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EX-32.2 - EXHIBIT 32.2 - 8point3 Energy Partners LPex-322_8311710q.htm
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EX-31.2 - EXHIBIT 31.2 - 8point3 Energy Partners LPex-312_8311710q.htm
EX-31.1 - EXHIBIT 31.1 - 8point3 Energy Partners LPex-311_8311710q.htm
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
___________________________________
 
FORM 10-Q
___________________________________
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended August 31, 2017
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _____ to _____

Commission File Number: 001-37447
__________________________________________________
8point3 Energy Partners LP
(Exact Name of Registrant as Specified in its Charter)
__________________________________________________
 
Delaware
47-3298142
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
77 Rio Robles
San Jose, California
95134
(Address of principal executive offices)
(Zip Code)
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  ☒    No  ☐  
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐
Indicate by check mark 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.
Large accelerated filer ☐
 
Accelerated filer ☒
 
Non-accelerated filer
 
Small reporting company
 
Emerging growth company ☒
 
 
 
 
(Do not check if a
small reporting company)
 
 
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☒
As of October 2, 2017, the registrant had outstanding 28,084,935 Class A shares representing limited partner interests and 51,000,000 Class B shares representing limited partner interests.
 




Table of Contents
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 


i



GLOSSARY

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

“2016 10-K” refers to our Annual Report on Form 10-K dated January 26, 2017, as amended.

“(ac)” refers to alternating current.

“AMAs” refers to asset management agreements.

“AROs” refers to asset retirement obligations.

“ATM Program” refers to the Partnership’s at-the-market offering program established on January 30, 2017 under the Equity Distribution Agreement by and among the Partnership and the General Partner, on the one hand, and Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, and Mizuho Securities USA Inc. (collectively, the “ATM Agents”), on the other hand, under which the Partnership may sell its Class A Shares from time to time to or through the ATM Agents.

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

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

“C&I” refers to commercial and industrial.

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

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

“COD” refers to the commercial operation date.

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

“EPC” refers to engineering, procurement and construction.

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

“FASB” refers to the Financial Accounting Standards Board.

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

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

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

“First Solar ROFO Projects” refers to, collectively, the projects set forth in the chart in Part I, Item 1 of the 2016 10-K, under the heading “Business—Our Portfolio—ROFO Projects” with First Solar listed as the “Developing Sponsor” and as to which we have a right of first offer under the First Solar ROFO Agreement should First Solar decide to sell them (but excluding (a) the Stateline Project, which we acquired on December 1, 2016, as further described in Part I, Item 1. “Financial Information—Notes to Unaudited Condensed Consolidated Financial Statements—Note 3—Investment in Unconsolidated Affiliates," (b) First Solar’s indirect interest in the Switch Station project, as further described in Part I, Item 1. “Financial Information—Notes to Unaudited Condensed Consolidated Financial Statements—Note 12—Related Parties,” (c) First Solar’s indirect interest in the Cuyama project, as further described in Part I, Item 1. “Financial Information—Notes to Unaudited Condensed

2



Consolidated Financial Statements—Note 12—Related Parties,” and (d) First Solar’s indirect interest in the California Flats project, as further described in Part I, Item 1.“Financial Information—Notes to Unaudited Condensed Consolidated Financial Statements—Note 12—Related Parties”.

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

“GW” refers to a gigawatt, or 1,000,000,000 watts. As used in this 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.

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

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

“Henrietta Project Entity” refers to Parrey, LLC.

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

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

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

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

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

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

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

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

“ITCs” refers to investment tax credits.

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

“Kern Letter Agreement” refers to that certain letter agreement, dated June 9, 2017, by and between OpCo and SunPower in connection with the closing of the fifth phase of the Kern Project. Please read Part I, Item 1. “Financial Information—Notes to Unaudited Condensed Consolidated Financial Statements—Note 2—Business Combinations” for further details.

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

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

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

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

3




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

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

“Kern Remaining Assets” refers to the certain assets of the Kern Project, with a nameplate capacity of up to approximately 3 MW, which may be acquired by the Partnership if certain conditions precedent set forth in the Kern Letter Agreement are satisfied.
 
“Kern Project” refers to the solar energy project located in Kern County, California, that is held by the Kern Project Entity and has an aggregate nameplate capacity of up to approximately 21 MW. OpCo’s acquisition of the Kern Project is being effectuated in phases, with the closing for the Kern Phase 1(a) Assets having occurred on January 26, 2016 (the “Kern Phase 1(a) Acquisition”), the closing for the Kern Phase 1(b) Assets having occurred on September 9, 2016 (the “Kern Phase 1(b) Acquisition”), the closing for the Kern Phase 2(a) Assets having occurred on November 30, 2016 (the “Kern Phase 2(a) Acquisition”), the closing for the Kern Phase 2(b) Assets having occurred on February 24, 2017 (the “Kern Phase 2(b) Acquisition”), and the closing for the Kern Phase 2(c) Assets having occurred on June 9, 2017 (the “Kern Phase 2(c) Acquisition”), and in the event that the conditions precedent set forth in the Kern Letter Agreement are met, the closing for the Kern Remaining Assets at a future closing date on or prior to September 30, 2017.

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

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

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

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

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

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

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

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

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

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

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

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

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

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


4



“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.

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

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

“Omnibus Agreement” refers to the Amended and Restated Omnibus Agreement, dated as of April 6, 2016, as amended, among the Partnership, OpCo, the General Partner, Holdings, First Solar and SunPower. Please read Part I, Item 1. “Financial Information—Notes to Unaudited Condensed Consolidated Financial Statements—Note 12—Related Parties” for further details.

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

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

“Portfolio” refers to, collectively, our portfolio of solar energy projects as of August 31, 2017, which consists of the Henrietta Project, the Hooper Project, the Kern Phase 1(a) Assets, the Kern Phase 1(b) Assets, the Kern Phase 2(a) Assets, the Kern Phase 2(b) Assets, the Kern Phase 2(c) Assets, the Kingbird Project, the Lost Hills Blackwell Project, the Macy’s California Project, the Macy’s Maryland Project, the Maryland Solar Project, the North Star Project, the Quinto Project, the Solar Gen 2 Project, the Stateline Project, the RPU Project, the UC Davis Project and the Residential Portfolio.

“PPA” refers to a power purchase agreement.

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

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

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

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

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

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

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

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


5



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

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

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

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

“SDG&E” refers to San Diego Gas & Electric Company.

“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.

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

“SRECs” refers to Solar Renewable Energy Credits.

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

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

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

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

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

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

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

“SunPower ROFO Projects” refers to, collectively, the projects set forth in the chart in Part I, Item 1 of the 2016 10-K, under the heading “Business—Our Portfolio—ROFO Projects” with SunPower listed as the Developing Sponsor and as to which we have a right of first offer under the SunPower ROFO Agreement should SunPower decide to sell them (but excluding SunPower’s interest in the El Pelicano project, as further described in Part I, Item 1. “Financial Information—Notes to Unaudited Condensed Consolidated Financial Statements—Note 12—Related Parties”, and SunPower's interest in the Boulder Solar 1 project, as further described in Part I, Item 1. “Financial Information—Notes to Unaudited Condensed Consolidated Financial Statements—Note 12—Related Parties”).

“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.

6




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

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

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


7



PART I—FINANCIAL INFORMATION
 
Item 1. Financial Statements.

8point3 Energy Partners LP
Condensed Consolidated Balance Sheets
(In thousands, except share data)
(Unaudited)

 
 
August 31, 2017
 
November 30, 2016
Assets
 
 

 
 
Current assets:
 
 

 
 
Cash and cash equivalents
 
$
10,361

 
$
14,261

Accounts receivable and short-term financing receivables, net
 
10,882

 
5,401

Prepaid and other current assets1
 
12,312

 
15,745

Total current assets
 
33,555

 
35,407

Property and equipment, net
 
719,868

 
720,132

Long-term financing receivables, net
 
77,484

 
80,014

Investments in unconsolidated affiliates
 
791,985

 
475,078

Other long-term assets
 
21,459

 
24,432

Total assets
 
$
1,644,351

 
$
1,335,063

Liabilities and Equity
 
 

 
 

Current liabilities:
 
 

 
 

Accounts payable and other current liabilities1
 
$
6,565

 
$
23,771

Short-term debt and financing obligations1
 
2,201

 
1,964

Deferred revenue, current portion
 
1,527

 
870

Total current liabilities
 
10,293

 
26,605

Long-term debt and financing obligations1
 
709,989

 
384,436

Deferred revenue, net of current portion
 
128

 
308

Deferred tax liabilities
 
38,591

 
30,733

Asset retirement obligations
 
14,796

 
13,448

Other long-term liabilities
 
1,853

 

Total liabilities
 
775,650

 
455,530

Redeemable noncontrolling interests
 
17,346

 
17,624

Commitments and contingencies (Note 5)
 


 


Equity:
 
 

 
 

Class A shares, 28,084,935 and 28,072,680 issued and outstanding as of August 31, 2017 and November 30, 2016, respectively
 
249,306

 
249,138

Class B shares, 51,000,000 issued and outstanding as of August 31, 2017 and November 30, 2016
 

 

Accumulated earnings
 
12,550

 
22,440

Total shareholders' equity attributable to 8point3 Energy Partners LP
 
261,856

 
271,578

Noncontrolling interests
 
589,499

 
590,331

Total equity
 
851,355

 
861,909

Total liabilities and equity
 
$
1,644,351

 
$
1,335,063


1
The Partnership has related-party balances for transactions made with the Sponsors and tax equity investors. Related-party balances recorded within “Prepaid and other current assets” in the unaudited condensed consolidated balance sheets were $0.8 million and $0.9 million as of August 31, 2017 and November 30, 2016, respectively. Related-party balances recorded within “Accounts payable and other current liabilities” in the unaudited condensed consolidated balance sheets were $3.5 million and $19.7 million due to Sponsors as of August 31, 2017 and November 30, 2016, respectively, and $0.9 million and $1.0 million due to tax equity investors as of August 31, 2017 and November 30, 2016, respectively. Related-party balances recorded within “Short-term debt and financing obligations” and “Long-term debt and financing obligations” in the unaudited condensed consolidated balance sheets were $2.2 million and $47.8 million, respectively, as of August 31, 2017, and $2.0 million and zero, respectively, as of November 30, 2016.
 
The accompanying notes are an integral part of these condensed consolidated financial statements.


8



8point3 Energy Partners LP
Condensed Consolidated Statements of Operations
(In thousands, except per share data)
(Unaudited)

 
Three Months Ended
 
Nine Months Ended
 
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Revenues:
 
 
 
 
 

 
 

Operating revenues1
$
27,744

 
$
26,116

 
$
54,319

 
$
46,735

Total revenues
27,744

 
26,116

 
54,319

 
46,735

Operating costs and expenses1:
 
 
 
 
 

 
 

Cost of operations
2,064

 
1,928

 
6,396

 
4,953

Selling, general and administrative
2,050

 
1,804

 
5,894

 
5,096

Depreciation and accretion
7,220

 
6,311

 
20,875

 
16,325

Acquisition-related transaction costs
19

 
599

 
50

 
2,261

Total operating costs and expenses
11,353

 
10,642

 
33,215

 
28,635

Operating income
16,391

 
15,474

 
21,104

 
18,100

Other expense (income):
 
 
 
 
 

 
 

Interest expense
6,060

 
3,199

 
17,429

 
9,123

Interest income
(304
)
 
(296
)
 
(869
)
 
(909
)
Other expense (income)
283

 
(291
)
 
(514
)
 
(551
)
Total other expense, net
6,039

 
2,612

 
16,046

 
7,663

Income before income taxes and equity in earnings of unconsolidated investees
10,352

 
12,862

 
5,058

 
10,437

Income tax provision
(5,012
)
 
(5,063
)
 
(7,860
)
 
(15,281
)
Equity in earnings of unconsolidated investees
23,322

 
8,075

 
33,287

 
13,504

Net income
28,662

 
15,874

 
30,485

 
8,660

Less: Net income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests
21,189

 
8,281

 
18,765

 
(14,263
)
Net income attributable to 8point3 Energy Partners LP Class A shares
$
7,473

 
$
7,593

 
$
11,720

 
$
22,923

Net income per Class A share:
 
 
 
 
 

 
 

Basic
$
0.27

 
$
0.38

 
$
0.42

 
$
1.15

Diluted
$
0.27

 
$
0.38

 
$
0.42

 
$
1.15

Distributions per Class A share:
$
0.26

 
$
0.23

 
$
0.77

 
$
0.67

Weighted average number of Class A shares:
 
 
 
 
 

 
 

Basic
28,081

 
20,015

 
28,077

 
20,011

Diluted
43,581

 
35,515

 
43,577

 
35,511

 
1
The Partnership has related-party activities for transactions made with the Sponsors. Related party transactions recorded within “Operating revenues” in the unaudited condensed consolidated statement of operations were $1.3 million for each of the three months ended August 31, 2017 and August 31, 2016, and $3.9 million for each of the nine months ended August 31, 2017 and August 31, 2016. Related party transactions recorded within “Operating costs and expenses” in the unaudited condensed consolidated statement of operations were $2.1 million and $1.9 million for the three months ended August 31, 2017 and August 31, 2016, respectively, and $6.3 million and $5.0 million for the nine months ended August 31, 2017 and August 31, 2016, respectively.

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


9



8point3 Energy Partners LP
Condensed Consolidated Statements of Redeemable Noncontrolling Interests and Equity
(In thousands, except share data)
(Unaudited)
 
 
Redeemable
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
Noncontrolling
 
Class A Shares
 
Class B Shares
 
Accumulated
 
Shareholders'
 
Noncontrolling
 
Total
 
Interests
 
Shares
 
Amount
 
Shares
 
Amount
 
Earnings
 
Equity
 
Interest
 
Equity
Balance as of November 30, 2015
$
89,747

 
20,007,281

 
$
392,748

 
51,000,000

 
$

 
$
15,580

 
$
408,328

 
$
194,058

 
$
602,386

Noncontrolling interests obtained through acquisition

 

 

 

 

 

 

 
40,128

 
40,128

Cash and accrued distributions to noncontrolling interests - tax equity investors
(3,580
)
 

 

 

 

 

 

 
(3,574
)
 
(3,574
)
Issuance of Class A shares, net of issuance costs

 
8,050,000

 
113,325

 

 

 

 
113,325

 

 
113,325

Reclassification of noncontrolling interests due to issuance of Class A shares

 

 
(257,159
)
 

 

 

 
(257,159
)
 
257,159

 

Share-based compensation

 
15,399

 
224

 

 

 

 
224

 

 
224

Contributions from SunPower

 

 

 

 

 

 

 
9,973

 
9,973

Contributions from tax equity investors

 

 

 

 

 

 

 
50,507

 
50,507

Cash distributions to Class A shareholders

 

 

 

 

 
(20,241
)
 
(20,241
)
 

 
(20,241
)
Cash distributions to Sponsors as OpCo unitholders

 

 

 

 

 

 

 
(12,271
)
 
(12,271
)
Net income (loss)
(68,543
)
 

 

 

 

 
27,101

 
27,101

 
54,351

 
81,452

Balance as of November 30, 2016
$
17,624

 
28,072,680

 
$
249,138

 
51,000,000

 
$

 
$
22,440

 
$
271,578

 
$
590,331

 
$
861,909

Noncontrolling interests obtained through acquisition

 

 

 

 

 

 

 
1,736

 
1,736

Cash and accrued distributions to noncontrolling interests - tax equity investors
(2,671
)
 

 

 

 

 

 

 
(4,037
)
 
(4,037
)
Share-based compensation

 
12,255

 
168

 

 

 

 
168

 

 
168

Contributions from tax equity investors

 

 

 

 

 

 

 
24,353

 
24,353

Cash distributions to Class A shareholders

 

 

 

 

 
(21,610
)
 
(21,610
)
 

 
(21,610
)
Cash distributions to Sponsors as OpCo unitholders

 

 

 

 

 

 

 
(39,255
)
 
(39,255
)
Net income
2,393

 

 

 

 

 
11,720

 
11,720

 
16,371

 
28,091

Balance as of August 31, 2017
$
17,346

 
28,084,935

 
$
249,306

 
51,000,000

 
$

 
$
12,550

 
$
261,856

 
$
589,499

 
$
851,355

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


10



8point3 Energy Partners LP
Condensed Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)
 
 
Nine Months Ended
 
 
August 31, 2017
 
August 31, 2016
Cash flows from operating activities:
 
 
 
 
Net income
 
$
30,485

 
$
8,660

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation, amortization and accretion
 
21,198

 
16,325

Unrealized gain on interest rate swap
 
(349
)
 
(536
)
Distributions from unconsolidated investees
 
32,892

 
15,130

Equity in earnings of unconsolidated investees
 
(33,287
)
 
(13,504
)
Deferred income taxes
 
7,858

 
15,281

Share-based compensation
 
168

 
168

Amortization of debt issuance costs
 
737

 
442

Other, net
 
1

 
270

Changes in operating assets and liabilities:
 
 
 
 
Accounts receivable and financing receivable, net
 
(2,830
)
 
(4,290
)
Prepaid and other assets
 
6,170

 
(1,398
)
Deferred revenue
 
482

 
467

Accounts payable and other liabilities
 
734

 
806

Net cash provided by operating activities
 
64,259

 
37,821

Cash flows from investing activities:
 


 
 
Cash provided by (used in) purchases of property and equipment, net
 
(314
)
 
1,415

Cash paid for acquisitions
 
(313,183
)
 
(124,326
)
Distributions from unconsolidated investees
 
13,575

 
653

Net cash used in investing activities
 
(299,922
)
 
(122,258
)
Cash flows from financing activities:
 


 
 
Proceeds from issuance of Class A shares, net of issuance costs
 

 
(201
)
Proceeds from issuance of bank loans, net of issuance costs
 
283,999

 
64,991

Repayment of bank loans
 
(7,000
)
 

Repayment of promissory note to First Solar
 
(1,964
)
 

Capital contributions from SunPower
 

 
9,973

Cash distribution to Class A shareholders
 
(21,610
)
 
(13,487
)
Cash distributions to Sponsors as OpCo unit holders
 
(39,255
)
 

Cash contributions from noncontrolling interests and redeemable noncontrolling interests - tax equity investors
 
24,353

 
372

Cash distributions to noncontrolling interests and redeemable noncontrolling interests - tax equity investors
 
(6,760
)
 
(4,102
)
Net cash provided by financing activities
 
231,763

 
57,546

Net decrease in cash and cash equivalents
 
(3,900
)
 
(26,891
)
Cash and cash equivalents, beginning of period
 
14,261

 
56,781

Cash and cash equivalents, end of period
 
$
10,361

 
$
29,890

Non-cash transactions:
 


 
 
Issuance by OpCo of promissory note to First Solar in connection with the Stateline Acquisition
 
$
50,000

 
$

Property and equipment acquisitions funded by liabilities
 
2,618

 
17,410

Settlement of related party payable by capital contribution from tax equity investor
 

 
46,837

Accrued distributions to noncontrolling interests and redeemable noncontrolling interests - tax equity investors
 
923

 
795

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

11



8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Description of Business

The Partnership

8point3 Energy Partners LP (together with its subsidiaries, the “Partnership”) is a limited partnership formed on March 3, 2015 under a master formation agreement by SunPower Corporation (“SunPower”) and First Solar, Inc. (“First Solar” and, together with SunPower, the “Sponsors”) to own, operate and acquire solar energy generation systems. As of August 31, 2017, 8point3 Energy Partners LP owned a controlling non-economic managing member interest in 8point3 Operating Company, LLC (“OpCo”) and a 35.5% limited liability company interest in OpCo, and the Sponsors collectively owned a noncontrolling 64.5% limited liability company interest in OpCo.

The following table provides an overview of the assets that comprise the Portfolio as of August 31, 2017:
Project
 
Location
 
Commercial
Operation Date(1)
 
MW(ac)
(2)
 
Counterparty
 
Remaining
Term of
Offtake Agreement
(in years)(3)
Utility
 
 
 
 
 
 
 
 
 
 
 
Maryland Solar
 
Maryland
 
February 2014
 
20

 
FirstEnergy
Solutions
 
15.6
 
Solar Gen 2
 
California
 
November 2014
 
150

 
San Diego Gas &
Electric
 
22.2
 
Lost Hills Blackwell
 
California
 
April 2015
 
32

 
City of
Roseville/Pacific
Gas and Electric
 
26.3
(4)
North Star
 
California
 
June 2015
 
60

 
Pacific Gas and
Electric
 
17.8
 
RPU
 
California
 
September 2015
 
7

 
City of Riverside
 
23.1
 
Quinto
 
California
 
November 2015
 
108

 
Southern California
Edison
 
18.3
 
Hooper
 
Colorado
 
December 2015
 
50

 
Public Service
Company of Colorado
 
18.3
 
Kingbird
 
California
 
April 2016
 
40

 
Southern California
Public Power Authority(5)
 
18.7
 
Henrietta
 
California
 
October 2016
 
102

 
Pacific Gas and
Electric
 
19.1
 
Stateline
 
California
 
August 2016
 
300

 
Southern California
Edison
 
19.0
 
Commercial & Industrial
 
 
 
 
 
 
 
 
 
 
 
UC Davis
 
California
 
September 2015
 
13

 
University of
California
 
18.0
 
Macy's California
 
California
 
October 2015
 
3

 
Macy's Corporate
Services
 
18.2
 
Macy’s Maryland
 
Maryland
 
December 2016
 
5

 
Macy's Corporate
Services
 
19.3
 
Kern(6)
 
California
 
September 2017
 
18

 
Kern High School District
 
19.5
(7)
Residential Portfolio
 
U.S. – Various
 
June 2014
 
38

 
Approx. 5,800
homeowners(8)
 
15.0
(9)
Total
 
 
 
 
 
946

 
 
 
 
 
 

12

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

(1)
For the Macy’s California Project, the Macy’s Maryland Project, and the Kern Project, COD represents the first date on which all of the solar generation systems within each of the Macy’s California Project, the Macy’s Maryland Project and the Kern Project, respectively, have achieved or are expected to achieve COD. For the Residential Portfolio, COD represents the first date on which all of the residential systems within the Residential Portfolio have achieved COD.
(2)
The MW for the projects in which the Partnership owns less than a 100% interest or in which the Partnership is the lessor under any sale-leaseback financing are shown on a gross basis.
(3)
Remaining term of offtake agreement is measured from the later of August 31, 2017 or the expected COD of the applicable project.
(4)
Remaining term comprised of 1.3 years on a PPA with the City of Roseville, California, followed by a 25-year PPA with PG&E starting in 2019.
(5)
The Kingbird Project is subject to two separate PPAs with member cities of the Southern California Public Power Authority.
(6)
OpCo’s acquisition of the Kern Project is being effectuated in phases, with the closing of the first phase, reflecting a nameplate capacity of approximately 3 MW, having occurred on January 26, 2016, the closing of the second phase, reflecting a nameplate capacity of approximately 5 MW, having occurred on September 9, 2016, the closing of the third phase, reflecting a nameplate capacity of approximately 5 MW, having occurred on November 30, 2016, the closing of the fourth phase, reflecting a nameplate capacity of approximately 3 MW, having closed on February 24, 2017, and the closing of the fifth phase, reflecting a nameplate capacity of approximately 2 MW, having closed on June 9, 2017.
(7)
Remaining term is the weighted average duration of the five phases of the Kern Project.
(8)
Comprised of the approximately 5,800 solar installations located at homes in Arizona, California, Colorado, Hawaii, Massachusetts, New Jersey, New York, Pennsylvania and Vermont, that are held by the Residential Portfolio Project Entity and have an aggregate nameplate capacity of 38 MW.
(9)
Remaining term is the weighted average duration of all of the residential leases, in each case measured from August 31, 2017.

Basis of Presentation and Preparation

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

the IPO SunPower Project Entities, including:
the Macy’s California Project Entities, which hold the Macy’s California Project;
the Quinto Project Entity, which holds the Quinto Project;
the RPU Project Entity, which holds the RPU Project;
the UC Davis Project Entity, which holds the UC Davis Project; and
the Residential Portfolio Project Entity, which holds the Residential Portfolio Project; and

the IPO First Solar Project Entities, including:
the Lost Hills Blackwell Project, which holds the Lost Hills Project and the Blackwell Project;
the Maryland Solar Project Entity, which holds the Maryland Solar Project;
the North Star Project Entity, which holds the North Star Project; and
the Solar Gen 2 Project Entity, which holds the Solar Gen 2 Project.

In connection with the IPO, SunPower contributed a nearly 100% interest in each of the IPO SunPower Project Entities to OpCo, subject, in the case of the Quinto Project, the RPU Project, the UC Davis Project and the Macy’s California Project, to the tax equity investor’s right to a varying portion of the cash flows from the projects. In connection with the IPO, First Solar directly contributed to OpCo a 100% interest in the Maryland Solar Project Entity and indirectly contributed to OpCo a 49% economic interest in each of the Lost Hills Blackwell Project, the North Star Project and the Solar Gen 2 Project.

Since November 30, 2015, the partnership completed six acquisitions from its Sponsors, four from SunPower and two from First Solar.


13

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

Four of the acquisitions are treated as business combinations:
the Kern Project Entity, which holds the Kern Project;
the Kingbird Project Entities, which holds the Kingbird Project;
the Hooper Project Entity, which holds the Hooper Project; and
the Macy’s Maryland Project Entity, which holds the Macy’s Maryland Project.

Two of the acquisitions are accounted for as equity method investments:
the Henrietta Project Entity, which holds the Henrietta Project. OpCo owns a 49% economic interest in the Henrietta Project Entity; and
the Stateline Project Entity, which holds the Stateline Project. OpCo owns a 34% economic interest in the Stateline Project Entity.

Principles of Consolidation

The unaudited condensed consolidated financial statements are prepared in accordance with U.S. GAAP, and include the accounts of the Partnership, and all of its subsidiaries, as appropriate under consolidation accounting guidelines. The year-end condensed consolidated balance sheet data was derived from the audited financial statements, but does not include all disclosures required by U.S. GAAP. Investments in unconsolidated affiliates in which the Partnership has less than a controlling interest are accounted for using the equity method of accounting. Inter-entity accounts and transactions have been eliminated in consolidation. In the opinion of management, the accompanying 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 should be read in conjunction with the accounting policies previously disclosed in Part II, Item 8. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 1—Description of Business” and “—Note 2—Summary of Significant Accounting Policies” of the 2016 10-K. Interim results are not necessarily indicative of results for a full year.

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 allowances for doubtful accounts related to accounts receivable and financing receivables; estimates of future cash flows and economic useful lives of property and equipment; the fair value and residual value of leased solar power systems; fair value of financial instruments; fair value of acquired assets and liabilities; valuation of certain accrued liabilities such as accrued system output performance warranty and AROs; and income taxes including the related valuation allowance. Actual results could materially differ from those estimates.

Recently Adopted Accounting Pronouncements

In August 2014, the FASB issued an update to the standards to require management to evaluate whether there are conditions and events that raise substantial doubt about the Partnership’s ability to continue as a going concern within one year after the date the financial statements are issued, and to provide related disclosures. The Partnership adopted the new guidance beginning on December 1, 2016 and the impact of this standard on its consolidated financial statements and disclosures is not material.

Recent Accounting Pronouncements Not Yet Adopted

In January 2017, the FASB issued an update to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions of assets or businesses. This new guidance becomes effective for the Partnership in the first quarter of fiscal 2019 and is applied prospectively. The Partnership is evaluating the impact of this standard on its consolidated financial statements and disclosures.

In October 2016, the FASB issued an update which amends the guidance on related parties that are under common control. Specifically, this update requires that a single decision maker consider indirect interests held by related parties under common control on a proportionate basis in a manner consistent with its evaluation of indirect interests held through other related parties. That is, the single decision maker does not consider indirect interests held through related parties as equivalent to direct interests in determining whether it meets the economics criterion to be a primary beneficiary. This new guidance

14

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

becomes effective for the Partnership in the first quarter of fiscal 2018. Early adoption is permitted, including adoption in an interim period. The Partnership is evaluating the impact of this standard on its consolidated financial statements and disclosures.

In October 2016, the FASB issued an update which eliminates a prior exception and now requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory, such as property and equipment, when such transfer occurs. This new guidance becomes effective for the Partnership in the first quarter of fiscal 2020 and shall be applied on a modified retrospective basis through a cumulative–effect adjustment directly to retained earnings as of the beginning of the period of adoption. Early adoption is permitted. The Partnership is evaluating the impact of this standard on its consolidated financial statements and disclosures.

In August 2016, the FASB issued an update to the statement of cash flows guidance, which addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. One identified cash flow issue relates to distributions received from equity method investees whereby the reporting entity should make an accounting policy election to classify distributions received from equity method investees using either the cumulative earnings approach or the nature of the distribution approach. This new guidance becomes effective for the Partnership in the first quarter of fiscal 2018 and is applied retrospectively. Early adoption is permitted, including adoption in an interim period. The Partnership is evaluating the change in accounting policy from the cumulative earnings approach to the nature of the distribution approach and the impact on its consolidated statements of cash flows and disclosures.

In March 2016, the FASB issued an update to the equity method investments guidance, which eliminates the requirement that an entity retroactively adopt the equity method of accounting if an investment qualifies for use of the equity method as a result of an increase in the level of ownership or degree of influence. The update requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for equity method accounting. This new guidance will be effective for the Partnership beginning on December 1, 2017 on a prospective basis. Early adoption is permitted. The Partnership is evaluating the impact of this standard on its consolidated financial statements and disclosures.

In February 2016, the FASB issued an update to the lease accounting guidance, which requires entities to begin recording assets and liabilities arising from substantially all leases on the balance sheet. The new guidance will also require significant additional disclosures about the amount, timing and uncertainty of cash flows from leases. This new guidance will be effective for the Partnership in the first quarter of fiscal 2020 using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. The Partnership is evaluating the impact of this standard on its consolidated financial statements and disclosures.

In May 2014, the FASB issued a new revenue recognition standard based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The FASB has issued several updates to the standard which (i) clarify the application of the principal versus agent guidance; (ii) clarify the guidance relating to performance obligations and licensing; and (iii) clarify assessment of the collectability criterion, presentation of sales taxes, measurement date for non-cash consideration and completed contracts at transaction. The new revenue recognition standard, amended by the updates, becomes effective for the Partnership in the first quarter of fiscal 2019 and is to be applied retrospectively using one of two prescribed methods. Early adoption is permitted. While the Partnership is continuing to assess all potential impacts of the standard, it currently believes the impact on its consolidated financial statements is not material because over 90% of the Partnership’s total revenue for all periods is comprised of lease revenue, which is substantially unchanged under the new standard.

Other than as described above, there has been no issued accounting guidance not yet adopted by the Partnership that it believes is material or potentially material to its consolidated financial statements. 

15

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

Note 2. Business Combinations

Acquisition accounting is dependent upon certain valuations and other studies that must be completed as of the acquisition date. The judgments made in the context of the purchase price allocation can materially impact the Partnership’s future results of operations. The Partnership’s purchase price allocations for acquisitions completed through November 30, 2016 are final and not subject to revision. For the acquisition completed during the nine months ended August 31, 2017, the valuation is based on the preliminary assessment of the fair values of the assets acquired, liabilities assumed and noncontrolling interests as of the acquisition date, and is subject to change as the Partnership obtains additional information for its estimates during the respective measurement period.

Kern Acquisition:

On January 26, 2016, OpCo and SunPower entered into the Kern Purchase Agreement, which was amended on September 28, 2016, November 30, 2016, February 24, 2017, and June 9, 2017, pursuant to which OpCo agreed to purchase an interest in the Kern Project. OpCo’s acquisition of the Kern Project is being effectuated in phases summarized below:

(i)
Phase 1(a): On January 26, 2016, 8point3 OpCo Holdings, LLC, a wholly owned subsidiary of OpCo (“OpCo Holdings”), acquired from SunPower all of the class B limited liability company interests of the Kern Class B Partnership.  Prior to the date of the execution of the Kern Purchase Agreement and in connection with the closing of the tax equity financing for the Kern Project, described below, the Kern Project Entity, an indirect subsidiary of the Kern Class B Partnership, acquired the Kern Phase 1(a) Assets. The initial phase of the acquisition of the Kern Project is referred to herein as the “Kern Phase 1(a) Acquisition.”

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

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

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

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

The aggregate purchase price for the acquisition is up to $36.7 million in cash, of which OpCo paid approximately $4.9 million on January 27, 2016 in connection with the closing of the first phase, approximately $9.2 million on September 9, 2016 in connection with the closing of the second phase, approximately $8.4 million on November 30, 2016 in connection with the closing of the third phase, approximately $6.0 million on February 24, 2017 in connection with the closing of the fourth phase, and approximately $3.2 million on June 9, 2017 in connection with the closing of the fifth phase. Please read "—Note 15—Subsequent Events” for further details.

In addition, on January 22, 2016, a subsidiary of the Kern Class B Partnership entered into a tax equity financing facility with a third-party investor, which allocates to OpCo a certain share of cash flows from the Kern Project pursuant to a distribution waterfall. Pursuant to this distribution waterfall, the tax equity investor is entitled to a monthly amount of project cash flow until a specified “flip” point is achieved. After the “flip” point, the cash allocations to OpCo increase. In addition, upon reaching the flip point, OpCo has a right to purchase the tax equity investor’s interests in the project for an amount that is not less than its fair market value. The tax equity investor made capital contributions to fund purchase price payments of approximately $29.2 million, of which $0.9 million, $1.8 million, $1.3 million, $6.7 million, $8.2 million, $6.3 million, and $4.0 million was paid on January 22, 2016, September 9, 2016, November 30, 2016, December 14, 2016, February 24, 2017, June 9, 2017, and September 28, 2017, respectively. For more information about the Partnership's tax equity structures in general, please read Part I, Item 1. “Business—Tax Equity Financing” of its 2016 10-K. 

The Kern Phase 1(a) Acquisition, the Kern Phase 1(b) Acquisition, the Kern Phase 2(a) Acquisition, the Kern Phase 2(b) Acquisition, and the Kern Phase 2(c) Acquisition qualify as business combinations and the Partnership accounts for the transactions under the acquisition method. The purchase allocation of the identifiable assets acquired, liabilities assumed and noncontrolling interests of the Kern Phase 1(a) Assets, the Kern Phase 1(b) Assets, the Kern Phase 2(a) Assets, the Kern Phase 2(b) Assets, and the Kern Phase 2(c) Assets are disclosed in the following table.

16

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

 
Fair Value
 
Kern Phase 1(a)
 
Kern Phase 1(b)
 
Kern Phase 2(a)
 
Kern Phase 2(b)
 
Kern Phase 2(c)
(in thousands)
Assets
 
Assets
 
Assets
 
Assets
 
Assets
Property and equipment
$
9,510

 
$
18,856

 
$
14,873

 
$
11,872

 
$
6,710

Related party payable
(3,435
)
 
(7,123
)
 
(4,504
)
 
(4,287
)
 
(2,618
)
Asset retirement obligation
(322
)
 
(785
)
 
(623
)
 
(493
)
 
(279
)
Noncontrolling interest
(866
)
 
(1,794
)
 
(1,332
)
 
(1,078
)
 
(658
)
Net assets acquired
$
4,887

 
$
9,154

 
$
8,414

 
$
6,014

 
$
3,155


Valuation methodology:

The Partnership utilized the discounted cash flow method under the income approach to value property and equipment for the Kern Phase 1(a) Assets, the Kern Phase 1(b) Assets, the Kern Phase 2(a) Assets, the Kern Phase 2(b) Assets, and the Kern Phase 2(c) Assets. Key assumptions used in the discounted cash flow method included forecasted pre-tax cash flows, forecasted taxable income and discount rates. All estimates, key assumptions and forecasts were reviewed by the Partnership and the fair value analyses and related valuations represent the conclusions of management.

Supplementary Data:

The results of operations for each phase of the Kern Project acquisition have been included in the Partnership’s consolidated statements of operations since their respective dates of acquisition. The Kern Phase 2(b) Assets and the Kern Phase 2(c) Assets contributed approximately $0.3 million and $0.5 million to the Partnership’s operating revenue in the three and nine months ended August 31, 2017, respectively, and increased operating income by $0.1 million and $0.2 million in the three and nine months ended August 31, 2017, respectively. Pro forma results of operations have not been presented as the impact of the acquisitions on February 24, 2017 and June 9, 2017 are not material to the Partnership’s results of operations for the current or prior periods. Additionally, the Kern Phase 2(b) Assets and the Kern Phase 2(c) Assets became operational after the acquisition date and therefore, would not have had any pro forma results in the prior period.

Note 3. Investment in Unconsolidated Affiliates

On November 11, 2016, OpCo entered into the Stateline Purchase Agreement with First Solar to acquire a 34% interest in the Stateline Project for $329.5 million (the “Stateline Acquisition”). The Stateline Acquisition closed on December 1, 2016 and the Partnership recorded an investment of $329.9 million after consideration of acquisition-related costs.

As of August 31, 2017, the Partnership owns a 49% ownership interest in each of SG2 Holdings, North Star Holdings, Lost Hills Blackwell Holdings and Henrietta Holdings, and a 34% ownership interest in Stateline Holdings. The minority membership interests are accounted for as equity method investments, as the Partnership is able to exercise significant influence through its governing board, while the non-affiliated majority owner otherwise controls. The following table summarizes the activity of the Partnership’s investments in its unconsolidated affiliates during each of the three and nine months ended August 31, 2017 and August 31, 2016, respectively:
 
Three Months Ended
 
Nine Months Ended
(in thousands)
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Balance at the beginning of the period
$
785,832

 
$
348,588

 
$
475,078

 
$
352,070

Investments in its unconsolidated affiliates during the period

 

 
330,087

 

Equity in earnings in unconsolidated affiliates (1)
23,322

 
8,075

 
33,287

 
13,504

Distributions from unconsolidated affiliates
(17,169
)
 
(6,872
)
 
(46,467
)
 
(15,783
)
Balance at the end of the period
$
791,985

 
$
349,791

 
$
791,985

 
$
349,791

 
(1)
The net income (loss) used to determine the Partnership’s equity in earnings of unconsolidated affiliates reflects adjustments pursuant to the equity method of accounting, including the amortization of basis differences resulting from the Partnership’s proportionate share of certain equity method investees’ net assets exceeding their carrying values.

The difference between the amounts at which the Partnership’s investments in unconsolidated affiliates are carried and the Partnership’s proportionate share of the equity method investee’s net assets for equity method investments was $137.4

17

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

million and $83.2 million as of August 31, 2017 and November 30, 2016, respectively. The Partnership accretes the basis difference over the life of the underlying assets and the accretion expense was $1.0 million and $0.4 million for the three months ended August 31, 2017 and August 31, 2016, respectively, and $3.1 million and $1.2 million for the nine months ended August 31, 2017 and August 31, 2016, respectively.
 
The following table presents summarized financial information of SG2 Holdings, North Star Holdings, Lost Hills Blackwell Holdings, Henrietta Holdings and Stateline Holdings as derived from the unaudited condensed consolidated financial statements of such entities for the each of the three and nine months ended August 31, 2017 and August 31, 2016, respectively:
 
Three Months Ended
 
Nine Months Ended
(in thousands)
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Summary statements of operations information:
 
 
 
 
 
 
 
Revenue
$
74,549

 
$
24,433

 
$
136,442

 
$
52,140

Operating expenses
26,939

 
11,201

 
78,851

 
34,483

Net income
47,627

 
13,346

 
53,298

 
17,964


 
Note 4. 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 unaudited condensed consolidated balance sheets is as follows:
 
As of
(in thousands)
August 31, 2017
 
November 30, 2016
Minimum lease payment receivable, net (1)
$
95,373

 
$
100,161

Unguaranteed residual value
12,848

 
12,926

Less: unearned income
(28,186
)
 
(30,557
)
Net financing receivables
$
80,035

 
$
82,530

Short-term financing receivables, net (2)
$
2,551

 
$
2,516

Long-term financing receivables, net
$
77,484

 
$
80,014

 
(1)
Allowance for losses on financing receivables was $0.6 million and $0.7 million as of August 31, 2017 and November 30, 2016, respectively.
(2)
Accounts receivable and short-term financing receivables, net on the unaudited condensed consolidated balance sheets includes other trade accounts receivable of $8.3 million and $2.9 million as of August 31, 2017 and November 30, 2016, respectively.


18

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

Current and Non-current Assets
 
As of
(in thousands)
August 31, 2017
 
November 30, 2016
Prepaid expense and other current assets
 
 
 
Reimbursable network upgrade costs (1)
$
8,615

 
$
13,870

Derivative financial instruments
1,246

 

Other current assets (2)
2,451

 
1,875

Total
$
12,312

 
$
15,745

Property and equipment, net
 
 
 
Utility solar power systems
632,478

 
578,817

Leased solar power systems
137,258

 
137,475

Land
1,020

 
1,020

Construction-in-progress (3)
3,496

 
36,981

 
$
774,252

 
$
754,293

Less: accumulated depreciation
(54,384
)
 
(34,161
)
Total
$
719,868

 
$
720,132

Other long-term assets
 
 
 
Reimbursable network upgrade costs (1)
$
20,026

 
$
21,781

Intangible assets (4)
1,433

 
1,754

Derivative financial instruments

 
897

Total
$
21,459

 
$
24,432

 
(1)
For the Kingbird Project and the Quinto Project, the construction costs related to the network upgrade of a transmission grid belonging to a utility company are reimbursable by that utility company over five years from the date the project reached commercial operation.
(2)
Other current assets included $0.3 million due from SunPower related to system output performance warranties and system repairs in connection with $0.1 million of system output performance warranty accrual and $0.2 million of system repairs accrual recorded in the “Accounts payable and other current liabilities” line item on the unaudited condensed consolidated balance sheets as of August 31, 2017. Similarly, other current assets included $0.5 million due from SunPower related to system output performance warranties and system repairs in connection with $0.2 million of system output performance warranty accrual and $0.3 million of system repairs accrual recorded in the “Accounts payable and other current liabilities” line item on the consolidated balance sheet as of November 30, 2016.
(3)
Construction-in-progress as of August 31, 2017 and November 30, 2016 is the project assets related to the Kern Phase 1(a) Assets.
(4)
Intangible assets represent a customer contract intangible that is amortized on a straight-line basis beginning on COD through the contract term end date of December 31, 2020. Operating revenues were reduced by $0.1 million and $0.3 million in the three and nine months ended August 31, 2017, respectively. Operating revenues were not affected by intangible assets in the three and nine months ended August 31, 2016.


19

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

Current Liabilities
 
As of
(in thousands)
August 31, 2017
 
November 30, 2016
Accounts payable and other current liabilities
 
 
 
Trade and accrued accounts payable
$
885

 
$
1,089

Related party payable (1)
4,417

 
20,653

System output performance warranty
52

 
196

Residential lease system repairs accrual
253

 
331

Other short-term liabilities
958

 
1,502

Total
$
6,565

 
$
23,771

 
(1)
Related party payable on the unaudited condensed consolidated balance sheets as of August 31, 2017 consists of (i) $3.5 million related to the purchase price payable to SunPower, which will be funded by the tax equity investor for the Kern Phase 1(a) Acquisition and the Kern Phase 2(c) Acquisition; (ii) $0.9 million related to accrued distribution to tax equity investors; and (iii) less than $0.1 million for accounts payable to related parties associated with O&M, AMA and MSA fees owed to the Sponsors. Related party payable on the consolidated balance sheets as of November 30, 2016 consists of (i) $19.5 million related to the purchase price payable to SunPower for the Kern Phase 1(a) Acquisition, the Kern Phase 1(b) Acquisition, the Kern Phase 2(a) Acquisition and the Macy’s Maryland Acquisition; (ii) $1.0 million related to accrued distribution to tax equity investors; and (iii) $0.1 million for accounts payable to related parties associated with O&M, AMA and MSA fees owed to the Sponsors.


Note 5. 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.

The total minimum lease and easement commitments at August 31, 2017 under these land use agreements are as follows:
(in thousands)
2017 (remaining
three months)
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
Total
Land use payments
$
406

 
$
1,329

 
$
1,686

 
$
1,742

 
$
1,782

 
$
56,411

 
$
63,356

 
Solar Power System Performance Warranty

Lease agreements require the Partnership to undertake a system output performance warranty. The Partnership has recorded in “Accounts payable and other current liabilities” amounts related to these system output performance warranties totaling $0.1 million and $0.2 million as of August 31, 2017 and November 30, 2016, respectively. The Partnership has also recorded in “Other current assets” amounts of $0.1 million and $0.2 million as of August 31, 2017 and November 30, 2016, relating to anticipated performance warranty reimbursements from the O&M provider.


20

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

The following table summarizes accrued system output performance warranty activity for the each of three and nine months ended August 31, 2017 and August 31, 2016, respectively:
 
Three Months Ended
 
Nine Months Ended
(in thousands)
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Balance at the beginning of the period
$
64

 
$
140

 
$
196

 
$
237

Settlements during the period
(16
)
 
(51
)
 
(67
)
 
(207
)
Adjustments during the period
4

 
110

 
(77
)
 
169

Balance at the end of the period
$
52

 
$
199

 
$
52

 
$
199


Asset Retirement Obligations

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

The following table summarizes ARO activity for each of the three and nine months ended August 31, 2017 and August 31, 2016, respectively:
 
Three Months Ended
 
Nine Months Ended
(in thousands)
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Balance at the beginning of the period
$
14,319

 
$
11,542

 
$
13,448

 
$
9,992

ARO assumed in acquisition
279

 
278

 
772

 
1,806

Accretion expense
201

 
141

 
558

 
387

Revisions to ARO during the period
(3
)
 
(78
)
 
18

 
(302
)
Balance at the end of the period
$
14,796

 
$
11,883

 
$
14,796

 
$
11,883

 
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 each of the three and nine months ended August 31, 2017 and August 31, 2016, there were no known environmental contingencies that required the Partnership to recognize a liability.
 

21

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

Note 6. Lease Agreements and Power Purchase Agreements

Lease Agreements

As of August 31, 2017, the Partnership’s unaudited condensed consolidated financial statements include approximately 5,800 residential lease agreements which have original terms of 20 years and are classified as either operating or sales-type leases. In addition, the lease agreement for the Maryland Solar Project has a lease term that will expire on December 31, 2019, and the lessee, who is an affiliate of First Solar, is obligated to pay a fixed amount of rent that is set based on the expected operations of the plant.

The following table presents the Partnership’s minimum future rental receipts on operating leases (including the lease agreement for the Maryland Solar Project and the residential lease portfolio) placed in service as of August 31, 2017:
 
(in thousands)
2017 (remaining
three months)
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
Total
Minimum future rentals on residential
   operating leases placed in service (1)
$
907

 
$
3,707

 
$
3,727

 
$
3,748

 
$
3,770

 
$
42,399

 
$
58,258

Maryland Solar lease
781

 
5,173

 
4,912

 

 

 

 
10,866

Total operating leases
$
1,688

 
$
8,880

 
$
8,639

 
$
3,748

 
$
3,770

 
$
42,399

 
$
69,124

 
(1)
Minimum future rentals on operating leases placed in service do not include contingent rentals that may be received from customers under agreements that include performance-based incentives and executory costs.

As of August 31, 2017, future maturities of net financing receivables for sales-type leases are as follows:
(in thousands)
2017 (remaining
three months)
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
Total
Scheduled maturities of minimum lease
   payments receivable (1)
$
1,558

 
$
5,635

 
$
5,721

 
$
5,811

 
$
5,905

 
$
70,743

 
$
95,373

 
(1)
Minimum future rentals on sales-type leases placed in service do not include contingent rentals that may be received from customers under agreements that include performance-based incentives and executory costs.

Power Purchase Agreements

Under the terms of various PPAs, the Partnership’s contracted counterparties may be obligated to take all or part of the output from the system at stipulated prices over defined periods. All PPAs associated with solar generation systems operating as of August 31, 2017 have no minimum lease payments and all of the rental income under these leases is recorded as revenue when the electricity is delivered.

SREC Sales Agreement

The Partnership applies for and receives SRECs for power generated by certain of its solar power systems. The Partnership has entered into a sales agreement with a non-affiliated party (the “SREC Sales Agreement”) to assist it in meeting its own emissions reduction or conservation requirements. Under the terms of the SREC Sales Agreement, the contracted counterparty is obligated to purchase an annual number of SRECs from the Partnership at stipulated prices over a defined period of time. The Partnership recognizes revenue and associated costs upon delivery of the SRECs to the counterparty. As of August 31, 2017, firm sales under the SREC Sales Agreement are as follows:
(in thousands)
2017 (remaining
three months)
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
Total
SREC sales
$
82

 
$
781

 
$
781

 
$
781

 
$
195

 
$

 
$
2,620

 
 

22

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

Note 7. Debt and Financing Obligations
 
The following table summarizes the Partnership’s debt obligations on its unaudited condensed consolidated balance sheets:
 
August 31, 2017
 
November 30, 2016
(in thousands)
Amount
 
Interest Rate
 
Amount
 
Interest Rate
Term loan due June 2020
$
300,000

 
3.24
%
 
$
300,000

 
2.61
%
Incremental term loan due June 2020
250,000

 
3.24
%
 

 
N/A

Delayed draw term loan facility due June 2020
25,000

 
3.24
%
 
25,000

 
2.61
%
Revolving credit facility due June 2020
90,000

 
3.24
%
 
63,000

 
2.61
%
Stateline Promissory Note due December 2020
50,004

 
4.00
%
 

 
N/A

Less: debt issuance costs
(2,814
)
 
N/A

 
(3,564
)
 
N/A

Total
$
712,190

 
 
 
$
384,436

 
 

Credit Facility

On June 5, 2015, OpCo entered into a $525.0 million credit facility, consisting of a $300.0 million term loan facility, a $25.0 million delayed draw term loan facility and a $200.0 million revolving credit facility. On April 6, 2016, the parties thereto amended the credit facility (i) to provide for the lenders’ consent to the Omnibus Agreement, (ii) to expand OpCo’s ability to further amend the Omnibus Agreement without lender consent in the future, subject to certain conditions, (iii) to permit certain customary restrictions on transfers of the equity interests of certain Project Entities, which are jointly owned, indirectly, by OpCo and SunPower, (iv) to supplement the Pledge and Security Agreement between the parties in light of the foregoing amendment, and (v) to make certain clarifying modifications to definitions and cross references. On September 30, 2016, OpCo entered into the Joinder Agreement, pursuant to which OpCo obtained a new $250.0 million incremental term loan facility, increasing the maximum borrowing capacity under the credit facility to $775.0 million.

Loans outstanding under the credit facility bear interest at either (i) a base rate, which is the highest of (x) the federal funds rate plus 0.50%, (y) the administrative agent’s prime rate and (z) one-month LIBOR, in each case, plus an applicable margin; or (ii) one-, two-, three- or six-month LIBOR plus an applicable margin. There will be no principal amortization over the term of the credit facility. The unused portion of the revolving credit facility and delayed draw term loan facility is subject to a commitment fee of 0.30% per annum. OpCo may prepay the borrowings under the term loan facility and the delayed draw term loan facility at any time. OpCo has entered into interest rate swap agreements to hedge the interest rate on a portion of the borrowings under the term loan facility. For more details, please read “—Note 8—Fair Value.”

OpCo’s credit facility contains covenants including, among others, requiring the Partnership to maintain the following financial ratios: (i) a debt to cash flow ratio of not more than (a) 6.00 to 1.00 for the fiscal quarters ending November 30, 2016 through November 30, 2017; and (b) 5.50 to 1.00 for each fiscal quarter ending thereafter; and (ii) a debt service coverage ratio of not less than 1.75 to 1.00. In addition, an event of default occurs under the credit facility upon a change of control. The credit facility defines a change of control as occurring when, among other things, (i) the Sponsors (or either of them) cease to direct the management, directly or indirectly, of the Partnership or OpCo, or (ii) the Sponsors collectively cease to own 35% of the economic interest in OpCo. On April 5, 2017, First Solar notified the general partner’s board of directors of its intention to explore alternatives related to its interests in the Partnership. Following such announcement, SunPower also notified the general partner’s board of directors that it is exploring alternatives related to its interests in the Partnership. Although its Sponsors have publicly announced their current intentions, there is no assurance that either or both of its Sponsors will pursue or effect any particular alternative. In addition, the credit facility contains customary non-financial covenants and certain restrictions that will limit the Partnership’s, OpCo’s and certain of the Partnership’s and its domestic subsidiaries’ ability to, among other things, incur or guarantee additional debt and to make distributions on or redeem or repurchase OpCo common units. The Joinder Agreement amended OpCo’s credit facility to permit OpCo to incur up to $50.0 million in subordinated indebtedness from First Solar or its affiliate to pay a portion of the purchase price for the Stateline Project. As of August 31, 2017, the Partnership was in compliance with its debt covenants.

OpCo’s credit facility is collateralized by a pledge of the equity of OpCo and certain of its subsidiaries. The Partnership and each of OpCo’s subsidiaries, other than certain non-guarantor subsidiaries, have guaranteed the obligations of OpCo under the credit facility.


23

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

As of both August 31, 2017 and November 30, 2016, OpCo had approximately $54.9 million of letters of credit outstanding under the revolving credit facility.

Stateline Promissory Note
 
On December 1, 2016, in connection with the Stateline Acquisition, OpCo issued a promissory note to First Solar in the principal amount of $50.0 million. The Stateline Promissory Note is unsecured and matures on the date that is six months after the maturity date under OpCo’s credit facility. Interest will accrue at a rate of 4.00% per annum, except it will accrue at a rate of 6.00% per annum (i) upon the occurrence and during the continuation of a specified event of default and (ii) in respect of amounts accrued as payments-in-kind pursuant to the terms of the note. OpCo is not permitted to prepay the $50.0 million promissory note without the consent of certain lenders under its existing credit agreement (except for certain mandatory prepayments). Until OpCo has paid in full the principal and interest on promissory note, OpCo is restricted in its ability to: (i) acquire interests in additional projects (other than the acquisition of the Kern Phase 2(a) Assets, the Kern Phase 2(b) Assets, the Kern Phase 2(c) Assets, and the Kern Remaining Assets); (ii) use the net proceeds of equity issuances except as prescribed in the promissory note; (iii) incur additional indebtedness to which the promissory note would be subordinate; and (iv) extend the maturity date under OpCo’s existing credit facility.
 
August 2011 Letter of Credit Facility with Deutsche Bank

In August 2011, the Predecessor’s parent, SunPower, entered into a letter of credit facility agreement with Deutsche Bank, as administrative agent, and certain financial institutions. Payment of obligations under the letter of credit facility is guaranteed by the majority shareholder of SunPower, Total S.A. As of August 31, 2017, and November 30, 2016, letters of credit issued and outstanding under the August 2011 letter of credit facility with Deutsche Bank which is available to SunPower for the Quinto Project and the RPU Project totaled $0.2 million and $11.5 million, respectively. Pursuant to the Omnibus Agreement, SunPower, as the Sponsor who contributed the Quinto Project, canceled one of its letter of credit facilities associated with the Quinto Project upon its achieving COD in November 2015. Since the RPU Project achieved COD in September 2015, SunPower, as the Sponsor who contributed the RPU Project, canceled the related letters of credit, and the Partnership has issued the required letters of credit under its revolving credit facility.

Note 8. Fair Value

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

Level 1—Quoted prices in active markets for identical assets or liabilities.
Level 2—Measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1.
Level 3—Prices or valuations that require management inputs that are both significant to the fair value measurement and unobservable.

The first two levels in the hierarchy are considered observable inputs and the last is considered unobservable.

Assets and Liabilities Measured at Fair Value on a Recurring Basis 

The following table presents the Partnership’s assets and liabilities measured at estimated fair value on a recurring basis, categorized in accordance with the fair value hierarchy:
 
August 31, 2017
 
November 30, 2016
(in thousands)
Level 2
 
Total
 
Level 2
 
Total
Assets
 

 
 

 
 

 
 

Derivative financial instruments
$
1,246

 
$
1,246

 
$
897

 
$
897

Total assets
$
1,246

 
$
1,246

 
$
897

 
$
897


Derivative financial instruments: On July 17, 2015, OpCo entered into interest rate swap agreements intended to hedge the interest rate risk on the outstanding borrowings under the term loan with an aggregate notional value of $240.0 million. Under the interest rate swap agreements, OpCo paid a fixed swap rate of interest of 1.55% and the counterparties to the

24

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

agreements paid a floating interest rate based on three-month LIBOR at quarterly intervals through the maturity date of August 31, 2018. OpCo had the right to cancel the interest rate swap agreements on August 31, 2016 and any quarterly fixed payment date thereafter with a minimum of five business days' notification. OpCo exercised its right to cancel the interest rate swap agreements on August 31, 2016 and entered into new interest rate swap agreements intended to hedge the interest rate risk on the outstanding borrowings under the term loan with an aggregate notional value of $250.0 million. Under the new interest rate swap agreements, OpCo will pay a fixed swap rate of interest of approximately 0.85% and the counterparties to the agreements will pay a floating interest rate based on one-month LIBOR at monthly intervals through the maturity date of August 31, 2018. On January 5, 2017, OpCo entered into another interest rate swap agreement intended to hedge the interest rate risk on the outstanding borrowings under the term loan with an aggregate notional value of $40.0 million. Under this interest rate swap agreement, OpCo will pay a fixed swap rate of interest of approximately 1.16% and the counterparty to the agreement will pay a floating interest rate based on one-month LIBOR at monthly intervals through the maturity date of August 31, 2018.

As of both August 31, 2017 and November 30, 2016, these interest rate swap agreements had not been designated as cash flow hedges and are reflected at fair value on the unaudited condensed consolidated balance sheets. As of August 31, 2017, these interest rate swap agreements have been presented in other current assets on the unaudited condensed consolidated balance sheet since the maturity date is within one year after the balance sheet date. As of November 30, 2016, these interest rate swap agreements have been presented in other long-term assets on the unaudited condensed consolidated balance sheet since the maturity date is over one year after the balance sheet date. During the three and nine months ended August 31, 2017, the Partnership recorded an unrealized loss of $0.3 million and an unrealized gain of $0.3 million, respectively, within other expense (income) in the unaudited condensed consolidated statements of operations related to the change in fair value. During the three and nine months ended August 31, 2016, the Partnership recorded an unrealized gain of $0.3 million and $0.5 million, respectively, within other expense (income) in the unaudited condensed consolidated statements of operations related to the change in fair value. The primary inputs into the valuation of interest rate swaps are interest yield curves, interest rate volatility, and credit spreads. The Partnership's interest rate swaps are classified within Level 2 of the fair value hierarchy, since all significant inputs are corroborated by market observable data. There were no transfers in or out of Level 1, Level 2 and Level 3 during the period.

Liabilities Measured at Fair Value on a Nonrecurring Basis

Long-term debt and financing obligations: The estimated fair value of the Partnership’s long-term debt was classified within Level 2 of the fair value hierarchy as of August 31, 2017 and November 30, 2016, and approximated its carrying value of $712.2 million and $384.4 million, respectively. The term loan facility is a variable rate debt with the interest rate indexed to the market and reset on a frequent and short-term basis. The Stateline Promissory Note is a fixed rate debt and the fair value was estimated using the income approach based on observable market inputs.

Note 9. Noncontrolling Interests

Noncontrolling interests represent the portion of net assets in consolidated subsidiaries that are not attributable, directly or indirectly, to the Partnership. For accounting purposes, the holders of noncontrolling interests of the Partnership include the Sponsors, which are SunPower and First Solar, as described in “—Note 1—Description of Business,” and third-party investors under the tax equity financing facilities. As of August 31, 2017 and November 30, 2016, First Solar and SunPower had noncontrolling interests of 28.0% and 36.5%, respectively, in OpCo.

In addition, certain subsidiaries of OpCo have entered into tax equity financing facilities with third-party investors under which the parties invest in entities that hold the solar power systems. The Partnership, through OpCo, holds controlling interests in these less-than-wholly-owned entities and has therefore fully consolidated these entities. The Partnership accounts for the portion of net assets 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 unaudited condensed consolidated balance sheets and the balance is the greater of the carrying value calculated under the HLBV Method or the redemption value.

During the three and nine months ended August 31, 2017, OpCo acquired noncontrolling interests totaling $0.7 million and $1.7 million, respectively. Please read “—Note 2—Business Combinations” for further details. During the three and nine months ended August 31, 2016, OpCo acquired noncontrolling interests totaling $0.6 million and $36.8 million, respectively. Please read “—Note 3—Business Combinations” of the 2016 10-K for further details.


25

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

As of August 31, 2017 and November 30, 2016, redeemable noncontrolling interests attributable to tax equity investors after adjusting the carrying amount to the redemption value was $17.3 million and $17.6 million, respectively, and noncontrolling interests attributable to tax equity investors were $43.3 million and $40.8 million, respectively.

During the three months ended August 31, 2017 and August 31, 2016 such indirect subsidiaries of OpCo received $5.6 million and zero, respectively, contributions from third-party investors under the related facilities and attributed $1.6 million and $24.3 million, respectively, in losses to the third-party investors primarily as a result of allocating certain assets, including tax credits, if any, to the investors. During the nine months ended August 31, 2017 and August 31, 2016 such indirect subsidiaries of OpCo received $24.4 million and $47.2 million, respectively, contributions from third-party investors under the related facilities and attributed $17.1 million and $112.1 million, respectively, in losses to the third-party investors primarily as a result of allocating certain assets, including tax credits, if any, to the investors.

During the three months ended August 31, 2017 and August 31, 2016, such indirect subsidiaries of OpCo made distributions to third-party investors under the related facilities of $2.7 million and $2.3 million, respectively. During the nine months ended August 31, 2017 and August 31, 2016, such indirect subsidiaries of OpCo made distributions to third-party investors under the related facilities of $6.7 million and $4.9 million, respectively.

The following table presents the noncontrolling interest balances by entity, reported in shareholders’ equity in the unaudited condensed consolidated balance sheets as of August 31, 2017 and November 30, 2016:
 
As of
(in thousands)
August 31, 2017
 
November 30, 2016
First Solar
$
236,746

 
$
238,210

SunPower
309,440

 
311,327

Tax equity investors
43,313

 
40,794

Total
$
589,499

 
$
590,331


Note 10. Shareholders’ Equity

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 to the public. On September 28, 2016 the Partnership sold in an underwritten registered public offering 8,050,000 Class A shares representing limited partner interests in the Partnership.

ATM Program

On January 30, 2017, the Partnership established the ATM Program under which the Partnership may sell Class A shares from time to time through the ATM Agents up to an aggregate sales price of $125.0 million. The Partnership may also sell Class A shares to any ATM Agent, as principal for its own account, at a price agreed upon at the time of the sale. The Partnership will use the net proceeds from sales under the ATM Program to purchase a number of common units in OpCo equal to the number of Class A shares issued under the ATM Program. OpCo may use the proceeds for general corporate purposes, which may include, among other things, repaying borrowings under the Stateline Promissory Note and OpCo’s credit facilities, and funding working capital or acquisitions. No shares were issued under the ATM Program during the quarter ended August 31, 2017.

As of both August 31, 2017 and November 30, 2016, the Partnership owned a 35.5% limited liability company interest in OpCo as well as a controlling noneconomic managing member interest in OpCo, and the Sponsors collectively owned 51,000,000 Class B shares in the Partnership, with SunPower and First Solar having owned 28,883,075 and 22,116,925 Class B shares, respectively, and together, having owned a noncontrolling 64.5% limited liability company interest in OpCo.


26

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

The following shares of the Partnership were outstanding as of August 31, 2017 and November 30, 2016, respectively:
 
As of
 
 
Shares
August 31, 2017
 
November 30, 2016
 
Shareholder
Class A shares
28,084,935

 
28,072,680

 
Public
Class B shares
22,116,925

 
22,116,925

 
First Solar
Class B shares
28,883,075

 
28,883,075

 
SunPower
Total shares outstanding
79,084,935

 
79,072,680

 
 
 
Cash Distribution

On July 14, 2017, the Partnership distributed $7.4 million on its Class A shares and OpCo distributed $13.5 million on its common and subordinated units, or in each case $0.2642 per share or unit, for the period from March 1, 2017 to May 31, 2017.

Note 11. Net Income Per Share

Basic net income per share is computed by dividing net income attributable to Class A shareholders by the weighted average number of Class A shares outstanding for the applicable period. Diluted net income per share is computed using basic weighted average Class A shares outstanding plus, if dilutive, any potentially dilutive securities outstanding during the period using the treasury-stock-type method. Pursuant to the Exchange Agreement entered into among the Partnership, the General Partner, OpCo, a wholly owned subsidiary of SunPower and a wholly owned subsidiary of First Solar, the Sponsors can tender OpCo common units and an equal number of such Sponsor’s Class B shares for redemption, and the Partnership has the right to directly purchase the tendered OpCo common units and Class B shares for, subject to the approval of its conflicts committee, cash or the issuance of Class A shares of the Partnership. If the Partnership elects to issue Class A shares, it would cancel the tendered Class B shares and hold the OpCo common units with the other OpCo common units it previously held, since the number of Class A shares issued must at all times equal the number of OpCo common units held by the Partnership. Since the Partnership would be holding additional OpCo common units, the net income attributable to Class A shares would proportionately increase, resulting in no change to net income per share for the three and nine months ended August 31, 2017 and August 31, 2016, respectively. In addition, there were no potentially dilutive securities (including any stock options, restricted stock and restricted stock units) for the three and nine months ended August 31, 2017 and August 31, 2016, respectively.


27

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

The following table presents the calculation of basic and diluted net income per share:
 
Three Months Ended
 
Nine Months Ended
(in thousands, except per share amounts)
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Basic net income per share:
 
 
 
 
 
 
 
Numerator:
 
 
 
 
 
 
 
Net income attributable to Class A shareholders
$
7,473

 
$
7,593

 
$
11,720

 
$
22,923

Denominator:
 
 
 
 
 
 
 
Basic weighted-average shares
28,081

 
20,015

 
28,077

 
20,011

 
 
 
 
 
 
 
 
Basic net income per share
$
0.27

 
$
0.38

 
$
0.42

 
$
1.15

 
 
 
 
 
 
 
 
Diluted net income per share:
 
 
 
 
 
 
 
Numerator:
 
 
 
 
 
 
 
Net income attributable to Class A shareholders
$
7,473

 
$
7,593

 
$
11,720

 
$
22,923

Add: Additional net income attributable to
   Class A shares due to increased percentage
   ownership in OpCo, net of tax, from the
   conversion of Class B shares
4,162

 
5,985

 
6,592

 
17,897

 
$
11,635

 
$
13,578

 
$
18,312

 
$
40,820

Denominator:
 
 
 
 
 
 
 
Basic weighted-average shares
28,081

 
20,015

 
28,077

 
20,011

Effect of dilutive securities:
 
 
 
 
 
 
 
Class B shares (1)
15,500

 
15,500

 
15,500

 
15,500

Diluted weighted-average shares
43,581

 
35,515

 
43,577

 
35,511

 
 
 
 
 
 
 
 
Diluted net income per share
$
0.27

 
$
0.38

 
$
0.42

 
$
1.15


(1)
Up to the amount of OpCo common units held by Sponsors


Note 12. Related Parties

Management Services Agreements

Immediately prior to the completion of the IPO on June 24, 2015, the Partnership, together with the General Partner, OpCo and Holdings, entered into similar but separate MSAs with affiliates of each of the Sponsors (each, a “Service Provider”). Under the MSAs, the Service Providers provide or arrange for the provision of certain administrative and management services for the Partnership and certain of its subsidiaries, including managing the Partnership’s day-to-day affairs, in addition to those services that are provided under existing O&M agreements and AMAs between affiliates of the Sponsors and certain of the subsidiaries of the Partnership. In August 2015, the First Solar MSA and the SunPower MSA were amended to adjust the annual management fee payable to each respective Service Provider. Under the First Solar MSA, OpCo pays an annual management fee of $0.6 million to the First Solar Service Provider. Under the SunPower MSA, OpCo pays an annual management fee of $1.1 million to the SunPower Service Provider. These payments are subject to annual adjustments for inflation. On January 20, 2017, the parties thereto amended the SunPower MSA to include Kingbird Solar, LLC and the Kingbird Project Entities under certain aspects of SunPower’s scope of managerial services effective April 30, 2016 in return for the associated AMA fee payable by First Solar Asset Management, LLC.

Costs incurred for these services were $0.4 million and $1.3 million the three and nine months ended August 31, 2017, respectively, and $0.4 million and $1.2 million for the three and nine months ended August 31, 2016, respectively.


28

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

EPC Agreements

Various projects are designed, engineered, constructed and commissioned pursuant to EPC agreements with affiliates of the Sponsors, which may include a 2- 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, 2017, all of the projects contributed by the Sponsors on the date of the IPO, along with the Henrietta Project, the Hooper Project, the Kern Phase 1(b) Assets, the Kern Phase 2(a) Assets, the Kern 2(b) Assets, the Kern 2(c) Assets, the Kingbird Project, the Macy’s Maryland Project and the Stateline Project have achieved COD. The Kern Phase 1(a) Assets are construction-in-progress as of August 31, 2017 and achieved COD in September 2017. SunPower as the EPC provider is required to complete the Kern Phase 1(a) Assets and pursuant to the Omnibus Agreement, all the associated costs to complete the Kern Phase 1(a) Assets are obligations of SunPower.

O&M Agreements and Asset Management Agreements

The Project Entities and certain other subsidiaries have entered into O&M agreements and AMAs with affiliates of the Sponsors, as applicable (except where such persons are otherwise subject to O&M agreements or AMAs with unaffiliated third parties). Under the terms of the O&M agreements and the AMAs, such affiliates have agreed to provide a variety of operation, maintenance and asset management services, and certain performance warranties or availability guarantees, to the subsidiaries of the Partnership in exchange for annual fees, which are subject to certain adjustments.

Costs incurred for O&M and AMA services were $1.7 million and $1.5 million for the three months ended August 31, 2017 and August 31, 2016, respectively, and $5.0 million and $3.8 million for the nine months ended August 31, 2017 and August 31, 2016, respectively.

Omnibus Agreement

The Partnership has entered into the Omnibus Agreement with its Sponsors, the General Partner, OpCo and Holdings.

The material provisions of the Omnibus Agreement are as follows: (a) each Sponsor was granted an exclusive right to perform certain services not otherwise covered by an O&M agreement or an AMA on behalf of the Project Entities contributed by such Sponsor; (b) with respect to any project in the Portfolio that had not achieved commercial operation as of the date contributed to the Partnership, the Sponsor who contributed such project agreed to pay to OpCo all costs required to complete such project, as well as certain liquidated damages in the event such project fails to achieve operability pursuant to an agreed schedule (subject to certain adjustments); (c) with respect to the Quinto Project and the North Star Project, the Sponsor who contributed such project agreed to pay to OpCo the difference, if any, between the amount of network upgrade refunds projected to be received in respect of such Sponsor’s contributed project at the time of the IPO and the amount of network upgrade refunds projected to be received given the actual amount of upgrade costs incurred in respect of such project; (d) each Sponsor agreed to certain undertakings on the part of its affiliates who are members of the Project Entities or who provide asset management, construction, operating and maintenance and other services to the Project Entities contributed by such Sponsor; (e) to the extent a Sponsor continues to post credit support on behalf of a Project Entity after it has been contributed to OpCo, OpCo agreed to reimburse such Sponsor upon any demand or draw under such credit support, and the Sponsor agreed to maintain such support pursuant to the applicable underlying contractual or regulatory requirements; (f) each Sponsor agreed to indemnify OpCo for any costs it incurs with respect to certain tax-related events and events in connection with tax equity financing arrangements; and (g) the parties agreed to a mutual undertaking regarding confidentiality and use of names, trademarks, trade names and other insignias. The schedules of the Omnibus Agreement are amended in connection with each project acquisition to include the solar power systems acquired effective the closing date of such acquisition.

During the three and nine months ended August 31, 2017, the Partnership received less than $0.1 million and $0.1 million, respectively, in indemnity payments from Sponsors related to the delay in commercial operations of the Kern Phase 1(a) Assets. During the three and nine months ended August 31, 2016, the Partnership received $0.1 million and $10.0 million, respectively, related to a shortfall associated with the network upgrade refunds projected to be received.

Promissory Notes

On November 25, 2015, OpCo issued a short-term promissory note to First Solar in the principal amount of $2.0 million (the “Short-term Note”), in exchange for First Solar’s loan of such amount to OpCo. Upon the receipt of certain payments by the Solar Gen 2 Project Entity from SDG&E under the power purchase agreement between the Solar Gen 2 Project Entity and SDG&E, which had been previously withheld pending completion of an administrative requirement (each, a “Specified

29

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

Payment”), OpCo was obligated to repay a portion of the principal amount of the Short-term Note equal to such Specified Payment and the unpaid balance of all interest accrued under the Short-term Note to and including the date of such repayment. Interest under the Short-term Note accrued at a rate of 1% on the portion of the principal of the Short-term Note equal to the amount of each Specified Payment from the date SDG&E remitted such payment to the Solar Gen 2 Project Entity through the date that OpCo repaid such amount to First Solar as described above. OpCo is permitted to prepay the Short-term Note at any time without penalty or premium. On December 30, 2016, OpCo repaid the Short-term Note to First Solar.

In connection with the closing of the Stateline Acquisition on December 1, 2016, OpCo issued the Stateline Promissory Note to First Solar in the principal amount of $50.0 million. Please read “—Note 7— Debt and Financing Obligations” for further details.

Purchase and Sale Agreements

On November 11, 2016, OpCo entered into the Stateline Purchase Agreement with First Solar and First Solar Asset Management, LLC pursuant to which OpCo agreed to purchase an interest in the Stateline Project, as further described above in “—Note 3—Investment in Unconsolidated Affiliates.” Effective December 1, 2016, OpCo acquired Stateline Holdings from First Solar for a total purchase price of $329.5 million (before consideration of acquisition-related costs).

On January 26, 2016, OpCo entered into the Kern Purchase Agreement with SunPower pursuant to which OpCo agreed to purchase an interest in the Kern Project, as further described above in “—Note 2—Business Combinations.” Effective January 26, 2016, a subsidiary of OpCo acquired from SunPower all of the class B limited liability company interests of the Kern Class B Partnership. Pursuant to the Kern Purchase Agreement, the purchase price for the Kern Project will be paid by OpCo when each phase of the project reaches “mechanical completion.” In addition, on January 22, 2016, a subsidiary of the Kern Class B Partnership entered into a tax equity financing facility with a third-party investor, which allocates to OpCo a certain share of cash flows from the Kern Project pursuant to a specified distribution waterfall. The tax equity investor made capital contributions to fund purchase price payments of approximately $29.2 million, of which $0.9 million, $1.8 million, $1.3 million, $6.7 million, $8.2 million, $6.3 million, and $4.0 million was paid on January 22, 2016, September 9, 2016, November 30, 2016, December 14, 2016, February 24, 2017, June 9, 2017, and September 28, 2017, respectively.

First Solar ROFO Agreement

Pursuant to the First Solar ROFO Agreement, First Solar previously granted to OpCo a right of first offer to purchase certain solar energy generating facilities for a period of five years. Such solar projects included the 179 MW Switch Station solar generation project in Nevada (“Switch Station”), the 40 MW Cuyama solar generation project in California (“Cuyama”), and the 280 MW California Flats solar generation project in California (“California Flats”). On February 13, 2017, OpCo waived the 45-day negotiation period under the First Solar ROFO Agreement with respect to Switch Station and on May 15, 2017, OpCo waived the 45-day negotiation period under the First Solar ROFO Agreement with respect to Cuyama and California Flats; following such waivers, First Solar had the right to offer and sell Switch Station, Cuyama, and California Flats to a third party, in accordance with the terms of the First Solar ROFO Agreement. On July 13, 2017, August 17, 2017, and August 22, 2017, First Solar sold the interests subject to the First Solar ROFO Agreement in Switch Station, Cuyama, and California Flats, respectively, to third parties, eliminating OpCo's ability to acquire such interests or any related assets. In addition, with First Solar's sale of such interests in Switch Station, Cuyama, and California Flats, no further projects remain subject to the First Solar ROFO Agreement.

SunPower ROFO Agreement

On February 13, 2017, OpCo entered into the Second Amendment and Waiver to Right of First Offer Agreement (the “Waiver”) with SunPower. Pursuant to SunPower ROFO Agreement, SunPower previously granted to OpCo a right of first offer to purchase certain solar energy generating facilities for a period of 5 years. Such solar projects included the 100 MW El Pelicano solar generation project in Chile (“El Pelicano”) and the Boulder Solar 1 solar generation project in Nevada ("Boulder Solar"). Pursuant to the Waiver, OpCo waived its rights under the ROFO Agreement with respect to El Pelicano. The Waiver also contains customary representations, warranties and agreements of OpCo and SunPower. On August 11, 2017, OpCo waived the 45-day negotiation period under the SunPower ROFO Agreement with respect to Boulder Solar; following such waiver, SunPower has the right to offer and sell Boulder Solar to a third party, in accordance with the terms of the SunPower ROFO Agreement.


30

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

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 (unless terminated earlier pursuant to its terms).

FirstEnergy Solutions Corp. (“FirstEnergy”), the Partnership’s offtake counterparty with respect to the Maryland Solar Project, had its credit rating downgraded multiple times in 2016 and 2017. As of August 14, 2017, the credit rating of FirstEnergy was Caa1 and CCC- by Moody’s Investors Service and Standard & Poor’s Ratings Services, respectively, both of which are below investment grade. In addition, Standard & Poor’s Ratings Services placed FirstEnergy on CreditWatch with negative implications, based on a $1.51 billion pretax impairment charge that the company’s competitive business will incur from the deactivation of several coal units. In November 2016, FirstEnergy Corp., the parent of FirstEnergy, announced a strategic review of its competitive business, pursuant to which the company would seek to move away from competitive markets. FirstEnergy’s annual report on Form 10-K for the year ended December 31, 2016 reported a substantial uncertainty as to their ability to continue as a going concern.

As further described in Part III, Item 13. “Certain Relationships and Related Transactions, and Director Independence—Agreements with our Sponsors—Maryland Solar Lease Arrangement” in the 2016 10-K, First Solar’s affiliate is obligated under the Maryland Solar lease arrangement to pay a fixed amount of rent that is set based on the expected operations of the plant. Such lease agreement will terminate upon any termination of the PPA for the Maryland Solar Project or the site ground lease. Pursuant to the PPA for the Maryland Solar Project, a FirstEnergy bankruptcy would be an event of default under the PPA, permitting (subject to applicable law) the termination of the PPA although FirstEnergy may choose to renegotiate or maintain the PPA in its current form. Upon any such early termination of the lease agreement, First Solar’s affiliate is obligated to return the facility in its then-current condition and location to the Partnership, without any warranties, and no rent shall thereafter be payable by such First Solar affiliate. In the event that the PPA was terminated and First Solar were to subsequently terminate the Maryland Solar Lease Agreement, the Maryland Solar Project would have no agreement through which to sell the energy that it produces, which equates to approximately $8.0 million in annual revenue, and the Partnership can enter into a replacement offtake agreement with a different counterparty. As of August 31, 2017, FirstEnergy is current with respect to the payments due under the PPA for the Maryland Solar Project.

The Partnership evaluates its long-lived assets, including property and equipment and projects, for impairment whenever events or changes in circumstances indicate the carrying value of such assets may not be recoverable. In consideration of the above events, the Partnership evaluated whether the carrying value of the project may no longer be recoverable using a probability-weighted assessment of potential outcomes and related undiscounted cash flows. As a result of such evaluation, the Partnership concluded the estimated future undiscounted net cash flows expected to be generated by the project over its estimated useful life exceeded the $52.0 million carrying value of the Maryland Solar Project's property and equipment as of August 31, 2017. Such assessment is subject to significant uncertainty and could change significantly as facts and circumstances change. In the event that the PPA for the Maryland Solar Project was terminated, if the Partnership is unable to enter into a replacement agreement or sell the energy it produces under similar terms, the carrying value of the project may not be recoverable, and the Partnership could record a material impairment loss in the amount by which the carrying value exceeds the fair value.

Note 13. Income Taxes

The provision for income taxes differed from the amount computed by applying the statutory U.S. federal rate of 35% primarily due to the tax impact of equity in earnings, the tax impact of noncontrolling interest, and state tax rates (net of federal benefit) in various jurisdictions, most significantly California.

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, since the 2017 financial reporting year is December 1, 2016 through November 30, 2017, the taxable income (loss) included in the 2017 tax provision is for the tax year ended December 31, 2016. The provision accrued at the financial reporting year-end will be a discrete period computation, and the tax credits and permanent differences recognized in that accrual will be those generated between the tax year-end date and the financial reporting year-end date. With the exception of minimum state income and franchise tax payments, any amounts recorded for income tax provision (benefit) represent deferred income taxes being provided on the net income before taxes of OpCo, a non-taxable partnership, which is allocated to the Partnership.

Although organized as a limited partnership under state law, the Partnership elected to be treated as a corporation for U.S. federal income tax purposes. Accordingly, the Partnership is subject to U.S. federal income taxes at regular corporate rates

31

8point3 Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements — Continued

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. 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 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 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 14. Segment Information

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

Long-lived assets consisting of property and equipment, net, were located in the United States. All operating revenues for each of the three and nine months ended August 31, 2017 and August 31, 2016 were from customers located in the United States. The following customers each comprised 10% or more of the its total revenue for each of the three and nine months ended August 31, 2017 and August 31, 2016, respectively:
 
Three Months Ended
 
Nine Months Ended
Customers
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Southern California Edison
60.2
%
 
63.6
%
 
49.3
%
 
56.6
%
Southern California Public Power Authority
*

 
*

 
10.9
%
 
*

 
*
Total revenue attributable to these customers was less than 10% of the Partnership's total revenue for the period.

Note 15. Subsequent Events
 
Distributions

On September 22, 2017, the general partner’s board of directors declared a cash distribution for our Class A shares of $0.2721 per share for the third quarter of 2017. The general partner’s board of directors declared a corresponding cash distribution for OpCo’s common and subordinated units, which includes all common and subordinated units held by First Solar and SunPower. The third quarter distribution will be paid on October 13, 2017 to shareholders and unitholders of record as of October 3, 2017.

Termination of Kern Purchase Agreement

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

32



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 and the notes thereto included elsewhere in this Quarterly Report on Form 10-Q and our 2016 10-K.
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 and contain projections of results of operations or of financial condition or forecasts of future events. Words such as “could,” “will,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential” or “continue” and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this report include statements concerning our Sponsors’ ownership interest in us, our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and 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 the 2016 10-K. Those risk factors and other factors noted throughout this report and in the 2016 10-K 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 2016 10-K to be a complete statement of all potential risks and uncertainties. Please read “Risk Factors” in Part II, Item 1A. of this Quarterly Report on Form 10-Q and in Part I, Item 1A. of the 2016 10-K.
Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to publicly update or revise any forward-looking statements except as required by law.

Overview

Description of Partnership

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

Our Portfolio

As of August 31, 2017, our Portfolio consisted of interests in 946 MW of solar energy projects. As of August 31, 2017, we owned interests in ten utility-scale solar energy projects, all of which are operational. These assets represent 92% of the generating capacity of our Portfolio. As of August 31, 2017, we owned interests in four C&I solar energy projects, three of which were operational and one of which was in late-stage construction, and a portfolio of residential DG Solar assets, which represent 8% of the generating capacity of our Portfolio. Our Portfolio is located entirely in the United States and consists of utility-scale and C&I assets that sell substantially all of their output under long-term, fixed-price offtake agreements primarily 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, 2017, the weighted average remaining life of offtake agreements across our Portfolio was 19.4 years.

For an overview of the assets that comprise our Portfolio as of August 31, 2017, please read Part I, Item 1. “Financial Information—Notes to Unaudited Condensed Consolidated Financial Statements—Note 1— Description of Business.”

How We Generate Revenues

Under our Utility Project Entities’ offtake agreements, each Utility Project Entity generally receives a fixed price over the term of the offtake agreement with respect to 100% of its output, subject to certain adjustments. Our Utility Project Entities’ offtake agreements have certain availability or production requirements, and if such requirements are not met, then in some cases the applicable project is required to pay the offtake counterparty a specified damages amount, and in some cases the

33


offtake counterparty has the right to terminate the offtake agreement or reduce the contract quantity. In addition, under our Utility Project Entities’ offtake agreements, each party typically has the right to terminate upon written notice ranging from ten to 60 days following the occurrence of an event of default that has not been cured within the applicable cure period, if any.

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

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

How We Evaluate Our Operations

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

Adjusted EBITDA.

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

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

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

Cash Available for Distribution.

We use cash available for distribution, which we define as Adjusted EBITDA less equity in earnings of unconsolidated affiliates, cash interest paid, cash income taxes paid, maintenance capital expenditures, cash distributions to noncontrolling

34


interests and principal amortization payments on any project-level indebtedness plus cash distributions from unconsolidated affiliates, indemnity payments and promissory notes from Sponsors, test electricity generation, cash proceeds from sales-type residential leases, state and local rebates and cash proceeds for reimbursable network upgrade costs. Our cash flow is generated from distributions we receive from OpCo each quarter. OpCo’s cash flow is generated primarily from distributions from the Project Entities. As a result, our ability to make distributions to our Class A shareholders depends primarily on the ability of the Project Entities to make cash distributions to OpCo and the ability of OpCo to make cash distributions to its unitholders.

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

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 or any other performance measure determined in accordance with U.S. GAAP, nor is it indicative of funds available to fund our cash needs. In addition, our calculations of cash available for distribution are not necessarily comparable to cash available for distribution as calculated by other companies. Investors should not rely on these measures as a substitute for any U.S. GAAP measure, including net income.

The following table presents a reconciliation of net income to Adjusted EBITDA and cash available for distribution for the three and nine months ended August 31, 2017 and August 31, 2016:
 
Three Months Ended
 
Nine Months Ended
(in thousands)
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Net income
$
28,662

 
$
15,874

 
$
30,485

 
$
8,660

Add (Less):
 
 

 

 

Interest expense, net of interest income
5,756

 
2,903

 
16,560

 
8,206

Income tax provision
5,012

 
5,063

 
7,860

 
15,281

Depreciation, amortization and accretion
7,327

 
6,311

 
21,198

 
16,325

Share-based compensation
56

 
56

 
168

 
168

Acquisition-related transaction costs (1)
19

 
599

 
50

 
2,261

Unrealized gain (loss) on derivatives (2)
284

 
(285
)
 
(349
)
 
(536
)
Add proportionate share from equity method
investments (3)
 
 


 
 
 

Interest expense, net of interest income
141

 
(54
)
 
440

 
(149
)
Depreciation, amortization and accretion
6,224

 
2,397

 
18,672

 
7,683

Adjusted EBITDA
$
53,481

 
$
32,864

 
$
95,084

 
$
57,899

Less:
 
 

 
 
 

Equity in earnings of unconsolidated affiliates, net with (3) above (4)
(29,687
)
 
(10,418
)
 
(52,399
)
 
(21,038
)
Cash interest paid (5)
(5,930
)
 
(3,278
)
 
(16,357
)
 
(9,176
)
Cash distributions to non-controlling interests
(2,599
)
 
(2,826
)
 
(6,760
)
 
(3,730
)
Maintenance capital expenditures
(177
)
 

 
(177
)
 

Short-term note (6)

 

 
(1,964
)
 

Add:
 
 


 
 
 


Cash distributions from unconsolidated affiliates (7)
17,169

 
7,018

 
46,467

 
16,075

Indemnity payment from Sponsors (8)
41

 
64

 
133

 
10,037

State and local rebates (9)

 

 

 
299

Cash proceeds from sales-type residential leases (10)
746

 
630

 
2,112

 
1,901

Test electricity generation (11)
1

 

 
33

 
421

Cash proceeds for reimbursable network upgrade costs (12)
125

 

 
7,878

 

Cash available for distribution
$
33,170

 
$
24,054

 
$
74,050

 
$
52,688


35


 
(1)
Represents acquisition-related financial advisory, legal and accounting fees associated with ROFO Project interests purchased and expected to be purchased by us in the future.
(2)
Represents the changes in fair value of interest rate swaps that were not designated as cash flow hedges.
(3)
Represents our proportionate share of net interest expense, depreciation, amortization and accretion from our unconsolidated affiliates that are accounted for under the equity method.
(4)
Equity in earnings of unconsolidated affiliates represents the earnings from the Solar Gen 2 Project, the North Star Project, the Lost Hills Blackwell Project, the Henrietta Project, and the Stateline Project and is included on our unaudited condensed consolidated statements of operations.
(5)
Represents cash interest payments related to OpCo’s senior secured credit facility and the Stateline Promissory Note.
(6)
Represents repayment of promissory note to First Solar.
(7)
Cash distributions from unconsolidated affiliates represent the cash received by OpCo with respect to its 49% interest in the Solar Gen 2 Project, the North Star Project, the Lost Hills Blackwell Project, the Henrietta Project, and its 34% interest in the Stateline Project.
(8)
Represents indemnity payments from the Sponsors owed to OpCo in accordance with the Omnibus Agreement. Please read Part I, Item 1. “Financial Information—Notes to Unaudited Condensed Consolidated Financial Statements—Note 12—Related Parties.”
(9)
State and local rebates represent cash received from state or local governments for owning certain solar power systems. The receipt of state and local rebates is accounted for as a reduction in the asset carrying value rather than operating revenue.
(10)
Cash proceeds from sales-type residential leases, net, represent gross rental cash receipts for sales-type leases, less sales-type revenue and lease interest income that is already reflected in net income during the period. The corresponding revenue for such leases was recognized in the period in which such lease was placed in service, rather than in the period in which the rental payment was received, due to the characterization of these leases under U.S. GAAP.
(11)
For the three and nine months ended August 31, 2017, test electricity generation represents the sale of electricity that was generated prior to COD by the Macy’s Maryland Project. For the nine months ended August 31, 2016, test electricity generation represents the sale of electricity that was generated prior to COD by the Kingbird Project. Solar systems may begin generating electricity prior to COD as a result of the installation and interconnection of individual solar modules, which occurs over time during the construction and commission period. The sale of test electricity generation is accounted for as a reduction in the asset carrying value rather than operating revenue prior to COD, even though it generates cash for the related Project Entity.
(12)
Cash proceeds from a utility company related to reimbursable network upgrade costs associated with the Quinto Project and the Kingbird Project.

Significant Factors and Trends Affecting Our Business

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

Power Purchase Agreements

Our revenues are a function of the volume of electricity generated and sold by our projects and rental payments under lease agreements. The assets in our Portfolio sell substantially all of their output or are leased under long-term, fixed price offtake agreements primarily with investment grade utility-scale and C&I offtakers, as well as high credit quality residential customers with an average FICO score of 765 at the time of initial contract. As of August 31, 2017, the weighted average remaining life of offtake agreements across our Portfolio was 19.4 years, with the offtake agreements of our Utility Project Entities having remaining terms ranging from 15.6 to 26.3 years and our C&I offtake agreements and residential offtake agreements having remaining terms ranging from 15.0 to 19.5 years. We believe long-term agreements with creditworthy customers substantially mitigate volatility in our cash flows. As of August 31, 2017, two offtake counterparties were placed on CreditWatch by Standard & Poor’s Ratings Services, increasing our credit risk associated with these customers. Please read Part II, Item 1A. “Risk Factors—Risks Related to Our Project Agreements—We rely on a limited number of offtake counterparties and we are exposed to the risk that they are unwilling or unable to fulfill their contractual obligations to us or that they otherwise terminate their offtake agreements with us” and Part I, Item 1. “Financial Information—Notes to Unaudited Condensed Consolidated Financial Statements—Note 12—Related Parties—Maryland Solar Lease Arrangement.”


36


Operation of Projects

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

Future Acquisitions

Our ability to grow our business and increase our quarterly cash distributions could be impacted by a number of factors and trends that affect our industry generally, including the development of any ROFO Projects we may acquire in the future. Our ability to acquire ROFO Projects is dependent on our ability to agree on terms with our Sponsors, our ability to borrow additional funds and access capital markets, our Sponsors’ ability to complete the development of the ROFO Projects and our Sponsors’ decision to sell the ROFO Projects they develop. We and our Sponsors have agreed in the past to make several adjustments to our ROFO Portfolio. We may in the future continue working with our Sponsors to make adjustments to our ROFO Portfolio, including to remove, or waive the negotiation obligations for, projects that we do not intend to acquire at the time our Sponsors plan to offer them. Such removals or waivers are subject to the approval of the board of directors of our General Partner and/or the board’s conflicts committee. The removal of any projects from the ROFO Portfolio or the waiver of the negotiation obligations with respect to any projects would reduce the likelihood that we would acquire such projects. In addition, with First Solar’s sale of the interests in the Switch Station project, the Cuyama project and the California Flats project, no further projects remain subject to the First Solar ROFO Agreement.

In addition, the development of solar energy projects by project developers, including our Sponsors, may be delayed or otherwise adversely affected by the outcome of the petition filed by Suniva, Inc., a U.S.-based manufacturer of solar cells, in April 2017, with the U.S. International Trade Commission (“USITC”) under Section 201 of the Trade Act of 1974 (the “Section 201 Petition”). The Section 201 Petition seeks various remedies including tariffs and restrictions on foreign-manufactured crystalline silicon PV cells and modules imported into the United States. On September 22, 2017, the USITC determined such products are being imported into the United States in such increased quantities as to be a substantial cause of serious injury to the relevant domestic industry. The USITC will now proceed to the remedy phase of its investigation. The uncertainty surrounding the potential outcome of the Section 201 Petition may cause market volatility, price fluctuations, supply shortages and project delays, adversely affecting our ability to acquire such projects.

Please read Part II, Item 1A. “Risk Factors—SunPower's failure to complete the development of the SunPower ROFO Projects or project developers’, including our Sponsors’, failure to develop other solar energy projects, including those opportunities that are part of our Sponsors’ development pipeline, could have a significant effect on our ability to grow.”

Demand for Solar Energy

United States energy demand is increasing due to economic development and population growth. The U.S. Energy Information Administration’s January 2017 Annual Energy Outlook projects consumption of renewable energy to increase the fastest of all energy sectors through 2040, on a percentage basis, with solar capacity representing 50% of new capacity additions after 2030, coupled with continued retirements of older, less efficient, fossil fuel producing units in response to the Clean Power Plan, availability of federal tax credits for renewable electricity generation and capacity during the early years of the projection, and state renewable portfolio standard programs. 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. 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. However, the demand for solar energy could change at any time, especially as a result of a decline in commodity prices, including the price of natural gas, or a change in the federal, state, or local policies regulating natural gas, coal, oil and other fossil fuels, which could lower prices for fuel sources used to produce energy from other technologies and reduce the demand for solar energy. For more information about the risks associated with changing demand for solar energy, please read Part I, Item 1A. “Risk Factors—If solar energy technology is not suitable for widespread adoption at economically attractive rates of return, or if sufficient additional demand for solar power systems does not develop or takes longer to develop than we anticipate, our ability to acquire accretive projects may decrease” in the 2016 10-K.


37


Government Incentives

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

The current administration’s proposed environmental and tax policies may create regulatory uncertainty in the clean energy sector, including the solar energy sector, and may lead to a reduction or removal of various clean energy programs and initiatives designed to curtail climate change. For more information about the risks associated with these government incentives, please read Part I, Item 1A. “Risk Factors—Government regulations providing incentives and subsidies for solar energy could change at any time, including pursuant to the proposed environmental and tax policies of the current administration, and such changes may negatively impact our growth strategy” in the 2016 10-K.

The projects in our Portfolio are generally unaffected by the trends discussed above, given that all of the electricity to be generated by our projects are sold under fixed-price offtake agreements, which, as of August 31, 2017, have a weighted average remaining life of approximately 19.4 years. In addition, our near-term growth strategy is also largely insulated from the trends discussed above. We expect that most of our short-term growth will come from opportunities to acquire the ROFO Projects, all of which will have executed power sale agreements at the time of any acquisition by us.

Critical Accounting Policies & Estimates

We prepare our unaudited condensed consolidated financial statements in conformity with U.S. generally accepted accounting principles, which requires management to make estimates and assumptions that affect the amounts of assets, liabilities, revenues, and expenses recorded in our financial statements. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions and conditions. In addition to our most critical estimates discussed below, we also have other key accounting policies that are less subjective and, therefore, judgments involved in their application would not have a material impact on our reported results of operations. Please read Part II, Item 8. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 2—Summary of Significant Accounting Policies” of the 2016 10-K. There have been no significant changes to our critical accounting policies and estimates since November 30, 2016.


38


Results of Operations
 
Three Months Ended
 
Nine Months Ended
 
(unaudited)
 
(unaudited)
 
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Revenues:


 


 
 

 
 

Operating revenues
$
27,744

 
$
26,116

 
$
54,319

 
$
46,735

Total revenues
27,744

 
26,116

 
54,319

 
46,735

Operating costs and expenses:


 


 


 


Cost of operations
2,064

 
1,928

 
6,396

 
4,953

Selling, general and administrative
2,050

 
1,804

 
5,894

 
5,096

Depreciation and accretion
7,220

 
6,311

 
20,875

 
16,325

Acquisition-related transaction costs
19

 
599

 
50

 
2,261

Total operating costs and expenses
11,353

 
10,642

 
33,215

 
28,635

Operating income
16,391

 
15,474

 
21,104

 
18,100

Other expense (income):


 


 


 


Interest expense
6,060

 
3,199

 
17,429

 
9,123

Interest income
(304
)
 
(296
)
 
(869
)
 
(909
)
Other expense (income)
283

 
(291
)
 
(514
)
 
(551
)
Total other expense, net
6,039

 
2,612

 
16,046

 
7,663

Income before income taxes and equity in earnings of unconsolidated investees
10,352

 
12,862

 
5,058

 
10,437

Income tax provision
(5,012
)
 
(5,063
)
 
(7,860
)
 
(15,281
)
Equity in earnings of unconsolidated investees
23,322

 
8,075

 
33,287

 
13,504

Net income
28,662

 
15,874

 
30,485

 
8,660

Less: Net income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests
21,189

 
8,281

 
18,765

 
(14,263
)
Net income attributable to 8point3 Energy Partners LP Class A shares
$
7,473

 
$
7,593

 
$
11,720

 
$
22,923

 
Three and Nine Months Ended August 31, 2017 Compared to Three and Nine Months Ended August 31, 2016

Revenues 
 
Three Months Ended
 
Nine Months Ended
 
(unaudited)
 
(unaudited)
(in thousands)
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Operating revenues
$
27,744

 
$
26,116

 
$
54,319

 
$
46,735

Total revenues
$
27,744

 
$
26,116

 
$
54,319

 
$
46,735

 
Over 90% of our operating revenues for both the three and nine months ended August 31, 2017 and August 31, 2016, were comprised of lease revenue from our utility-scale assets, C&I assets and Residential Portfolio. The Partnership’s only revenue streams not from the leasing of solar power systems are from the PPA and SREC Sales Agreement entered into by the Macy's Maryland Project Entity and contracted counterparties. All revenues for the periods presented were generated in the United States.

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 were placed into service prior to fiscal 2015, all revenue related to the NPV of the minimum lease payments for sales-type leases has been recognized as of December 28, 2014. Accordingly, other than interest revenue, we had no sales-type lease revenue on our unaudited condensed consolidated financial statements for the three and nine months ended August 31, 2017 and August 31, 2016.

For those residential leases classified as sales-type leases, the NPV 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 NPV is inclusive of

39


certain fixed and determinable state or local rebates 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 power 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 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.

Total revenues increased by $1.6 million, or 6%, for the three months ended August 31, 2017 as compared to the three months ended August 31, 2016, and increased by $7.6 million, or 16%, for the nine months ended August 31, 2017 as compared to the nine months ended August 31, 2016, due to (i) revenue generated from the Macy’s Maryland Project, the Kern Phase 1(b) Assets, the Kern Phase 2(a) Assets and Kern 2(b) Assets, which commenced operations subsequent to the third quarter of fiscal 2016, and the Kingbird Project, which commenced operations during the second quarter of fiscal 2016, and (ii) net revenue recognized under the SREC Sales Agreement.

Operating Costs and Expenses
 
Three Months Ended
 
Nine Months Ended
 
(unaudited)
 
(unaudited)
(in thousands)
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Cost of operations
$
2,064

 
$
1,928

 
$
6,396

 
$
4,953

Selling, general and administrative
2,050

 
1,804

 
5,894

 
5,096

Depreciation and accretion
7,220

 
6,311

 
20,875

 
16,325

Acquisition-related transaction costs
19

 
599

 
50

 
2,261

Total operating costs and expenses
$
11,353

 
$
10,642

 
$
33,215

 
$
28,635

Total operating costs and expenses as a percentage of revenues
40.9
%
 
40.7
%
 
61.1
%
 
61.3
%
 
Cost of Operations: Cost of operations primarily includes expenses related to O&M agreements and land lease expenses. The increase of $0.1 million, or 7%, for the three months ended August 31, 2017 as compared to the three months ended August 31, 2016, and the increase of $1.4 million, or 29%, for the nine months ended August 31, 2017 as compared to the nine months ended August 31, 2016, was primarily driven by (i) increased expenses associated with operating the solar power systems due to the Macy's Maryland Project, the Kern Phase 1(b) Assets, the Kern Phase 2(a) Assets, and Kern 2(b) Assets, which commenced operations subsequent to the third quarter of fiscal 2016, and the Kingbird Project, which commenced operations during the second quarter of fiscal 2016, and (ii) costs associated with the sale and delivery of SRECs.

Selling, General and Administrative: SG&A expense primarily includes operating expenses such as audit, legal, insurance, independent board of directors services and fees under the AMAs and MSAs with our Sponsors. The increase of $0.2 million, or 14%, for the three months ended August 31, 2017 as compared to the three months ended August 31, 2016, and the increase of $0.8 million, or 16%, for the nine months ended August 31, 2017 as compared to the nine months ended August 31, 2016, was primarily driven by additional expenses associated with operating the solar power systems for the Macy's Maryland Project, the Kern Phase 1(b) Assets, the Kern Phase 2(a) Assets, and Kern 2(b) Assets, which commenced operations subsequent to the third quarter of fiscal 2016.

Depreciation and Accretion: Depreciation expense reflects costs associated with depreciation of our solar power system assets that have been placed in service. The increase of $0.9 million, or 14% for the three months ended August 31, 2017 as compared to the three months ended August 31, 2016, and the increase of $4.6 million, or 28%, for the nine months ended August 31, 2017 as compared to the nine months ended August 31, 2016, was primarily driven by the commencement of operations, and related depreciation, of the Macy’s Maryland Project, the Kern Phase 1(b) Asset, and the Kern Phase 2(a) Assets, and Kern 2(b) Assets, which commenced operations subsequent to the third quarter of fiscal 2016.

Acquisition-related Transaction Costs: Acquisition-related transactions costs represent legal and consulting fees incurred in connection with the acquisitions. The decrease of $0.6 million, or 97%, for the three months ended August 31, 2017

40


as compared to the three months ended August 31, 2016, and the decrease of $2.2 million, or 98%, for the nine months ended August 31, 2017 as compared to the nine months ended August 31, 2016, was primarily driven by the fees incurred in connection with the Kern Phase 1(a) Acquisition in January 2016, the Kingbird Acquisition in March 2016, the Hooper Acquisition in April 2016, and the Macy's Maryland Acquisition in July 2016. Transaction costs associated with acquiring the Kern Project Entity were primarily incurred by the Partnership in connection with the initial phase of the acquisition which occurred in the first half of fiscal 2016.

Other Expense, net
 
Three Months Ended
 
Nine Months Ended
 
(unaudited)
 
(unaudited)
(in thousands)
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Interest expense
$
6,060

 
$
3,199

 
$
17,429

 
$
9,123

Interest income
(304
)
 
(296
)
 
(869
)
 
(909
)
Other expense (income)
283

 
(291
)
 
(514
)
 
(551
)
Total other expense, net
$
6,039

 
$
2,612

 
$
16,046

 
$
7,663

Total other expense, net as a percentage of revenues
21.8
%
 
10.0
%
 
29.5
%
 
16.4
%
 
Interest Expense: Cash interest expense for the three and nine months ended August 31, 2017 relates to fees associated with outstanding borrowings under OpCo’s senior secured credit facility and the Stateline Promissory Note. Cash interest expense for the three and nine months ended August 31, 2016 relates to fees associated with outstanding borrowings under OpCo’s senior secured credit facility. Non-cash interest expense for the three and nine months ended August 31, 2017 and August 31, 2016 relates to debt issuance costs associated with OpCo’s senior secured credit facility. Please read Part I, Item 1. “Financial Information—Notes to Unaudited Condensed Consolidated Financial Statements—Note 7—Debt and Financing Obligations” for rates and borrowing activity. The interest incurred related to our projects that are under construction is not reflected as an expense in the unaudited condensed consolidated statements of operations, as it is capitalized to construction-in-progress until the solar power system is ready for its intended use.

Interest expense for the three and nine months ended August 31, 2017 included non-cash interest expense of $0.3 million and $0.7 million, respectively, and cash interest expense of $5.8 million and $16.7 million, respectively. Interest expense for the three and nine months ended August 31, 2016 included non-cash interest expense of $0.1 million and $0.4 million, respectively, and cash interest expense of $3.1 million and $8.7 million, respectively. 

Non-cash interest expense increased $0.2 million for the three months ended August 31, 2017 as compared to the three months ended August 31, 2016, and increased $0.3 million for the nine months ended August 31, 2017 as compared to the nine months ended August 31, 2016, primarily due to the debt issuance costs associated with the drawdown of our $250.0 million incremental term loan facility and additional drawdowns under our $200.0 million revolving credit facility. Cash interest expense increased $2.7 million, or 90%, for the three months ended August 31, 2017 as compared to the three months ended August 31, 2016, and increased $8.0 million, or 92%, for the nine months ended August 31, 2017 as compared to the nine months ended August 31, 2016, primarily due the Stateline Promissory Note issued on December 1, 2016, as well as fees associated with the drawdown of our $250.0 million incremental term loan facility and additional drawdowns under our revolving credit facility.

Interest Income: Interest income represents the accrued interest on reimbursable network upgrade costs related to the Quinto Project and the Kingbird Project. These costs plus accrued interest are reimbursable by the applicable utility company over five years from when the project achieves commercial operation. Interest income was $0.3 million for both the three months ended August 31, 2017 and August 31, 2016, respectively, and $0.9 million for both the nine months ended August 31, 2017 and August 31, 2016, respectively.

Other Expense (Income): Other expense for the three months ended August 31, 2017 of $0.3 million relates to the unrealized loss related to the mark-to-market valuation adjustment of interest rate swaps associated with our term loan facility. Other income for the nine months ended August 31, 2017 of $0.5 million relates to (i) a $0.3 million unrealized gain related to the mark-to-market valuation adjustment of interest rate swaps associated with our term loan facility, and (ii) $0.2 million of payments received under the Partnership’s O&M agreement with First Solar associated with performance of certain projects. Other income in the three and nine months ended August 31, 2016 primarily relates to an unrealized gain on interest rate swap associated with our term loan facility of $0.3 million and $0.5 million, respectively. We enter 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

41


expense (income), net in the unaudited condensed consolidated statement of operations as these hedges are not accounted for under hedge accounting.

Income Tax Provision
 
Three Months Ended
 
Nine Months Ended
 
(unaudited)
 
(unaudited)
(in thousands)
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Income tax provision
$
5,012

 
$
5,063

 
$
7,860

 
$
15,281

Income tax provision as a percentage of revenues
18.1
%
 
19.4
%
 
14.5
%
 
32.7
%

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

Our income tax provision primarily represents deferred federal and state taxes on the net income of OpCo, a non-taxable partnership, that is allocated to the Partnership (exclusive of income tax but after noncontrolling interest).

The decrease in income tax provision as a percentage of revenues for the three months ended August 31, 2017 of 18.1% compared to 19.4% for the three months ended August 31, 2016 is the result of (i) an increase in equity in earnings of unconsolidated affiliates, and (ii) lower income before income taxes for the three months ended August 31, 2017 of $10.4 million compared to income before income taxes of $12.9 million for the three months ended August 31, 2016.

The decrease in income tax provision as a percentage of revenues for the nine months ended August 31, 2017 of 14.5% compared to 32.7% for the nine months ended August 31, 2016 is the result of (i) an increase in equity in earnings of unconsolidated affiliates, and (ii) lower income before income taxes for the nine months ended August 31, 2017 of $5.1 million compared to income before income taxes of $10.4 million for the nine months ended August 31, 2016.

Equity in Earnings of Unconsolidated Investees
 
Three Months Ended
 
Nine Months Ended
 
(unaudited)
 
(unaudited)
(in thousands)
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Equity in earnings of unconsolidated investees
$
23,322

 
$
8,075

 
$
33,287

 
$
13,504

Equity in earnings of unconsolidated investees as a percentage of revenues
84.1
%
 
30.9
%
 
61.3
%
 
28.9
%
 
Equity in earnings of unconsolidated investees represents our proportionate share of the earnings and losses from our minority membership interests accounted for as equity method investments, including SG2 Holdings, North Star Holdings, Lost Hills Blackwell Holdings, Henrietta Holdings and Stateline Holdings. We own a 49% ownership interest in each of SG2 Holdings, North Star Holdings, Lost Hills Blackwell Holdings and Henrietta Holdings, and a 34% ownership interest in Stateline Holdings. Henrietta Holdings and Stateline Holdings were acquired subsequent to the third quarter of fiscal 2016.

Net Income (loss) Attributable to Noncontrolling Interests and Redeemable Noncontrolling Interests
 
Three Months Ended
 
Nine Months Ended
 
(unaudited)
 
(unaudited)
(in thousands)
August 31, 2017
 
August 31, 2016
 
August 31, 2017
 
August 31, 2016
Net income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests
$
21,189

 
$
8,281

 
$
18,765

 
$
(14,263
)
Net income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests as a percentage of net revenues
76.4
%
 
31.7
%
 
34.5
%
 
(30.5
)%
 
We apply the HLBV Method in allocating recorded net income (loss) to each tax equity investor based on the change during the reporting period of the amount of net assets of the entity to which each tax equity investor would be entitled to under

42


the governing contractual arrangements in a liquidation scenario. If the redemption value of our redeemable noncontrolling interests exceeds their carrying value after attribution of income (loss) under the HLBV Method in any period, we will make an additional attribution of income to our redeemable noncontrolling interests such that their carrying value will at least equal the redemption value.

Net income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests for the three and nine months ended August 31, 2017 included a net loss of $1.6 million and $17.1 million, respectively, attributable to noncontrolling interests and redeemable noncontrolling interests related to our tax equity financing facilities with third-party investors under which the parties invest in entities that hold the solar power systems, partially offset by net income of $22.8 million and $35.9 million, respectively, attributable to our Sponsors as a result of their economic ownership in OpCo. Net income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests for the three and nine months ended August 31, 2016 included a net loss of $24.3 million and $112.1 million, respectively, attributable to noncontrolling interests and redeemable noncontrolling interests related to our tax equity financing facilities with third-party investors under which the parties invest in entities that hold the solar power systems, offset by net income of $32.6 million and $97.9 million, respectively, attributable to our Sponsors as a result of their economic ownership in OpCo.

Cash Flows

Nine Months Ended August 31, 2017 Compared to Nine Months Ended August 31, 2016

A summary of the sources and uses of cash and cash equivalents is as follows:
 
Nine Months Ended
 
(unaudited)
(in thousands)
August 31, 2017
 
August 31, 2016
Net cash provided by operating activities
$
64,259

 
$
37,821

Net cash used in investing activities
(299,922
)
 
(122,258
)
Net cash provided by financing activities
231,763

 
57,546


Operating Activities

Net cash provided by operating activities for the nine months ended August 31, 2017 was $64.3 million and was primarily the result of: (i) net income of $30.5 million; (ii) $32.9 million in cash distributions received from equity method investees that were classified in operating activities as returns on the investments; (iii) adjustment for non-cash charges of $30.0 million, including $21.2 million depreciation of operating lease assets and solar power systems and amortization of intangible assets, $7.9 million deferred income taxes, $0.7 million amortization of debt issuance costs, and $0.2 million share-based compensation; (iv) $6.2 million decrease in prepaid expenses and other current assets; (v) $0.7 million increase in accounts payable and other accrued liabilities, and (vi) $0.5 million decrease in deferred revenue on operating leases. These inflows were partially offset by: (i) $2.8 million increase in accounts receivable and financing receivable, net; and (ii) adjustments for non-cash income of $33.6 million, including $33.3 million equity in earnings of unconsolidated investees and $0.3 million mark-to-market gain on interest rate swaps.

Net cash provided by operating activities for the nine months ended August 31, 2016 was $37.8 million and was primarily the result of: (i) $15.1 million in cash distributions received from equity method investees that were classified in operating activities as returns on the investments; (ii) net income of $8.7 million; (iii) adjustments for non-cash charges of $32.5 million, including $16.3 million depreciation of operating lease assets and solar power systems, $15.3 million deferred income taxes expense, $0.2 million share-based compensation, $0.4 million amortization of debt issuance costs, and $0.3 million bad debt expense related to residential lease customers; (iv) $0.8 million increase in accounts payable and other accrued liabilities; and (v) $0.5 million increase in deferred revenue from the Maryland Solar Project. These inflows were partially offset by: (i) adjustments for non-cash income of $14.0 million, including $13.5 million equity in earnings of unconsolidated investees and $0.5 million mark-to-market gain on interest rate swaps; (ii) $4.3 million increase in accounts receivable and short-term financing receivables, net; and (iii) $1.4 million increase in prepaid expenses and other current assets.

Investing Activities

Net cash used in investing activities for the nine months ended August 31, 2017 was $299.9 million and was primarily the result of: (i) $313.2 million net cash paid for the acquisitions of the Stateline Project, the Kern Phase 1(a) Assets, the Kern Phase 2(a) Assets, the Kern Phase 2(b) Assets, the Kern Phase 2(c) Assets, and the Macy’s Maryland Project; (ii) capital

43


expenditures of $0.3 million, which were due to the purchases of property and equipment associated with the Kingbird Project. These outflows were offset by $13.6 million in distributions from unconsolidated investees classified in investing activities as returns of the investments.

Net cash used in investing activities for the nine months ended August 31, 2016 was $122.3 million and was primarily the result of $124.3 million net cash paid for the acquisitions of the Kern Phase 1(a) Assets, the Kingbird Project, the Hooper Project and the Macy’s Maryland Project. These outflows were partially offset by $0.6 million of cash distributions from unconsolidated investees classified in investing activities as returns of the investments, and $1.4 million of net cash provided by purchases of property and equipment, which primarily consists of collections of test energy billings.

Financing Activities

Net cash provided by financing activities for the nine months ended August 31, 2017 was $231.8 million due to: (i) a $250.0 million draw down under the incremental term loan facility in connection with the Stateline Acquisition; (ii) a $34.0 million draw down under the revolving credit facility; and (iii) $24.4 million of cash contributions from tax equity investors. These cash inflows were partially offset by: (i) $39.3 million of cash distributions to our Sponsors as OpCo’s common and subordinated unitholders; (ii) $21.6 million of cash distributions to our Class A shareholders; (iii) $6.8 million of cash distributions to tax equity investors; (iv) $7.0 million in repayments of outstanding amounts under our revolving credit facility; and (v) the repayment of the $2.0 million Short-term Note to First Solar.

Net cash provided by financing activities for the nine months ended August 31, 2016 was $57.5 million and was primarily the result of: (i) $65.0 million proceeds from issuance of bank loans, net of issuance costs, including $40.0 million from the revolving credit facility and $25.0 million from the delayed draw term loan facility; (ii) $10.0 million in capital contributions from SunPower as an indemnity per the Amended and Restated Omnibus Agreement for a short-fall associated with reimbursable costs for the Quinto Project network upgrade; and (iii) $0.3 million of cash contributions from tax equity investors. These cash inflows were partially offset by: (i) $13.5 million of cash distributions to our Class A members; (ii) $4.1 million of cash distributions to tax equity investors; and (iii) $0.2 million of equity issuance costs.

Liquidity and Capital Resources

Our liquidity as of August 31, 2017 was $65.5 million, consisting of $10.4 million cash on hand and $55.1 million of available capacity under our five-year revolving credit facility.

Sources of Liquidity

We expect our ongoing sources of liquidity to include cash on hand, cash generated from operations (excluding cash distributions to minority investors), distributions and dividends from the operations of our equity investments, borrowings under new and existing financing arrangements (the aggregate amount of which may be lower because of our reduced ownership in projects subject to tax equity financing) and the issuance of additional equity securities as appropriate given market conditions. We may also incur debt at the project level, which may be limited by the rights of our tax equity investors and current debt covenants. We expect that these sources of funds will be adequate to provide for our short-term and long-term liquidity needs. Our ability to meet our debt service obligations and other capital requirements, including capital expenditures, as well as make acquisitions, will depend on our future operating performance which, in turn, will be subject to general economic, financial, business, competitive, legislative, regulatory and other conditions, many of which are beyond our control.

We believe that we will have sufficient borrowings available under our revolving credit facility, liquid assets and cash flows from operations to meet our financial commitments, debt service obligations, contingencies and anticipated required capital expenditures for at least the next 12 months. Additionally, we have an active shelf registration statement filed with the Securities and Exchange Commission for the issuance of additional equity securities as appropriate given market conditions.

Term Loans, Delayed Draw Term Loan, Revolving Credit Facility and Stateline Promissory Note

On June 5, 2015, OpCo entered into a $525.0 million credit facility, consisting of a $300.0 million term loan facility, a $25.0 million delayed draw term loan facility and a $200.0 million revolving credit facility. On April 6, 2016, the parties thereto amended the credit facility (i) to provide for the lenders’ consent to the Omnibus Agreement, (ii) to expand OpCo’s ability to further amend the Omnibus Agreement without lender consent in the future, subject to certain conditions, (iii) to permit certain customary restrictions on transfers of the equity interests of certain Project Entities, which are jointly owned, indirectly, by OpCo and SunPower, (iv) to supplement the Pledge and Security Agreement between the parties in light of the foregoing amendment, and (v) to make certain clarifying modifications to definitions and cross references. On September 30,

44


2016, OpCo entered into the Joinder Agreement under its existing senior secured credit facility, pursuant to which OpCo obtained a new $250.0 million incremental term loan facility, increasing the maximum borrowing capacity under the credit facility to $775.0 million.

Loans outstanding under the credit facility bear interest at either (i) a base rate, which is the highest of (x) the federal funds rate plus 0.50%, (y) the administrative agent’s prime rate and (z) one-month LIBOR, in each case, plus an applicable margin; or (ii) one-, two-, three- or six-month LIBOR plus an applicable margin. There will be no principal amortization over the term of the credit facility. The unused portion of the revolving credit facility and delayed draw term loan facility is subject to a commitment fee of 0.30% per annum. OpCo may prepay the borrowings under the term loan facility and the delayed draw term loan facility at any time.

In general, the credit facility contains representations, warranties, covenants (including financial covenants) and defaults that are customary for this type of financing; provided, however, that OpCo is permitted to pay distributions to its unitholders and we are permitted to pay distributions to our shareholders out of available cash so long as no default or event of default under the credit facility has occurred or is continuing at the time of such distribution, or would result therefrom, and OpCo is otherwise in compliance, on a pro forma basis, with the facility’s covenants requiring it to maintain its debt to cash flow ratio and debt service coverage ratio (as such financial ratios are described below). Among other things, events of defaults that could result in restrictions on our ability to make such distributions include certain failures to make payments when due under the credit facility, certain defaults under other agreements, breaches of certain covenants and representations under the credit facility, commencement of certain insolvency proceedings, the existence of certain judgments or attachments, certain orders of dissolution of loan parties, certain events relating to employee benefit plans, the occurrence of a change of control (as more fully described below), certain events relating to the effectiveness and validity of the guaranties and collateral documents in support of the credit facility (as described below) and other credit documents and, under certain circumstances, the termination of the Omnibus Agreement or the Quinto PPA. In the future, we may increase our debt to fund our operations or future acquisitions.

OpCo’s credit facility also contains covenants requiring us to maintain the following financial ratios: (i) a debt to cash flow ratio (as more fully defined in the credit facility) of not more than (a) 6.00 to 1.00 for the fiscal quarters ending November 30, 2016 through November 30, 2017, and (b) 5.50 to 1.00 for each fiscal quarter ending thereafter; and (ii) a debt service coverage ratio (as more fully 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. On April 5, 2017, First Solar notified our general partner’s board of directors of its intention to explore alternatives related to its interests in the Partnership. Following such announcement, SunPower also notified our general partner’s board of directors that it is exploring alternatives related to its interests in the Partnership. Although our Sponsors have publicly announced their current intentions, there is no assurance that either or both of our Sponsors will pursue or effect any particular alternative. In addition, the credit facility contains customary non-financial covenants and certain restrictions that will limit the Partnership’s, OpCo’s and certain of the Partnership’s and its domestic subsidiaries’ ability to, among other things, incur or guarantee additional debt and to make distributions on or redeem or repurchase OpCo common units. The Joinder Agreement amended OpCo’s credit facility to permit OpCo to incur up to $50.0 million in subordinated indebtedness from First Solar or its affiliate to pay a portion of the purchase price for the Stateline Project. As of August 31, 2017, the Partnership was in compliance with its debt covenants.

OpCo’s credit facility is collateralized by a pledge over the equity of OpCo and certain of its subsidiaries. The Partnership and each of OpCo’s subsidiaries, other than certain non-guarantor subsidiaries, have guaranteed the obligations of OpCo under the credit facility.

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

As of August 31, 2017, OpCo had outstanding borrowings of $300.0 million under the term loan facility, $250.0 million under the incremental term loan facility, $25.0 million under the delayed draw term loan facility, $90.0 million under the revolving credit facility, approximately $54.9 million of letters of credit outstanding under the revolving credit facility, and $50.0 million Stateline Promissory Note. The remaining portion of the revolving credit facility is undrawn as of August 31, 2017.

45



ATM Program

On January 30, 2017, the Partnership established the ATM Program under which the Partnership may sell its Class A shares from time to time through the ATM Agents up to an aggregate sales price of $125.0 million. The Partnership may also sell its Class A shares to any ATM Agent, as principal for its own account, at a price agreed upon at the time of the sale. The Partnership will use the net proceeds from sales under the ATM Program to purchase a number of common units in OpCo equal to the number of Class A shares issued under the ATM Program. OpCo may use the proceeds for general corporate purposes, which may include, among other things, repaying borrowings under the Stateline Promissory Note and OpCo’s credit facilities, and funding working capital or acquisitions. No shares were issued under the ATM Program during the nine months ended August 31, 2017.

Tax Equity

Our projects are, and our future acquisitions are expected to be, subject to two types of tax equity financing. In the first type of tax equity financing, the governing agreements provide, and the governing agreements of our future acquisitions may provide, our tax equity investors with a number of minority investor protection rights with respect to the applicable asset or assets that have been financed with tax equity, including restricting the ability of the entity that owns such asset or assets to incur debt. To the extent we want to incur project-level debt at a project in which we co-invest with a tax equity investor, we may be required to obtain the tax equity investor’s consent prior to such incurrence. In addition, the amount of debt that could 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.
Contractual Obligations
The following table summarizes our contractual obligations as of August 31, 2017:
 
 
 
 
Payments Due by Period
 (in thousands)
Total
 
2017 (remaining
three months)
 
2018-2019
 
2020-2021
 
Beyond 2021
Land use commitments (1)
$
63,356

 
$
406

 
$
3,015

 
$
3,524

 
$
56,411

Term loan (2)
326,921

 
2,203

 
19,077

 
305,641

 

Incremental term loan (3)
273,099

 
2,047

 
16,419

 
254,633

 

Delayed draw term loan facility (4)
27,310

 
205

 
1,642

 
25,463

 

Revolving credit facility (4)
98,316

 
737

 
5,911

 
91,668

 

Stateline Promissory Note (5)
56,651

 
884

 
8,382

 
47,385

 

Total contractual obligations
$
845,653

 
$
6,482

 
$
54,446

 
$
728,314

 
$
56,411

 
(1)
Land use commitments primarily relate to a non-cancellable operating lease for the Quinto Project and two operating leases for the Kingbird Project, and are equal to the minimum lease and easement payments to landowners for the right to use the land upon which solar power systems are located.

46


(2)
Includes $300.0 million of borrowings outstanding under the term loan facility entered into by OpCo on June 5, 2015 (in connection with our IPO) which will mature on or about June 5, 2020, at which point all amounts outstanding under the term loan facility will become due. From September 1, 2017 to August 31, 2018, which is the remaining term of the interest rate swaps, the interest payments for the notional amount of $250.0 million and $40.0 million are calculated based on the fixed swap rate of 0.85% plus the 2% margin and 1.16% plus the 2% margin, respectively. The interest payments for the remaining $10.0 million notional amount through August 31, 2018, and the full amount of $300.0 million outstanding thereafter through the maturity date, are estimated based on the floating cash interest rate of approximately 3.24% per annum effective as of August 31, 2017.
(3)
Includes $250.0 million of borrowings outstanding under the incremental term loan facility entered into by OpCo on September 30, 2016 (in connection with the Joinder Agreement under its existing senior secured credit facility) which will mature on or about June 5, 2020, at which point all amounts outstanding under the incremental term loan facility will become due. The interest payments for the $250.0 million notional amount through the maturity date are estimated based on the floating cash interest rate of approximately 3.24% per annum effective as of August 31, 2017.
(4)
Includes $25.0 million of borrowings outstanding under the delayed draw term loan facility and $90.0 million of borrowings outstanding under the revolving credit facility entered into by OpCo on June 5, 2015, which will mature on or about June 5, 2020, at which point all amounts outstanding under the delayed draw term loan facility and the revolving credit facility will become due. The interest payments for the $115.0 million notional amount through the maturity date are estimated based on the floating cash interest rate of approximately 3.24% per annum effective as of August 31, 2017.
(5)
Includes $50.0 million of borrowings outstanding under the Stateline Promissory Note by OpCo to First Solar on December 1, 2016 which will mature on December 5, 2020. Interest payments are estimated based on a rate of 4.00% per annum.

Off-Balance-Sheet Arrangements
As of August 31, 2017, 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. Any market risk sensitive instruments that we have entered into are for hedging purposes, rather than for speculative trading.

Credit Risk

Credit risk relates to the risk of loss resulting from non-performance or non-payment by offtake counterparties under the terms of their contractual obligations, thereby impacting the amount and timing of expected cash flows. We monitor and manage credit risk through credit policies that include the use of credit mitigation measures such as having a diversified portfolio of offtake counterparties. However, there are a limited number of offtake counterparties under our offtake agreements, which offtake counterparties are entities engaged in the energy industry, and this concentration may impact the overall exposure to credit risk, either positively or negatively, in that the offtake counterparties may be similarly affected by changes in economic, industry or other conditions. If any of these offtake agreement customers’ receivable balances in the future should be deemed uncollectible, it could have a material adverse effect on our forecasted cash flows. As of August 31, 2017 and November 30, 2016, two offtake counterparties were placed on CreditWatch by Standard & Poor’s Ratings Services, increasing our credit risk associated with these customers. Please read Part II, Item 1A. “Risk Factors—We rely on a limited number of offtake counterparties and we are exposed to the risk that they are unwilling or unable to fulfill their contractual obligations to us or that they otherwise terminate their offtake agreements with us” and Part I, Item 1. “Financial Information—Notes to Unaudited Condensed Consolidated Financial Statements—Note 12—Related Parties—Maryland Solar Lease Arrangement.”

Credit risk under the residential lease program is limited because customers are required to have a minimum FICO credit score at the time of initial contract, the existing customer base is of high credit quality with an average FICO credit score of 765 at the time of initial contract, the program has a large number of customers with small account balances for each, and the customers are diversified geographically within the United States. As of August 31, 2017, we do not believe we had significant credit risk under the residential lease program.


47



Credit risk also relates to the risk of loss resulting from non-performance or non-payment by our Sponsors under the terms of their contractual obligations, including indemnity, reimbursement and other payment obligations under the Omnibus Agreement, thereby impacting the amount and timing of expected cash flows. Our ability to mitigate such risk with respect to the Sponsors is limited. Please read Part I, Item 1A. “Risk Factors—Risks Related to Our Business—We are exposed to the credit risk of our Sponsors, and any deterioration of our Sponsors’ creditworthiness could adversely affect our business, our credit ratings and our overall risk profile” in the 2016 10-K.

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.

Our interest expense would increase to the extent interest rates rise in connection with our variable interest rate borrowings. As of August 31, 2017, the outstanding principal balance of our variable interest borrowings was $665.0 million of which $375.0 million is unhedged. An immediate 10% increase in interest rates would have an increase of approximately $0.5 million of annualized interest expense on our unaudited condensed consolidated financial statements. This increase was mitigated by interest rate swaps that we entered into on August 31, 2016 and January 5, 2017 in connection with our term loan facility, which covered $250.0 million and $40.0 million, respectively, of the $665.0 million outstanding principal balance. As of August 31, 2017, our investment portfolio consisted of 100% in demand deposits.

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


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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 Securities and Exchange Commission 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, 2017 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.

We are subject to various risks and uncertainties in the course of our business. Risk factors relating to the Partnership are set forth under Part I, Item 1A. “Risk Factors” of the 2016 10-K. 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.

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

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

For example, FirstEnergy, our offtake counterparty with respect to the Maryland Solar Project, had its credit rating downgraded multiple times in 2016 and 2017. As of August 14, 2017, the credit rating of FirstEnergy was Caa1 and CCC- by

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Moody’s Investors Service and Standard & Poor’s Ratings Services, respectively, both of which are below investment grade. In addition, Standard & Poor’s Ratings Services placed FirstEnergy on CreditWatch with negative implications, based on a $1.51 billion pretax impairment charge that the company’s competitive business will incur from the deactivation of several coal units. In November 2016, FirstEnergy Corp., the parent of FirstEnergy, announced a strategic review of its competitive business, pursuant to which the company would seek to move away from competitive markets. In addition, Standard & Poor’s Ratings Services also placed another of our offtake counterparties, Macy’s, on CreditWatch in January 2016 and on CreditWatch negative on January 5, 2017. FirstEnergy’s annual report on Form 10-K for the year ended December 31, 2016 reported a substantial uncertainty as to their ability to continue as a going concern. Both First Energy and Macy’s remain on Standard & Poor’s Ratings Services under CreditWatch.

As further described in Part III, Item 13. “Certain Relationships and Related Transactions, and Director Independence—Agreements with our Sponsors—Maryland Solar Lease Arrangement” in the 2016 10-K, the Maryland Solar Project Entity has leased the Maryland Solar Project to an affiliate of First Solar, with the lease term expiring on December 31, 2019. Under the arrangement, First Solar’s affiliate is obligated to pay a fixed amount of rent that is set based on the expected operations of the plant. Such lease agreement will terminate upon any termination of the PPA for the Maryland Solar Project or the site ground lease. Pursuant to the PPA for the Maryland Solar Project, a FirstEnergy bankruptcy would be an event of default under the PPA, permitting (subject to applicable law) the termination of the PPA although FirstEnergy may choose to renegotiate or maintain the PPA in its current form. Upon any such early termination of the lease agreement, First Solar’s affiliate is obligated to return the facility in its then-current condition and location to us, without any warranties, and no rent shall thereafter be payable by such First Solar affiliate. In the event that the PPA was terminated and First Solar were to subsequently terminate the Maryland Solar Lease Agreement, the Maryland Solar Project would have no agreement through which to sell the energy that it produces, which equates to approximately $8.0 million in annual revenue and we can enter into a replacement offtake agreement with a different counterparty. We would attempt to replace the PPA with a similar offtake agreement with similar terms; however, we may not be able to find a replacement offtake agreement in a timely manner or at all and the terms of any replacement agreement may be less favorable to us than the terminated PPA.

We evaluate our long-lived assets, including property and equipment and projects, for impairment whenever events or changes in circumstances indicate the carrying value of such assets may not be recoverable. In consideration of the above events, we evaluated whether the carrying value of the project may no longer be recoverable using a probability-weighted assessment of potential outcomes and related undiscounted cash flows. As a result of such evaluation, we concluded the estimated future undiscounted net cash flows expected to be generated by the project over its estimated useful life exceeded the $52.0 million carrying value of the Maryland Solar Project's property and equipment as of August 31, 2017. Such assessment is subject to significant uncertainty and could change significantly as facts and circumstances change. In the event that the PPA for the Maryland Solar Project was terminated, if we are unable to enter into a replacement agreement or sell the energy it produces under similar terms, the carrying value of the project may not be recoverable, and we could record a material impairment loss in the amount by which the carrying value exceeds the fair value.

While as of August 31, 2017, both FirstEnergy and Macy’s are current with respect to payments due under the PPAs for the Maryland Solar Project, the Macy’s California Project and the Macy’s Maryland Project, as applicable, a failure by such offtake counterparties to fulfill their obligations under their respective PPAs, or any restructuring of their obligations pursuant to bankruptcy or similar proceedings, could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our Class A shareholders.

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

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


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

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

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

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

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

issues related to pricing and terms under offtake agreements;

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

difficulty accessing the capital markets to secure construction financing;

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

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

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

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

issues related to the outcome of the Section 201 Petition, including market volatility, price fluctuations, supply shortages, and project delays in the near term and materially increasing the price of solar products in the long term;

competition from other alternative energy technologies or conventional energy companies;

high development or capital costs; and

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

In addition, we and our Sponsors have agreed in the past to make several adjustments to our ROFO Portfolio. We may in the future continue working with our Sponsors to make adjustments to our ROFO Portfolio, including to remove, or waive of

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the negotiation obligations for, projects that we do not intend to acquire at the time our Sponsors plan to offer them. Such removals or waivers are subject to the approval of the board of directors of our General Partner and/or the board's conflicts committee. The removal of any projects from the ROFO Portfolio or the waiver of the negotiation obligations with respect to any projects would reduce the likelihood that we would acquire such projects. In addition, with First Solar’s sale of the interest in the Switch Station project, the Cuyama project and the California Flats project, no further projects remain subject to the First Solar ROFO Agreement.

Both of our Sponsors also announced significant work force reductions in the second half of 2016. If the challenges of developing solar energy projects increase for project developers, including our Sponsors, our pool of available opportunities may be limited, which could have a material adverse effect on our ability to grow our business and make cash distributions to our Class A shareholders.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

None.

Item 5. Other Information.

None.

Item 6. Exhibits.


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Exhibit Index
Exhibit
 
 
 
Incorporated by Reference
Number
 
Description
 
Form
 
File No.
 
Exhibit
 
Filing Date
2.1
 
 
8-K
 
001-37447
 
2.1
 
6/13/2017
10.1
 
 
8-K
 
001-37447
 
10.1
 
6/13/2017
31.1*
 
 
__
 
__
 
__
 
__
31.2*
 
 
__
 
__
 
__
 
__
32.1*
 
 
__
 
__
 
__
 
__
32.2*
 
 
__
 
__
 
__
 
__
101.INS*
 
XBRL Instance Document
 
__
 
__
 
__
 
__
101.SCH*
 
XBRL Taxonomy Extension Schema Document
 
__
 
__
 
__
 
__
101.CAL*
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
__
 
__
 
__
 
__
101.DEF*
 
XBRL Taxonomy Extension Definition Linkbase Document
 
__
 
__
 
__
 
__
101.LAB*
 
XBRL Taxonomy Extension Label Linkbase Document
 
__
 
__
 
__
 
__
101.PRE*
 
XBRL Taxonomy Extension Presentation Linkbase Document
 
__
 
__
 
__
 
__
 
*
Filed herewith

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
8point3 Energy Partners LP
 
 
 
 
 
 
By:
8point3 General Partner, LLC
 
 
 
its general partner
 
 
 
 
Date:
October 4, 2017
By:
/s/ BRYAN SCHUMAKER
 
 
 
Bryan Schumaker
 
 
 
Chief Financial Officer
 
 
 
(Principal Financial Officer)


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