credit Facility to reduce the impact of changes in interest rates; unrealized gains and losses of the effective portion of derivative financial instruments are excluded from earnings and reported as a component of accumulated other comprehensive loss in the condensed consolidated balance sheets. The ineffective portion of derivatives financial instruments are included in other expense (income), net in the condensed consolidated statements of operations.

Comprehensive Income (Loss)

Comprehensive income (loss) is defined as the change in equity during a period from non-owner sources. The Partnership’s comprehensive income (loss) for each period presented is comprised of (i) its net income (loss); and (ii) changes in unrealized gains or losses for the effective portion of derivatives designated as cash flow hedges.

Equity Method Investments

The Partnership uses the equity method of accounting for equity investments where it has the ability to significantly influence the operations or financial decisions of the investee but does not own a majority interest. It considers the participating and protective rights it has as well as the legal form of the investee when evaluating whether it has the ability to exercise significant influence. Equity method investments are included in “Investment in unconsolidated affiliates” in the accompanying 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 eight months ended August 31, 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 August 31, 2015. Highly liquid investments with original or remaining maturities of 90 days or less at the time of purchase are considered cash equivalents.

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

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 and test electricity generation customers, respectively, 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 August 31, 2015 and December 28, 2014, no allowance for doubtful accounts related to operating leases had been recorded.

Financing receivables:    Leases are classified as either operating or sales-type leases in accordance with the relevant accounting guidance. Financing receivables are generated by solar energy systems leased to residential customers under sales-type leases. Financing receivables represent gross minimum lease payments to be received from customers and the systems’ estimated residual value, net of executory costs, unearned income and allowance for estimated losses.

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 August 31, 2015 and December 28, 2014, $0.3 million and zero, respectively, had been recorded as allowance for losses on financing receivables.

Property and Equipment

 

Property and equipment, including photovoltaic (“PV”) solar power systems, are stated at cost, less accumulated depreciation. Leased solar energy systems are depreciated to their estimated residual value using the straight-line method over the lease term of 20 years. Any energy generated by PV solar power systems prior to being placed into service or investment tax credit to which a Sponsor is entitled, reduces the carrying value of the asset by the related amount. Depreciation expense for PV solar power systems is computed using the straight-line method over the shorter of the term of the estimated useful life or the lease on the land. The estimated useful life of a system is reassessed whenever applicable facts and circumstances indicate a change in the estimated useful life of such system has occurred. The estimated useful life of all solar energy systems is 30 years and all systems are physically located in the United States. Depreciation expense for the three and eight months ended August 31, 2015 was $1.2 million and $2.4 million, respectively, and was $0.7 million and $1.6 million for the three and nine months ended September 28, 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 August 31, 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 or terminations. The impairment evaluation of leased solar energy systems includes an analysis of estimated future undiscounted net cash flows expected to be generated by the assets over their remaining estimated useful lives. If the estimate of future undiscounted net cash flows is insufficient to recover the carrying value of the assets over the remaining estimated useful lives, the Partnership records an impairment loss in the amount by which the carrying value of the assets exceeds the fair value. Fair value is generally measured based on either quoted market prices, if available, or discounted cash flow analyses.

With respect to 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

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

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 eight months ended August 31, 2015 was $2.1 million and $3.8 million, respectively, and during the three and nine months ended September 28, 2014 was $0.1 million and $1.2 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 $8.5 million as of August 31, 2015. The Predecessor had not accrued any AROs as of December 28, 2014 since it had not significantly commenced construction on any of the projects on the sites.

Contingencies

 

The Partnership is involved in conditions, situations or circumstances in the ordinary course of business with possible loss contingencies, such as system output performance warranty and residential lease system repairs, that will ultimately be resolved when one or more future events occur or fail to occur. In certain circumstances, the Partnership has hired service providers to mitigate the potential risk of loss. For example, the Partnership provides system output performance warranties under residential lease agreements with homeowners. The operations and maintenance (“O&M”) provider, currently a subsidiary of SunPower, also provides system output performance warranties to the Partnership equivalent to those offered by the Partnership to homeowners.  As a result, the Partnership records liabilities in connection with these items offset by a corresponding amount in other assets as due from the O&M provider on its consolidated financial statements. As of August 31, 2015, the Partnership recorded $1.4 million in other current liabilities related to system output performance warranties and system repairs and a corresponding amount due from SunPower in other current assets.

If some amount within a range of loss appears at the time to be a better estimate than any other amount within the range, that amount will be accrued. When no amount within the range is a better estimate than any other amount, however, the minimum amount in the range will be accrued. The Partnership continually evaluates uncertainties associated with loss contingencies and records a charge equal to at least the minimum estimated liability for a loss contingency when both of the following conditions are met: (i) information available prior to issuance of the financial statements indicates that it is probable that an asset had been impaired or a liability had been incurred at the date of the financial statements; and (ii) the loss or range of loss can be reasonably estimated.

Product Warranties

The Sponsors as the manufacturers generally warrant the performance of the solar panels that they manufacture at certain levels of power output for 25 years. In addition, long-term warranties from the original equipment manufacturers of certain system components, such as inverters, are passed through to customers. Warranties of 25 years from solar panel suppliers are standard in the solar industry, while inverters typically carry warranty periods ranging from five to 10 years. In addition, the Sponsors as providers of engineering, procurement and construction (“EPC”) services generally warrant the workmanship on installed systems for periods ranging up to 10 years, and the Sponsors as providers of O&M services pursuant to the O&M agreements also provide system output performance warranties or availability guarantees. The Predecessor recorded product warranty reserve in connection with the sales-type leases based on its best estimate of such costs and recognized it as a cost of operations. Since the Partnership receives product warranties from its original equipment manufacturers, it no longer records product warranties on its unaudited condensed consolidated financial statements as of August 31, 2015.

 

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Segment Information

The Partnership manages its Initial Portfolio as one segment that operates a portfolio of solar energy generation systems. It operates as a single reportable segment based on the “management” approach.

All operating revenues for the three and eight months ended August 31, 2015 and the three and nine months ended September 28, 2014 were from customers located in the United States. Operating revenues from a customer accounted for 32% and 15% of total operating revenues for the three months and eight months ended August 31, 2015, respectively.

Revenue Recognition

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

Sales-type leases:    Certain residential leased solar energy systems are classified as sales-type leases because the net present value (“NPV”) of the minimum lease payments per the contract, excluding the portion of payments representing executory costs, equals or exceeds 90% of the excess of the fair value of the leased property to the lessor at lease inception. For such solar energy systems, the NPV of the minimum lease payments, net of executory costs, is recognized as revenue when the lease is placed in service. This NPV includes fixed and determinable state or local rebates defined in the minimum lease payments under the lease but excludes performance-based incentives (“PBI Rebates”) because these rebates are not fixed and determinable as they relate to the generation of electricity from the leased solar energy system, and therefore, represent contingent revenue recognized upon cash receipt. This NPV, as well as that of the residual value of the lease at termination, are recorded as financing receivables in the condensed consolidated balance sheets. The difference between the initial net amounts and the gross amounts is amortized to revenue over the lease term using the effective interest method. Revenue representing executory costs to operate and maintain the leased solar energy system is recognized on a straight-line basis over the 20-year lease term. The residual values of solar energy systems are determined at the inception of the lease applying an estimated system fair value at the end of the lease term. As all the leases owned by the Predecessor have been placed into service, all revenue related to the NPV of the minimum lease payments has been recognized as of December 28, 2014. Accordingly, other than interest revenue, there was no sales-type lease revenue recognized on the unaudited condensed consolidated financial statements for the three and eight months ended August 31, 2015.

 

Operating leases:    For those residential systems classified as operating leases, revenue associated with renting the solar energy system and executory costs is recognized on a straight-line basis over the 20-year lease term. State or local rebates defined in the minimum lease payments under the lease that are deemed fixed and determinable are recorded as deferred revenue in the condensed consolidated balance sheets when the lease is placed in service and amortized to revenue on a straight-line basis over the 20-year lease term. PBI Rebates representing contingent revenue are recognized upon cash receipt. In addition, the Partnership also recognizes lease revenue for the Maryland Solar Project, which is subject to a solar lease agreement that expires on December 31, 2019, with an affiliate of First Solar as the lessee. Revenue generated primarily from various non-affiliated parties under long-term PPA contracts are accounted for as operating leases.

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

Noncontrolling Interests

Noncontrolling interests represent the portion of net assets in consolidated subsidiaries that are not attributable, directly or indirectly, to the Partnership. The largest portion of noncontrolling interest in the Partnership relates to the Sponsor’s ownership in OpCo.  In addition, the Partnership has entered into certain tax equity transactions with third-party investors under which the investors are determined to hold noncontrolling interests in entities fully consolidated by OpCo. The net assets of the shared entities are attributed to the controlling and noncontrolling interests based on the terms of the governing contractual arrangements. Therefore, for the tax equity transactions, the Partnership further determined the hypothetical liquidation at book value method (the “HLBV Method”) to be the appropriate method for attributing net assets to the controlling and noncontrolling interests as this method most closely mirrors the economics of the governing contractual arrangements. Under the HLBV Method, the Partnership allocates recorded income (loss) to each investor based on the change, during the reporting period, of the amount of net assets each investor is entitled to under the governing contractual arrangements in a liquidation scenario. The Partnership accounts for the portion of net

 

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assets using the HLBV Method in the consolidated entities attributable to the investors as “Redeemable noncontrolling interests” and “Noncontrolling interests” in its unaudited condensed consolidated financial statements. Noncontrolling interests in subsidiaries that are redeemable at the option of the noncontrolling interest holder are classified as “Redeemable noncontrolling interests in subsidiaries” between liabilities and equity on the condensed consolidated balance sheets. 

Cost of Operations

Cost of operations includes O&M costs related to the operating projects as well as cost recognized on sales-type leases and is recognized when the leased solar energy system is placed in service or sold. Cost recognized on sales-type leases includes initial direct 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.

 

Share-Based Compensation Expense

The Partnership measures compensation expense for all share-based payment awards based on estimated grant-date fair values of Class A shares, and accounts for share-based compensation expense by amortizing the fair value on a straight-line basis over the requisite vesting period, less estimated forfeitures. Share-based compensation expenses for the three and eight months ended August 31, 2015 were $0.1 million and were included in SG&A expense.

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

 

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

 

 

Note 3. Business Combinations

Acquisition accounting is dependent upon certain valuations and other studies that must be completed as of the acquisition date. The judgments made in the context of the purchase price allocation can materially impact the Partnership’s future results of operations. For the acquisitions completed during the eight months ended August 31, 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.

 

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.  

 

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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 August 31, 2015 are as follows:

 

 

The following table presents summarized financial information for SG2 Holdings, LLC (“SG2 Holdings”) and NS Solar Holdings, LLC (“North Star Holdings”), significant investees, as derived from the respective unaudited condensed consolidated financial statements of SG2 Holdings and NS Holdings for the three and eight months ended August 31, 2015:

 

 

 

 

 

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Note 5. Balance Sheet Components

Financing Receivables

The Partnership’s net investment in sales-type leases presented in “Accounts receivable and short-term financing receivables, net” and “Long-term financing receivables, net” on the condensed consolidated balance sheets is as follows:

 

 

 

 

 

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Note 6. Commitments and Contingencies

Land Use Commitments

The Partnership is a party to various agreements that provide for payments to landowners for the right to use the land upon which projects under PPAs are located. Total lease and easement expense was $0.1 million and $1.1 million in the three and eight months ended August 31, 2015, respectively, and $0.5 million and $1.0 million in the three and nine months ended September 28, 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 August 31, 2015 under these land use agreements are as follows:

 

 

 

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Product Warranties

The following table summarizes accrued warranty activity for the three and eight months ended August 31, 2015 and the three and nine months ended September 28, 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 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 $0.3 million and $0.5 million as of August 31, 2015 and December 28, 2014, respectively. The Partnership has also recorded in “Other current assets” amounts of $0.3 million and zero as of August 31, 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 eight months ended August 31, 2015 and three and nine months ended September 28, 2014:

 

 

Asset Retirement Obligations

The Partnership’s AROs are based on estimated third-party costs associated with the decommissioning of the applicable project assets. These costs may increase or decrease in the future as a result of changes in regulations, engineering designs and technology, permit modifications, inflation, or other factors. Decommissioning activities generally are made over a period of time commencing at the end of the system’s life.

The following table summarizes ARO activity for the three and eight months ended August 31, 2015 and the three and nine months ended September 28, 2014, respectively:

 

 

 

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Legal Proceedings

In the normal course of business, the Partnership may be notified of possible claims or assessments. The Partnership will record a provision for these claims when it is both probable that a liability has been incurred and the amount of the loss, or a range of the potential loss, can be reasonably estimated. These provisions are reviewed regularly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information or events pertaining to a particular case.

Although the Partnership may, from time to time, be involved in litigation and claims arising out of its operations in the ordinary course of business, the Partnership is not a party to any litigation or governmental or other proceeding that the Partnership believes will have a material adverse impact on its financial position, results of operations, or liquidity.

Environmental Contingencies

The Partnership reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. During the three and eight months ended August 31, 2015 and the three and nine months ended September 28, 2014, there were no known environmental contingencies that required the Partnership to recognize a liability.

 

 

Note 7. Lease Agreements and Power Purchase Agreements

Lease Agreements

As of August 31, 2015, the Partnership’s unaudited 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 August 31, 2015:

 

 

As of August 31, 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.  

 

 

 

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Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

Note 8. Debt and Financing Obligations

Term Loan and Revolving Credit Facility

On June 5, 2015, OpCo entered into a $525.0 million credit facility, consisting of a $300.0 million term loan facility, a $25.0 million delayed draw term loan facility and a $200.0 million revolving credit facility. OpCo borrowed $300.0 million under the term loan facility on June 5, 2015, which indebtedness will mature on the fifth anniversary of its issuance, at which point all amounts outstanding under the term loan facility will become due and payable. There will be no principal amortization over the term of the facility. The discount and incremental debt issuance costs associated with 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 August 31, 2015, the full amount of the $300.0 million term loan facility and approximately $9.4 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 collateralized by a pledge of the equity of OpCo and certain of its domestic subsidiaries. The Partnership and each of OpCo’s domestic subsidiaries, other than certain non-guarantor subsidiaries, have guaranteed the obligations of OpCo under the credit facility.

 

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 up to $775.0 million in the aggregate, with any increase in the revolving credit facility not to exceed $100.0 million. The term loan bears an interest rate of approximately 2.33% per annum as of August 31, 2015. OpCo has entered into interest rate swap agreements to hedge the interest rate on the borrowings under the term loan facility. See Note 9 for more details.

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 August 31, 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

 

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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 eight months ended August 31, 2015 and the three and nine months ended September 28, 2014, respectively, and was recognized as interest expense in the condensed consolidated statement of operations.

Residential Lease Financing

The Predecessor entered into two financing arrangements under which leased solar energy systems were financed by two third-party investors. Under the terms of these financing arrangements, the investors provided upfront payments to the Predecessor, which the Predecessor recognized as a financing obligation that is reduced over the specified term of the arrangement as customer receivables and federal cash grants are received by the third-party investors. Non-cash interest expense is recognized on the Partnership’s condensed consolidated statements of operations using the effective interest rate method calculated at a rate of approximately 14%-15%.

 

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

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

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

August 2011 Letter of Credit Facility with Deutsche Bank

In August 2011, the Predecessor’s parent, SunPower, entered into a letter of credit facility agreement for the Quinto Project 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 August 31, 2015 and December 28, 2014, letters of credit issued and outstanding under the August 2011 letter of credit facility with Deutsche Bank totaled $30.5 million and $38.3 million, respectively. The associated fees incurred for the letters of credit to Deutsche Bank were $0.1 million and $0.4 million, respectively, during the three and eight months ended August 31, 2015 and $0.2 million and $0.4 million, respectively, during the three and nine months ended September 28, 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.

 

 

 

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Note 9. Fair Value

Fair value is estimated by applying the following hierarchy, which prioritizes the inputs used to measure fair value into three levels and bases the categorization within the hierarchy upon the lowest level of input that is available and significant to the fair value measurement (observable inputs are the preferred basis of valuation):

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

 

 

On July 17, 2015, OpCo entered into interest swap agreements intended to hedge the interest rate risk on the outstanding and forecasted future borrowings under the term loan with an aggregate notional value of $240.0 million. Under the interest rate swap agreements, OpCo will pay a fixed swap rate of interest of 1.55% and the counterparties to the agreements will pay a floating interest rate based on three-month LIBOR at quarterly intervals through the maturity date of August 31, 2018. OpCo also has the right to cancel the interest rate swap agreements on August 31, 2016 and any quarterly fixed payment date thereafter with a minimum of five business days’ notification. As of August 31, 2015, these interest rate swap agreements had not been designated as cash flow hedges. The fair value of these interest rate swap agreements have been presented in other current liabilities on the unaudited condensed consolidated balance sheet since OpCo has the right to cancel the swap agreements within one year of the balance sheet date. During both the three and eight months ended August 31, 2015, the Partnership recorded a change in fair value of $0.8 million within other expense.  The primary inputs into the valuation of interest rate swaps are interest yield curves, interest rate volatility, and credit spreads. The Partnership's interest rate swaps are classified within Level 2 of the fair value hierarchy, since all significant inputs are corroborated by market observable data. There were no transfers in or out of Level 1, Level 2 and Level 3 during the period.  

The Predecessor entered into interest rate swap agreements, designated as cash flow hedges, in the fourth quarter of the year ended December 28, 2014 on the outstanding and forecasted future borrowings under the Quinto Credit Facility to reduce the impact of changes in interest rates. As of August 31, 2015 and December 28, 2014, the Predecessor had interest rate swap agreements designated as cash flow hedges with an aggregate notional value of zero and $238.0 million, respectively. These swap agreements allowed the Predecessor to effectively convert floating-rate payments into fixed-rate payments periodically over the life of the agreements. These derivatives had a maturity of more than 12 months. The Predecessor assessed the effectiveness of these cash flow hedges at inception and on a quarterly basis. If it was determined that a derivative instrument was not highly effective or the transaction was no longer deemed probable of occurring, the Predecessor discontinued hedge accounting and recognized the ineffective portion in current period earnings. The hedge became ineffective in the three months ended March 28, 2015 and the ineffective portion was recognized in earnings at that time. The interest swap was terminated upon the IPO and the remaining ineffective portion was recognized in earnings during the three months ended August 31, 2015. During the three months ended August 31, 2015, $2.7 million was reclassified into loss on cash flow hedges within other expense, net in the condensed consolidated statement of operations, as the transaction was terminated. During the eight months ended August 31, 2015 and the nine months ended

 

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September 28, 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.

Other Fair Value Disclosures

As of August 31, 2015, the estimated fair value of the Partnership’s long-term debt approximated its carrying value.

 

 

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 August 31, 2015, First Solar and SunPower had noncontrolling interests of 31.1% and 40.7%, respectively, in OpCo.

In addition, certain subsidiaries of OpCo have entered into tax equity financing facilities with third-party investors under which the parties invest in entities that hold the solar power systems. The Partnership, through OpCo, holds controlling interests in these less-than-wholly-owned entities and has therefore fully consolidated these entities. The Partnership accounts for the portion of net assets using the HLBV Method in the consolidated entities attributable to the investors as "Redeemable noncontrolling interests" and "Noncontrolling interests" in its unaudited condensed 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 August 31, 2015, redeemable noncontrolling interests and noncontrolling interests were $2.1 million and $4.3 million, respectively. During the three and eight months ended August 31, 2015 and during the three and nine months ended September 28, 2014, such subsidiaries of OpCo received $7.0 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 August 31, 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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Note 12. Shareholders’ Equity

The Partnership’s Class A shares and Class B shares represent limited partner interests in the Partnership. The Partnership’s partnership agreement authorizes the issuance of an unlimited number of Class A shares and Class B shares. The number of Class A shares issued by the Partnership will at all times equal the number of OpCo common units held by the Partnership. The number of Class B shares issued by the Partnership will at all times equal the aggregate number of OpCo common and subordinated units held by persons or entities other than the Partnership. The holders of Class A shares and Class B shares are entitled to exercise the rights or privileges available to limited partners under the partnership agreement, but only holders of Class A shares are entitled to participate in the Partnership’s distributions. The Partnership is required to distribute its available cash (as defined in the Partnership’s partnership agreement) to the holders of Class A shares each quarter.  The Partnership’s Class A shareholders and Class B shareholders have only limited voting rights and at times vote together or as separate classes. These voting rights include, but are not limited to, certain amendments to the Partnership’s partnership agreement, merger or dissolution of the Partnership or the sale of all or substantially all of the Partnership’s assets and removal of the General Partner.  The Partnership’s shareholders are not entitled to elect the General Partner or its directors.  If at any time the General Partner and its affiliates control more than 80% of the aggregate of (i) the number of Class A shares then outstanding and (ii) the number of Class B shares equal to the number of OpCo common units owned by the Sponsors and their affiliates, the General Partner will have the right to acquire all, but not less than all, of the shares of such class then outstanding held by unaffiliated persons as of a record date to be selected by the General Partner, on at least ten but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of (i) the highest cash price paid by either of the General Partner or any of its affiliates for any share of the class purchased within the 90 days preceding the date on which the General Partner first mails notice of its election to purchase those shares; and (ii) the current market price calculated in accordance with the Partnership’s partnership agreement as of the date three business days before the date the notice is mailed. The Partnership is a party to an Exchange Agreement whereby it has agreed in certain situations to issue Class A shares to the Sponsors in exchange for an equal number of Class B shares and OpCo common units.  Alternatively, each of OpCo and Partnership have the right, with the approval of the conflicts committee, to acquire such Class B shares and OpCo common units for cash.

OpCo’s equity consists of common units and subordinated units and incentive distribution rights (“IDRs”), which represent a variable interest in distributions after certain distribution thresholds are met.  OpCo’s limited liability company agreement authorizes the issuance of an unlimited number of common units and subordinated units.  OpCo is required to distribute its available cash (as defined in OpCo’s limited liability company agreement) to the holders of its common units, subordinated units and IDRs each quarter.  Distributions, other than liquidating distributions, are made to such holders according to a predetermined waterfall.  During the subordination period, OpCo’s common units have a preference on such distributions until each unit has received the minimum quarterly distribution for such quarter and any arrearages on the minimum quarterly distribution for previous quarters and OpCo’s common units and subordinated units have a preference on such distributions until each unit has received 150% of the minimum quarterly distribution for such quarter. Thereafter, the IDRs are entitled to an increasing amount of any excess distributed.  After the subordination period, holders of OpCo units have a preference over the IDRs on such distributions until each unit has received 150% of the minimum quarterly distribution for such quarter. In addition, during the forbearance period, the OpCo common units, subordianted units and IDRs held by the Sponsors are not entitled to any distributions. Liquidating distributions are made according to the balance in each holder’s capital account upon liquidation.  Similar to the voting rights of Class A shareholders and Class B shareholders, OpCo’s common unitholders and subordinated unitholders have only limited voting rights and at times vote together or as separate classes.  These voting rights include, but are not limited to, certain amendments to OpCo’s limited liability company agreement, merger or dissolution of OpCo or the sale of all or substantially all of OpCo’s assets.  Holders of IDRs have no voting rights.

Initial Public Offering

On June 24, 2015, the Partnership completed its IPO by issuing 20,000,000 of its Class A shares representing limited partner interests in the Partnership at a price to the public of $21.00 per share for aggregate gross proceeds of $420.0 million. The underwriting discount of $23.1 million and the structuring fee of $3.2 million paid to the underwriters, for a total of $26.3 million, were deducted from the gross proceeds from the IPO. This amount excludes offering expenses, which were paid by the Sponsors. On June 18, 2015, the Partnership granted the underwriters an option to purchase for 30 days after the date of the Prospectus up to an additional 3,000,000 Class A shares representing limited partner interests in the Partnership at the IPO price less underwriting discount and structuring fee. If the underwriter’s option to purchase additional shares was unexercised in full, OpCo would be required to issue in the aggregate to SunPower and First Solar an amount of common units equal to the amount of Class A shares subject to the underwriter’s option to purchase additional shares that remained unexercised. Additionally, under OpCo’s limited liability company agreement, in the event OpCo issues common units to any person or entity other than the Partnership, the Partnership agreed to issue the same number of Class B shares to such other person or entity. As a result of the expiration of the underwriter’s option to purchase

 

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Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

additional shares without the exercise of any portion thereof, the Partnership issued additional Class B shares of 1,300,995 and 1,699,005 to First Solar and SunPower, respectively.  As of August 31, 2015, the Partnership owned a 28.2% limited liability company interest in OpCo as well as a controlling noneconomic managing member interest in OpCo and the Sponsors collectively owned 51,000,000 Class B shares in the Partnership, with SunPower and First Solar having owned 28,883,075 and 22,116,925 Class B shares, respectively, and together, having owned a noncontrolling 71.8% limited liability company interest in OpCo.

The Partnership received net proceeds of $393.8 million from the sale of the Class A shares after deducting underwriting fees and structuring fees (exclusive of offering expenses paid by the Sponsors).

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

As of August 31, 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 and filed a Form S-8 for its LTIP on July 14, 2015. Awards under the LTIP may consist of unrestricted shares, restricted shares, restricted share units, options, share appreciation rights and distribution equivalent rights. The LTIP limits the number of shares that may be delivered pursuant to awards to 2,000,000 Class A shares and provides that no director may receive awards in any calendar year with a grant date value in excess of $250,000. Shares that are withheld to satisfy exercise price or tax withholding obligations are available for delivery pursuant to other awards.

The LTIP will expire upon the earliest of the date established by the board of directors or a committee thereof, the tenth anniversary of its adoption or the date that no shares remain available under the LTIP for awards. Upon termination of the LTIP, awards then outstanding will continue pursuant to the terms of their grants. Class A shares to be delivered pursuant to awards under the LTIP may be Class A shares acquired in the open market, Class A shares already owned by the General Partner, Class A shares acquired by the General Partner from the Partnership or from any other person, or any combination thereof.

Participants will not pay any consideration for the Class A shares they receive, nor will the Partnership receive any remuneration for these shares as the Partnership intends these awards to serve as a means of incentive compensation for performance. The committee has the discretion to determine the employees, consultants and directors to whom equity awards shall be granted, the number of shares to be granted, and the vesting and other terms of the award as applicable (such as whether the award will be based on the achievement of specific financial or performance metrics).

The Partnership measures compensation expense for all share-based payment awards based on estimated grant-date fair values of Class A shares, and accounts for share-based compensation expense by amortizing the fair value on a straight-line basis over the requisite vesting period, less estimated forfeitures. During the three months ended August 31, 2015, the Partnership issued an aggregate of 2,679 Class A shares to the three independent members of the board of directors. These shares were unrestricted and had no vesting period. Share-based compensation expenses for the three and eight months ended August 31, 2015 were $0.1 million and were included in SG&A expense.    

 

 

 

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Note 14. Net Income Per Share

Basic net income per share is computed by dividing net income from the IPO completion date of June 24, 2015 to the three and eight month periods ended August 31, 2015 attributable to Class A shareholders by the weighted average number of Class A shares outstanding for the applicable periods. Diluted net income per share is computed using basic weighted average Class A shares outstanding plus, if dilutive, any potentially dilutive securities outstanding during the period using the treasury-stock-type method. Pursuant to the Exchange Agreement, among the Partnership, the General Partner, OpCo, a wholly owned subsidiary of SunPower and a wholly owned subsidiary of First Solar, the Sponsors can tender OpCo common units and an equal number of such Sponsor’s Class B shares for redemption, and the Partnership has the right to directly purchase the tendered units for, subject to the approval of its conflicts committee, cash or Class A shares. If Class B shares were converted into Class A shares, the net income attributable to Class A shares would proportionately increase, resulting in no change to net income per share for the period from the IPO closing date to the quarter ended August 31, 2015. In addition, there were no potentially dilutive securities (including any stock options, restricted stock and restricted stock units) for the three and eight months ended August 31, 2015, respectively. Accordingly, basic and diluted net income per share were the same for each of the three and eight months ended August 31, 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

 

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and management services for the Partnership and certain of its subsidiaries, including managing the Partnership’s day-to-day affairs, in addition to those services that are provided under existing O&M agreements and asset management agreements (“AMAs”) between affiliates of the Sponsors and certain of the subsidiaries of the Partnership. In August 2015, the First Solar MSA and the SunPower MSA were amended to adjust the annual management fee payable to each respective Service Provider. In the case of the First Solar MSA, OpCo will initially pay an annual management fee of $0.6 million to the First Solar Service Provider. In the case of the SunPower MSA, OpCo will initially pay an annual management fee of $1.1 million to the SunPower Service Provider. These payments will be 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 $0.3 million for each of the three and eight months ended August 31, 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 August 31, 2015, certain projects contributed by SunPower are construction in progress and expected to achieve COD within the next quarter.  SunPower as the EPC provider is required to complete the projects and pursuant 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 $16.5 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 or availability guarantees, to the subsidiaries of the Partnership in exchange for fixed annual fees, which are subject to certain adjustments.

O&M services to the leased solar energy systems, also known as executory costs, were allocated to the Predecessor by SunPower and disclosed as cost of operations-SunPower in the combined carve-out statement of operations of the Predecessor (as presented in the Prospectus). Costs incurred for these services were $0.1 million and $0.2 million for the three months ended August 31, 2015 and September 28, 2014, respectively, and $0.5 million and $0.7 million for the eight and nine months ended August 31, 2015 and September 28, 2014, respectively.

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.

In August 2015, the Omnibus Agreement was amended to provide that (i) with respect to each of the North Star Project and the Quinto Project, which were contributed to the Partnership by First Solar and SunPower, respectively, the Sponsors agreed to pay to OpCo the difference, if any, between the amount of network upgrade refunds projected to be received in respect of the sponsor’s

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

project at the time of contribution and the amount of network upgrade refunds projected to be received in respect of such project at the commencement of commercial operation of such project; and (ii) SunPower agreed to indemnify OpCo for certain costs it may incur in connection with the termination of certain tax equity financing arrangements relating to the contributed residential lease portfolios, which occurred before the Partnership’s IPO.

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 to the PSAs, the purchase price will be paid in installments. The purchase price payments remaining as of August 31, 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 August 31, 2015, the SP Holding Companies received as capital contributions from tax equity investors a total amount of $7.0 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 $193.0 million as of August 31, 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 $0.8 million and $4.8 million in the three and eight months ended August 31, 2015 and $0.4 million and $0.8 million in the three and nine months ended September 28, 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 the tax impact of equity in earnings, valuation allowances during the Predecessor period, the tax impact of noncontrolling interest, a permanent difference between the amount recognized as deductible for GAAP and tax purposes related to board of director stock compensation, and state tax rates (net of federal benefit) in various jurisdictions, most significantly California. All tax expense

 

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8point3 Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 

after the IPO closing date is deferred tax expense and the Partnership has not paid any cash taxes in the period after the IPO closing date covered by these unaudited condensed consolidated financial statements.

The Partnership’s financial reporting year-end is November 30 while its tax year-end is December 31. The Partnership has elected to base the tax provision on the financial reporting year; therefore, it will have no taxable income in 2015.  The provision accrued at the financial reporting year-end will be a discrete period computation, and the tax credits and permanent differences recognized in that accrual will be those generated between the 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 unaudited condensed consolidated financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of the differences between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

The Partnership recognizes deferred tax assets to the extent that it believes these assets are more likely than not to be realized. In making such a determination, the Partnership considers all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning strategies, and results of recent operations. If the Partnership determines that it would be able to realize its deferred tax assets in the future in excess of their net recorded amount, it would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.

The Partnership records uncertain tax positions in accordance with ASC 740 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 manages its Initial Portfolio as one segment that operates a portfolio of solar energy generation systems. It operates as a single reportable segment based on the “management” approach.

All operating revenues for the three and eight months ended August 31, 2015 and the three and nine months ended September 28, 2014 were from customers located in the United States. Operating revenues from a customer accounted for 32% and 15% of total operating revenues for the three and eight months ended August 31, 2015, respectively. Long-lived assets consisting of property and equipment, net, were located in the United States.

 

 

Note 18. Subsequent Events

 

The Partnership declared a third quarter distribution for its Class A shares of $0.157 per share, the prorated minimum quarterly distribution for the post-IPO period from June 24, 2015 to August 31, 2015 consistent with the Partnership’s fiscal year change and timing of the IPO. The third quarter distribution will be paid on October 15, 2015 to shareholders of record as of October 1, 2015.

 

 

 

 

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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 for and as of the three and eight months ended August 31, 2015 and the three and nine months ended September 28, 2014, respectively and the notes thereto included elsewhere in this Quarterly Report on Form 10-Q. The unaudited condensed consolidated 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.

As of August 31, 2015, we owned a controlling non-economic managing member interest and a 28.2% limited liability company interest in OpCo and our Sponsors collectively owned a noncontrolling 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’ noncontrolling 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 August 31, 2015, we owned a 28.2% limited liability company interest in OpCo as well as a controlling non-economic managing member interest in OpCo and the Sponsors collectively own 51,000,000 Class B shares in the Partnership, with SunPower and First Solar owning 28,883,075 and 22,116,925 Class B shares, respectively, and together owning a noncontrolling 71.8% limited liability company interest in OpCo.

In connection with the IPO, OpCo entered into a $525.0 million senior secured credit facility, consisting of a $300.0 million term loan facility, a $25.0 million delayed draw term loan facility and a $200.0 million revolving credit facility. As of August 31, 2015, the full amount of the term loan facility and approximately $9.4 million of letters of credit under the revolving credit facility were outstanding. The remaining portion of the revolving credit facility and the delayed draw term loan facility are undrawn. Our ability to borrow under the revolving credit facility and the delayed draw term loan facility and our ability to access the debt and equity capital markets should provide us with the financial flexibility to pursue acquisition opportunities. As of August 31, 2015, none of our Project Entities had any indebtedness for borrowed money.

As of August 31, 2015, we owned 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 August 31, 2015, the weighted average remaining life of offtake agreements across our Initial Portfolio was 21.8 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).

We used all of the net proceeds of the IPO to purchase 20,000,000 OpCo common units from OpCo. OpCo used (i) approximately $154.4 million of such net proceeds to make a cash distribution to First Solar, (ii) approximately $201.6 million of

 

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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 August 31, 2015, the weighted average remaining life of offtake agreements across our Initial Portfolio was 21.8 years, with the offtake agreements of our Utility Project Entities having remaining terms ranging from 17.6 to 28.3 years and our C&I offtake agreements and residential offtake agreements having remaining terms ranging from 17.1 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 evaluate are Adjusted EBITDA and cash available for distribution.

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

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

However, Adjusted EBITDA has limitations as an analytical tool because it does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments, does not reflect changes in, or cash requirements for, working capital, does not reflect significant interest expense or the cash requirements necessary to service interest or principal payments on our outstanding debt or cash distributions on tax equity, does not reflect payments made or future requirements for income taxes, and

 

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excludes the effect of certain other cash flow items, all of which could have a material effect on our financial condition and results of operations. Adjusted EBITDA is a non-U.S. GAAP measure and should not be considered an alternative to net income, net cash provided by (used in) operating activities or any other performance or liquidity measure determined in accordance with U.S. GAAP, nor is it indicative of funds available to fund our cash needs. In addition, our calculations of Adjusted EBITDA are not necessarily comparable to EBITDA as calculated by other companies. Investors should not rely on these measures as a substitute for any U.S. GAAP measure, including net income or net cash provided by (used in) operating activities.

Cash Available for Distribution.    Although we have not quantified cash available for distribution on a historical basis, we use cash available for distribution, which we define as Adjusted EBITDA less equity in earnings of unconsolidated affiliates, cash interest paid, cash income taxes paid, maintenance capital expenditures, cash distributions to noncontrolling interests and principal amortization of indebtedness plus cash distributions from unconsolidated affiliates, test electricity generation and cash proceeds from sales-type residential leases. Our cash flow is generated from distributions we receive from OpCo each quarter. OpCo’s cash flow is generated primarily from distributions from the Project Entities. As a result, our ability to make distributions to our Class A shareholders depends primarily on the ability of the Project Entities to make cash distributions to OpCo and the ability of OpCo to make cash distributions to its unitholders.

We believe cash available for distribution is useful to investors in evaluating our operating performance because securities analysts and other interested parties use such calculations as a measure of our ability to make our minimum quarterly distribution. In addition, cash available for distribution is used by our management team for determining future acquisitions and managing our growth. The U.S. GAAP measures most directly comparable to cash available for distribution are net income and net cash provided by 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.

 

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The following table presents a reconciliation of net income to Adjusted EBITDA and Cash Available for Distribution for the three and eight months ended August 31, 2015 and the three and nine months ended September 28, 2014:

 

 

 

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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 unaudited 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.    The Predecessor’s historical combined carve-out financial statements (as presented in the Prospectus) included SG&A expenses that have historically included direct charges for certain overhead and shared services expenses allocated by SunPower. Allocations for SG&A services included such items as information technology, legal, human resources and other financial and administrative services. These expenses were charged or allocated to the Predecessor based on management’s estimate of proportional use. Under the Management Services Agreements amended in August 2015, we will initially pay annual fees of $1.7 million to our Sponsors for general and administrative services. These annual management fees 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 August 31, 2015, OpCo owned a 49% interest in the Solar Gen 2 Project, the North Star Project and the Lost Hills Blackwell Project; however, as these interests were previously owned by First Solar, they are not included in the Predecessor’s combined carve-out financial statements. The results of operations of joint ventures in which OpCo owns a meaningful noncontrolling interest will not be consolidated in our unaudited condensed consolidated 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 $525.0 million senior secured credit facility, consisting of a $300.0 million term loan facility, a $25.0 million delayed draw term loan facility and a $200.0 million revolving credit facility. As of August 31, 2015, the full amount of the term loan facility and approximately $9.4 million of letters of credit under our revolving credit facility were outstanding. The remaining portion of the revolving credit facility and the delayed draw term loan facility are undrawn. We used the proceeds of the term loan facility to pay distributions to our Sponsors.

Expiration of Section 1603 Cash Grant Program.    The Predecessor’s combined carve-out financial statements (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 includes the period from June 1, 2015 to August 31, 2015 consistent with our November 30 fiscal year end. The corresponding third quarter for the prior year includes the Predecessor’s period from June 30, 2014 to September 28, 2014.

These accompanying unaudited condensed consolidated financial statements cover the period from December 29, 2014 through August 31, 2015, representing the first eight months of the Partnership’s recently adopted fiscal year. The prior year’s comparable nine-month period covers the period from December 30, 2013 through September 28, 2014 and is reported on the basis of the previous fiscal year end of the Predecessor. As a result of the change in our fiscal year end, the quarterly periods of our newly adopted fiscal year do not coincide with the historical quarterly periods previously reported by the Predecessor. Financial information for the three and eight months ended August 31, 2014 has not been included in this Form 10-Q for the following reasons: (i) the three and nine months ended September 28, 2014 provide as meaningful a comparison to the three and eight months ended August 31, 2015 as would

 

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the three and eight months ended August 31, 2014; (ii) we believe that there are no significant factors, seasonal or other, that would impact the comparability of information if the results for the three and eight months ended August 31, 2014 were presented in lieu of results for the three and nine months ended September 28, 2014; and (iii) it was not practicable or cost justified to prepare this information.

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” in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 28, 2015 (the “Partnership’s Second Quarter 2015 Form 10-Q”).

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 August 31, 2015, have a weighted average remaining life of approximately 21.8 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.

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 unaudited condensed consolidated financial statements and related footnotes. In preparing these unaudited condensed consolidated financial statements, we have made our best estimates of certain amounts included in the unaudited condensed 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

 

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Note 2 of the unaudited condensed consolidated financial statements. There have been no significant changes to our critical accounting policies and estimates since December 28, 2014.

Results of Operations

Three and Eight Months Ended August 31, 2015 Compared to Three and Nine Months Ended September 28, 2014

Revenues

 

 

Operating revenues for the three months ended August 31, 2015 were comprised of lease revenues from our solar energy system lease arrangements. 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, other than interest revenue, we had no sales-type lease revenue on our unaudited condensed consolidated financial statements for the three and eight months ended August 31, 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 eight months ended August 31, 2015 and the three and nine months ended September 28, 2014.

Total revenues increased by $0.7 million, or 32.0%, during the three months ended August 31, 2015 as compared to the three months ended September 28, 2014 mainly due to the addition of a solar energy system contributed by our Sponsor at IPO, which generates quarterly rent revenue. Total revenues decreased by $0.3 million, or 4.0%, during the eight months ended August 31, 2015 as compared to the nine months ended September 28, 2014 due to no sales-type leases being placed in service in the eight months ended August 31, 2015 and a decrease in in upfront rebate revenue on operating leases which did not transition to us post initial public offering, partially offset by the rent revenues from the solar energy system contributed at IPO in 2015.

 

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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, and also costs related to system output performance warranty and residential lease system repairs accrual and reserves for upfront rebate receivables. Costs recognized on sales-type leases include initial direct costs to complete a leased solar 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 eight months ended August 31, 2015. For the three and nine months ended September 28, 2014, we recognized zero and $5.7 million, respectively, of cash grants as a reduction of sales-type lease cost of operations.

The decrease of $1.8 million, or 96.0%, for the three months ended August 31, 2015 as compared to the three months ended September 28, 2014 is mainly driven by a $1.1 million change in system output performance warranty and residential lease system repairs accrual, $0.6 million reserve for upfront rebates receivables related to our residential leasing business booked during the three months ended September 28, 2014, and less than $0.1 million in other costs.

The increase of $5.8 million, or 170.0%, for the eight months ended August 31, 2015 as compared to the nine months ended September 28, 2014 is mainly driven by (i) $5.7 million lower cost in 2014 due to the recognition of certain cash grants related to sales-type leases placed in service in prior periods until all criteria necessary to be entitled to such grant income were met during the second quarter of fiscal 2014 and (ii)  a net change of $0.7 million of reserve recorded for the aged rebates receivable during fiscal 2015. These increases were offset by a decrease of $0.5 million of system output performance warranty and residential lease system repairs accrual for the eight months ended August 31, 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 $0.1 million for the three months ended August 31, 2015 and $0.2 million for the three months ended September 28, 2014. Costs incurred for these services were $0.5 million for the eight months ended August 31, 2015 and $0.7 million for the nine months ended September 28, 2014.

Selling, General and Administrative: Selling, general and administrative expense includes (i) post-IPO operating expenses such as audit, legal, insurance, independent board of directors and fees under the AMAs and MSAs with our Sponsors; (ii) charges that were incurred by SunPower that were specifically identified as attributable to the Predecessor; and (iii) an allocation of SunPower operating expenses based on the proportional level of effort attributable to the operation of the Predecessor’s portfolio of solar energy systems leased to residential homeowners and solar energy projects under construction. These expenses include asset management, legal, accounting, tax, treasury, information technology, insurance, employee benefit costs, human resources, procurement, and other corporate services and infrastructure costs.

The increase of $1.5 million, or 148.1%, for the three months ended August 31, 2015 as compared to the three months ended September 28, 2014 was primarily driven by a $1.3 million of post-IPO operating expenses related to audit, legal, insurance, retaining the independent directors of the board of directors, MSA and other fees, $0.3 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 95.8% complete as of August 31, 2015, an increase in the allocation of $0.2 million of costs incurred by SunPower related to our IPO, and an increase of $0.2 million in bad debt allowance, offset by approximately $0.5

 

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million reduction in land lease costs of the Predecessor related to the Quinto Project and other non-capitalizable project-related expenses incurred during the project development period in the prior year.

The increase of $6.2 million, or 212.7%, for the eight months ended August 31, 2015 as compared to the nine months ended September 28, 2014 was primarily driven by a $3.9 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 95.8% complete as of August 31, 2015, $1.3 million of post-IPO operating expenses related to audit, legal, insurance, retaining the independent directors the board of directors, MSA and other fees, the allocation of $1.6 million of costs incurred by SunPower related to our IPO, and $0.3 million increase in bad debt expense and other costs related to residential lease customers, offset by approximately $1.0 million reduction in land lease costs of the Predecessor related to the Quinto Project and other non-capitalizable project-related expenses incurred during the project development period in the prior year.

Depreciation: Depreciation expense reflects costs associated with depreciation of 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 $0.4 million, or 59.9%, for the three months ended August 31, 2015 as compared to the three months ended September 28, 2014 is primarily a result of depreciation related to our Maryland Solar Project.

The increase of $0.7 million, or 44.9%, for the eight months ended August 31, 2015 as compared to the nine months ended September 28, 2014 is primarily a result of $0.4 million depreciation related to our Maryland Solar Project and recognition of certain cash grants for the nine months ended September 28, 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 unaudited 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 August 31, 2015 included $0.1 million of non-cash interest expense and $0.1 million of cash interest expense compared to total interest expense for the three months ended September 28, 2014 which included $1.2 million of non-cash interest expense and $0.1 million of cash interest expense. Non-cash interest expense decreased $1.1 million, or 91.7% quarter-on-quarter due to the Predecessor terminating the remaining residential lease financing obligation arrangement in May 2015.

 

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Interest expense for the eight months ended August 31, 2015 included $1.3 million of non-cash interest expense and $0.3 million of cash interest expense compared to total interest expense for the nine months ended September 28, 2014 which included $3.7 million of non-cash interest expense and $0.4 million of cash interest expense. Non-cash interest expense decreased $2.4 million, or 64.9% quarter-on-quarter due to the Predecessor terminating one residential lease financing obligation in January 2015 and the remaining obligation in May 2015.

Interest income of $0.2 million for the three and eight months ended August 31, 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.

Other expense for the three and eight months ended August 31, 2015 included a loss on cash flow hedges of $2.7 million and $5.4 million associated with the Predecessor, respectively, a $0.8 million unrealized loss on cash flow hedge associated with our term loan facility, and a loss on termination of the residential lease financial obligation of zero and $6.5 million, respectively.

Loss on cash flow hedges associated with Predecessor: The Predecessor entered into interest rate swap agreements, designated as cash flow hedges, in the fourth quarter of the year ended December 28, 2014 on the outstanding and forecasted future borrowings under the Quinto Credit Facility to reduce the impact of changes in interest rates. The Predecessor assessed the effectiveness of these cash flow hedges at inception and on a quarterly basis. If it was determined that a derivative instrument was not highly effective or the transaction was no longer deemed probable of occurring, the Predecessor discontinued hedge accounting and recognized the ineffective portion in current period earnings. The hedge became ineffective in the quarter ended March 28, 2015, 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 August 31, 2015 $2.7 million 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 eight and nine months ended August 31, 2015 and September 28, 2014, $5.4 million and zero, respectively, was reclassified into loss on cash flow hedges within other expense, net in the condensed consolidated statements of operations, as the transaction was terminated.

Loss on cash flow hedges associated with term loan facility: During the three and eight months ended August 31, 2015, we entered into interest rate swap agreements to economically hedge the cash flows on our term loan facility. The changes in fair value are recorded in other expense in the unaudited condensed consolidated statement of operations as these hedges are not accounted for under hedge accounting. During the three and eight months ended August 31, 2015, we recorded an unrealized loss of $0.8 million for the mark-to-market valuation adjustment of interest rate swap agreements.

Loss on termination of financing obligation: On January 30, 2015, the Predecessor entered into an agreement with one of the residential lease financing third-party investors that terminated the financing obligation arrangement. In conjunction with the 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 August 31, 2015 and September 28, 2014, zero was recognized as a loss on termination within other expense, net in the condensed consolidated statements of operations. During the eight and nine months ended August 31, 2015 and September 28, 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.

Income tax (provision) benefit

 

 

Income Tax (Provision) Benefit: Our tax rate is primarily affected by the tax impact of equity in earnings, valuation allowances during the Predecessor period, the tax impact of noncontrolling interest, permanent differences related to the book-to-tax difference of the deduction for stock compensation to members of the board of directors due to differences in valuation dates, and state tax rates (net of federal benefit) in various jurisdictions, most significantly California. We included the income tax provision related to our

 

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equity in earnings of unconsolidated investees in the income tax (provision) benefit line of the condensed consolidated statements of operations.

Our income tax (provision) benefit following the IPO closing date represents federal and state taxes on net income (exclusive of income tax but after noncontrolling interest). The Predecessor’s income tax (provision) benefit, which was calculated on a separate return basis for the carve-out period, was due to minimum state income taxes. The change in income tax (provision) benefit as a percentage of revenues for the three months ended August 31, 2015 of (22.8)% compared to (1.2)% for the three months ended September 28, 2014 is the result of an increase in equity in earnings of unconsolidated affiliates along with higher losses before income taxes for the three months ended August 31, 2015 of $4.1 million compared to losses before income taxes of $2.8 million for the three months ended September 28, 2014.

Equity in Earnings of Unconsolidated Investees

 

 

Equity in earnings of unconsolidated investees represents our proportionate share of the earnings and losses from SG2 Holdings, North Star Holdings and Lost Hills Blackwell Holdings, 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 eight months ended August 31, 2015, we recognized equity in earnings of $6.1 million. We did not have any equity method investments during the three and nine months ended September 28, 2014.

Net income attributable to noncontrolling interests and redeemable noncontrolling interests

 

 

Net income attributable noncontrolling interests and redeemable noncontrolling interests for the three and eight months ended August 31, 2015 included (i) a net loss of $0.7 million attributable to noncontrolling interests and redeemable noncontrolling interests related to our tax equity financing facilities with third-party investors under which the parties invest in entities that hold the solar power systems and (ii) net income of $4.4 million attributable to our Sponsors as a result of their economic ownership in our OpCo. We apply the hypothetical liquidation value method in allocating recorded net income (loss) to each tax equity investor based on the change during the reporting period of the amount of net assets of the entity to which each tax equity investor would be entitled to under the governing contractual arrangements in a liquidation scenario.

 

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Cash Flows

Eight Months Ended August 31, 2015 Compared to Nine Months Ended September 28, 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 eight months ended August 31, 2015 was $7.3 million and was primarily the result of: (i) a net loss of $15.4 million; (ii) a $6.1 million non-cash adjustment for equity in earnings of unconsolidated investees; and (iii) $4.2 million increase in prepaid and other current assets, related to capitalized expenses incurred by the Predecessor for our initial public offering. This was partially offset by: (i) non-cash charges of $16.1 million, including a $3.2 million mark-to-market loss on cash flow hedges, $6.5 million loss upon termination of residential financing arrangement, $2.4 million depreciation of operating lease assets and solar energy systems utility, $1.3 million reserve for rebates receivable, $1.2 million interest expense for the financing arrangement of residential leased solar energy systems prior to termination, $0.7 million charge for deferred income taxes, and $0.8 million unrealized loss on interest rate swaps; (ii) $1.6 million increase in accounts payable and other accrued liabilities; (iii) $0.4 million increase in deferred revenue on operating leases; and (iv) $0.2 million decrease in solar power systems to be leased.

Net cash provided by operating activities for the nine months ended September 28, 2014 was $1.7 million and was primarily the result of: (i) net income of $1.0 million; (ii) non-cash charges of $5.3 million, including $1.6 million depreciation of operating lease assets and $3.7 million loss upon termination of residential financing arrangement; (iii) $2.8 million decrease in cash grants and rebates receivable; and (iv) $0.4 million decrease in solar power systems to be leased. This was partially offset by: (i) $2.9 million increase in accounts receivable and financing receivable for rent due on sales-type and operating leases; (ii) $4.1 million decrease in accounts payable and other accrued liabilities related to recognition of deferred cash grant awards; (iii) $0.3 million increase in prepaid expense and other current assets related to prepaid land lease on the Quinto Project; and (iv) $0.6 million decrease in deferred rent revenue for operating leases.

Investing Activities

Net cash used in investing activities for the eight months ended August 31, 2015 was $220.6 million and was primarily the result of $225.2 million related to costs incurred by the Predecessor associated with solar energy projects under construction. These costs were partially offset by $4.7 million of cash distributions from unconsolidated investees.

Net cash used in investing activities for the nine months ended September 28, 2014 was $30.5 million and was the result of $33.7 million of costs associated with solar energy projects under construction, partially offset by $3.2 million of cash grants received related to residential solar energy systems under operating leases.

Financing Activities

Net cash provided by financing activities for the eight months ended August 31, 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) $7.0 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 financing arrangements prior to the IPO and the Quinto Solar Project at the IPO closing; (vi) $3.2 million of capital distributions to SunPower made by the Predecessor before the IPO; and (vii) $6.0 million of cash distribution to SunPower for the remaining purchase price payments of initial projects.

 

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Net cash provided by financing activities for the nine months ended September 28, 2014, was $28.8 million due to $38.2 million of capital contributions from SunPower to fund the SunPower Project Entities before the IPO, partially offset by $9.4 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 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 $525.0 million senior secured credit facility, consisting of a $300.0 million term loan facility, a $25.0 million delayed draw term loan facility and a $200.0 million revolving credit facility. As of August 31, 2015, the full amount of the $300.0 million term loan facility and approximately $9.4 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 up to $775.0 million in the aggregate, with any increase in the revolving facility not to exceed $100.0 million. The proceeds of the term loan facility were used to pay fees and expenses, to repay existing indebtedness, to make a distribution to the Sponsors and for general purposes, including to fund acquisition opportunities, while the proceeds of the delayed draw term loan facility 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 has occurred or is continuing at the time of such distribution, or would result therefrom, and OpCo is otherwise in compliance, on a

 

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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 August 31, 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 August 31, 2015:

 

 

Off-Balance-Sheet Arrangements

As of August 31, 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 August 31, 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 August 31, 2015, the outstanding principal balance of our variable interest borrowings was $300.0 million of which $60.0 million is unhedged.  An immediate 10% increase in interest rates would have an increase of approximately $0.02 million of annualized interest expenses on our unaudited condensed consolidated financial statements. However, we entered into interest rate swaps on July 17, 2015, which would mitigate the interest rate risk of our term loan facility. As of August 31, 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 August 31, 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.

Information regarding risk factors appears in Part II, Item 1A. Risk Factors in the Partnership’s Second Quarter 2015 Form 10-Q.  The factors discussed in the Partnership’s Second Quarter 2015 Form 10-Q, as well as other information set forth in this report, which could materially adversely affect the Partnership’s business, financial condition, results of operations, cash available for distribution and prospects should be carefully considered.  The risks described in the Partnership’s Second Quarter 2015 Form 10-Q are not the only risks facing the Partnership.  Additional risks and uncertainties not currently known to the Partnership, or that are currently deemed to be immaterial, also may materially adversely affect the Partnership’s business, financial condition, results of operations, cash available for distribution and prospects.

 

 

 

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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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