Pattern Energy Group Inc.
Pattern Energy Group Inc. (Form: 10-Q, Received: 08/10/2015 08:09:50)
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2015.

or

 

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

Commission File Number 001-36087

 

 

PATTERN ENERGY GROUP INC.

(Exact name of Registrant as specified in its charter)

 

 

 

Delaware   90-0893251

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

Pier 1, Bay 3, San Francisco, CA 94111

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (415) 283-4000

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   x     No   ¨

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

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   x    Accelerated filer   ¨
Non-accelerated filer   ¨    Smaller 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   x

As of August 5, 2015, there were 74,672,596 shares of Class A common stock outstanding with par value of $0.01 per share.

 

 

 


Table of Contents

PATTERN ENERGY GROUP INC.

REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2015

TABLE OF CONTENTS

 

  PART I. FINANCIAL INFORMATION   
Item 1.  

Financial Statements

     5   
 

Consolidated Balance Sheets as of June 30, 2015 (unaudited) and December 31, 2014

     5   
 

Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2015 and 2014 (unaudited)

     6   
 

Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2015 and 2014 (unaudited)

     7   
 

Consolidated Statements of Stockholders’ Equity for the Six Months Ended June 30, 2015 and 2014 (unaudited)

     8   
 

Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2015 and 2014 (unaudited)

     9   
 

Notes to Consolidated Financial Statements (unaudited)

     11   
Item 2.  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     40   
Item 3.  

Quantitative and Qualitative Disclosures about Market Risk

     52   
Item 4.  

Controls and Procedures

     52   
  PART II. OTHER INFORMATION   
Item 1.  

Legal Proceedings

     54   
Item 1A.  

Risk Factors

     54   
Item 6.  

Exhibits

     57   
 

Signatures

     58   

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q (“Form 10-Q”) may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

 

    our ability to complete construction of our construction projects and transition them into financially successful operating projects;

 

    our ability to complete the acquisition of power projects;

 

    fluctuations in supply, demand, prices and other conditions for electricity, other commodities and RECs;

 

    our electricity generation, our projections thereof and factors affecting production, including wind and other conditions, other weather conditions, availability and curtailment;

 

    changes in law, including applicable tax laws;

 

    public response to and changes in the local, state, provincial and federal regulatory framework affecting renewable energy projects, including the potential expiration or extension of the U.S. federal PTC, ITC and potential reductions in RPS requirements;

 

    the ability of our counterparties to satisfy their financial commitments or business obligations;

 

    the availability of financing, including tax equity financing, for our power projects;

 

    an increase in interest rates;

 

    our substantial short-term and long-term indebtedness, including additional debt in the future;

 

    competition from other power project developers;

 

    development constraints, including the availability of interconnection and transmission;

 

    potential environmental liabilities and the cost and conditions of compliance with applicable environmental laws and regulations;

 

    our ability to operate our business efficiently, manage capital expenditures and costs effectively and generate cash flow;

 

    our ability to retain and attract executive officers and key employees;

 

    our ability to keep pace with and take advantage of new technologies;

 

    the effects of litigation, including administrative and other proceedings or investigations, relating to our wind power projects under construction and those in operation;

 

    conditions in energy markets as well as financial markets generally, which will be affected by interest rates, foreign currency exchange rate fluctuations and general economic conditions;

 

    the effectiveness of our currency risk management program;

 

    the effective life and cost of maintenance of our wind turbines and other equipment;

 

    the increased costs of, and tariffs on, spare parts;

 

    scarcity of necessary equipment;

 

    negative public or community response to wind power projects;

 

    the value of collateral in the event of liquidation; and

 

    other factors discussed under “Risk Factors.”

 

3


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For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see Part II, “Item 1A. Risk Factors” in this report and our Annual Report on Form 10-K for the year ended December 31, 2014.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

 

4


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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Pattern Energy Group Inc.

Consolidated Balance Sheets

(In thousands of U.S. Dollars, except share data)

(Unaudited)

 

     June 30,     December 31,  
     2015     2014  

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 82,936      $ 101,656   

Restricted cash

     26,283        7,945   

Trade receivables

     48,363        35,759   

Related party receivable

     820        671   

Reimbursable interconnection costs

     1,286        2,532   

Derivative assets, current

     18,415        18,506   

Current net deferred tax assets

     307        318   

Prepaid expenses and other current assets

     26,041        27,954   

Deferred financing costs, current, net of accumulated amortization of $4,340 and $3,493 as of June 30, 2015 and December 31, 2014, respectively

     1,903        1,747   
  

 

 

   

 

 

 

Total current assets

     206,354        197,088   

Restricted cash

     17,142        39,745   

Turbine advances

     60,893        79,637   

Construction in progress

     338,906        26,195   

Property, plant and equipment, net of accumulated depreciation of $429,939 and $278,291 as of June 30, 2015 and December 31, 2014, respectively

     2,812,203        2,350,856   

Unconsolidated investments

     147,644        29,079   

Derivative assets

     50,354        49,369   

Deferred financing costs

     4,838        5,166   

Net deferred tax assets

     6,927        5,474   

Finite-lived intangible assets, net of accumulated amortization of $1,077 and $154 as of June 30, 2015 and December 31, 2014, respectively

     101,082        1,257   

Other assets

     31,646        11,421   
  

 

 

   

 

 

 

Total assets

   $ 3,777,989      $ 2,795,287   
  

 

 

   

 

 

 

Liabilities and equity

    

Current liabilities:

    

Accounts payable and other accrued liabilities

   $ 29,273      $ 24,793   

Accrued construction costs

     42,115        20,132   

Related party payable

     881        5,757   

Accrued interest

     5,423        3,634   

Dividends payable

     24,563        15,734   

Derivative liabilities, current

     19,788        16,307   

Revolving credit facility

     250,000        50,000   

Current portion of long-term debt, net of financing costs of $10,166 and $11,868 as of June 30, 2015 and December 31, 2014, respectively

     332,226        109,693   

Current net deferred tax liabilities

     149        149   

Current portion of contingent liabilities

     11,468        4,000   
  

 

 

   

 

 

 

Total current liabilities

     715,886        250,199   

Long-term debt, net of financing costs of $22,883 and $24,887 as of June 30, 2015 and December 31, 2014, respectively

     1,369,135        1,304,165   

Derivative liabilities

     27,495        17,467   

Asset retirement obligations

     38,940        29,272   

Net deferred tax liabilities

     23,872        20,418   

Contingent liabilities

     1,189        175   

Finite-lived intangible liability, net of accumulated amortization of $434 and $0 as of June 30, 2015 and December 31, 2014, respectively

     59,866        —     

Other long-term liabilities

     9,576        8,857   
  

 

 

   

 

 

 

Total liabilities

     2,245,959        1,630,553   
  

 

 

   

 

 

 

Temporary equity - noncontrolling interests

     35,000        —     

Equity:

    

Class A common stock, $0.01 par value per share: 500,000,000 shares authorized; 69,237,919 and 62,062,841 shares outstanding as of June 30, 2015 and December 31, 2014, respectively

     693        621   

Additional paid-in capital

     874,015        723,938   

Accumulated loss

     (50,208     (44,626

Accumulated other comprehensive loss

     (50,634     (45,068

Treasury stock, at cost; 36,523 and 25,465 shares of Class A common stock as of June 30, 2015 and December 31, 2014, respectively

     (1,027     (717
  

 

 

   

 

 

 

Total equity before noncontrolling interest

     772,839        634,148   

Noncontrolling interest

     724,191        530,586   
  

 

 

   

 

 

 

Total equity

     1,497,030        1,164,734   
  

 

 

   

 

 

 

Total liabilities, temporary equity, and equity

   $ 3,777,989      $ 2,795,287   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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Pattern Energy Group Inc.

Consolidated Statements of Operations

(In thousands of U.S. Dollars, except share data)

(Unaudited)

 

     Three months ended June 30,     Six months ended June 30,  
     2015     2014     2015     2014  

Revenue:

        

Electricity sales

   $ 82,945      $ 66,053      $ 137,929      $ 119,924   

Energy derivative settlements

     5,928        3,983        12,097        6,718   

Unrealized loss on energy derivative

     (6,002     (6,549     (3,030     (14,282

Related party revenue

     872        949        1,675        1,462   

Other revenue

     928        503        866        734   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenue

     84,671        64,939        149,537        114,556   
  

 

 

   

 

 

   

 

 

   

 

 

 

Cost of revenue:

        

Project expense

     27,981        16,700        53,227        32,774   

Depreciation and accretion

     34,342        21,284        63,398        42,461   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total cost of revenue

     62,323        37,984        116,625        75,235   
  

 

 

   

 

 

   

 

 

   

 

 

 

Gross profit

     22,348        26,955        32,912        39,321   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses:

        

General and administrative

     8,870        6,288        15,091        10,191   

Related party general and administrative

     1,621        1,383        3,429        2,663   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     10,491        7,671        18,520        12,854   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     11,857        19,284        14,392        26,467   
  

 

 

   

 

 

   

 

 

   

 

 

 

Other expense:

        

Interest expense

     (18,943     (15,807     (36,861     (30,428

Interest rate derivative settlements

     (960     (1,035     (1,919     (2,052

Unrealized gain (loss) on derivatives

     5,138        (2,942     2,697        (6,665

Equity in earnings (losses) in unconsolidated investments

     13,801        (3,688     10,719        (16,236

Related party income

     756        444        1,424        1,072   

Net (loss) gain on transactions

     (1,305     14,537        (2,589     14,537   

Other (expense) income, net

     (1,084     439        (1,408     606   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other expense

     (2,597     (8,052     (27,937     (39,166
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) before income tax

     9,260        11,232        (13,545     (12,699

Tax provision

     3,603        4,065        2,857        2,033   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

     5,657        7,167        (16,402     (14,732

Net loss attributable to noncontrolling interest

     (8,660     (4,032     (10,820     (11,042
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to controlling interest

   $ 14,317      $ 11,199      $ (5,582   $ (3,690
  

 

 

   

 

 

   

 

 

   

 

 

 

Earnings per share information:

        

Net income (loss) attributable to controlling interest

   $ 14,317      $ 11,199      $ (5,582   $ (3,690

Cash dividends declared on Class A common shares

     (24,380     (14,981     (48,003     (26,138

Deemed dividends on Class B common shares

     —          (7,457     —          (7,457
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss attributable to common stockholders

   $ (10,063   $ (11,239   $ (53,585   $ (37,285
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average number of shares:

        

Class A common stock - Basic

     68,943,707        41,174,697        67,426,286        38,331,595   

Class A common stock - Diluted

     69,147,260        41,510,219        67,426,286        53,886,595   

Class B common stock - Basic and diluted

     —          15,555,000        —          15,555,000   

Earnings (loss) per share

        

Class A common stock:

        

Basic earnings (loss) per share

   $ 0.21      $ 0.17      $ (0.08   $ (0.01
  

 

 

   

 

 

   

 

 

   

 

 

 

Diluted earnings (loss) per share

   $ 0.21      $ 0.16      $ (0.08   $ (0.07
  

 

 

   

 

 

   

 

 

   

 

 

 

Class B common stock:

        

Basic and diluted earnings (loss) per share

   $ —        $ 0.28      $ —        $ (0.21
  

 

 

   

 

 

   

 

 

   

 

 

 

Dividends declared per Class A common share

   $ 0.35      $ 0.32      $ 0.71      $ 0.63   
  

 

 

   

 

 

   

 

 

   

 

 

 

Deemed dividends per Class B common share

   $ —        $ 0.48      $ —        $ 0.48   
  

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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Pattern Energy Group Inc.

Consolidated Statements of Comprehensive Income (Loss)

(In thousands of U.S. Dollars)

(Unaudited)

 

     Three months ended June 30,     Six months ended June 30,  
     2015     2014     2015     2014  

Net income (loss)

   $ 5,657      $ 7,167      $ (16,402   $ (14,732
  

 

 

   

 

 

   

 

 

   

 

 

 

Other comprehensive income (loss):

        

Foreign currency translation, net of zero tax impact

     (498     4,221        (9,692     (869
  

 

 

   

 

 

   

 

 

   

 

 

 

Derivative activity:

        

Effective portion of change in fair market value of derivatives, net of tax (provision) benefit of ($628), $66, $56 and $66, respectively

     10,100        (8,896     (657     (17,989

Reclassifications to net loss, net of tax impact of $168, $37, $341 and $37, respectively

     3,465        3,349        6,956        6,520   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total change in effective portion of change in fair market value of derivatives

     13,565        (5,547     6,299        (11,469

Proportionate share of equity investee’s derivative activity:

        

Effective portion of change in fair market value of derivatives, net of tax (provision) benefit of ($7), $560, $859, and $1,805, respectively

     20        (1,205     (2,382     (4,283

Reclassifications to net loss, net of tax impact of $206, $0, $377, and $0, respectively

     571        —          1,045        —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Total change in effective portion of change in fair market value of derivatives

     591        (1,205     (1,337     (4,283
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other comprehensive income (loss), net of tax

     13,658        (2,531     (4,730     (16,621
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income (loss)

     19,315        4,636        (21,132     (31,353
  

 

 

   

 

 

   

 

 

   

 

 

 

Less comprehensive loss attributable to noncontrolling interest:

        

Net loss attributable to noncontrolling interest

     (8,660     (4,032     (10,820     (11,042
  

 

 

   

 

 

   

 

 

   

 

 

 

Derivative activity:

        

Effective portion of change in fair market value of derivatives, net of tax (provision) benefit of ($188), $20, $17 and $20, respectively

     955        (1,149     (985     (1,884

Reclassifications to net loss, net of tax impact of $50, $11, $102 and $11, respectively

     905        876        1,821        1,705   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total change in effective portion of change in fair market value of derivatives

     1,860        (273     836        (179
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive loss attributable to noncontrolling interest

     (6,800     (4,305     (9,984     (11,221
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income (loss) attributable to controlling interest

   $ 26,115      $ 8,941      $ (11,148   $ (20,132
  

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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Pattern Energy Group Inc.

Consolidated Statement of Stockholders’ Equity

(In thousands of U.S. Dollars, except share data)

(Unaudited)

 

    Controlling Interest     Noncontrolling Interest        
                                              Accumulated                                   Accumulated              
                            Additional                 Other                                   Other              
    Class A Common Stock     Class B Common Stock     Paid-in           Accumulated     Comprehensive     Treasury Stock                 Accumulated     Comprehensive           Total  
    Shares     Amount     Shares     Amount     Capital     Capital     Loss     Loss     Shares     Amount     Total     Capital     Income (Loss)     Loss     Total     Equity  

Balances at December 31, 2013

    35,531,720      $ 355        15,555,000      $ 156      $ 489,412      $ —        $ (13,336   $ (8,353     (934   $ (24   $ 468,210      $ 90,217      $ 18,601      $ (9,024   $ 99,794      $ 568,004   

Issuance of Class A common stock related to the public offering, net of issuance costs

    10,810,810        108            286,671                  286,779                286,779   

Issuances of Class A common stock under equity incentive award plan

    173,287        2        —          —          (2     —          —          —          —          —          —          —          —          —          —          —     

Issuance of Class A common stock upon exercise of stock options

    10,001              220                  220                220   

Repurchase of shares for employee tax withholding

    —          —          —          —          —          —          —          —          (1,904     (55     (55     —          —          —          —          (55

Stock-based compensation

    —          —          —          —          2,175        —          —          —          —          —          2,175        —          —          —          —          2,175   

Refund of issuance costs related to the IPO

    —          —          —          —          163        —          —          —          —          —          163        —          —          —          —          163   

Dividends declared on Class A common stock

    —          —          —          —          (26,138     —          —          —          —          —          (26,138     —          —          —          —          (26,138

Sale of Class A membership interests in Panhandle 1

    —          —          —          —          —            —          —          —          —          —          210,250        —          —          210,250        210,250   

Acquisition of AEI ownership in E1 Arrayan

    —          —          —          —          —            —          —          —          —          —          35,259        —          —          35,259        35,259   

Distribution to noncontrolling interest

    —          —          —          —          —            —          —          —          —          —          (1,470     —          —          (1,470     (1,470

Net loss

    —          —          —          —          —          —          (3,690     —          —          —          (3,690     —          (11,042     —          (11,042     (14,732

Other comprehensive (loss) income, net of tax

    —          —          —          —          —          —          —          (16,442     —          —          (16,442     —          —          (179     (179     (16,621
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balances at June 30, 2014

    46,525,818      $ 465        15,555,000      $ 156      $ 752,501      $ —        $ (17,026   $ (24,795     (2,838   $ (79   $ 711,222      $ 334,256      $ 7,559      $ (9,203   $ 332,612      $ 1,043,834   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balances at December 31, 2014

    62,088,306      $ 621        —        $ —        $ 723,938      $ —        $ (44,626   $ (45,068     (25,465   $ (717   $ 634,148      $ 529,539      $ 9,892      $ (8,845   $ 530,586      $ 1,164,734   

Issuance of Class A common stock related to the public offering, net of issuance costs

    7,000,000        70        —          —          196,089        —          —          —          —          —          196,159        —          —          —          —          196,159   

Issuance of Class A common stock under equity incentive award plan

    186,136        2            (2           —          —                 

Repurchase of shares for employee tax withholding

    —          —          —          —          —          —          —          —          (11,058     (310     (310     —          —          —          —          (310

Stock-based compensation

    —          —          —          —          1,989        —          —          —          —          —          1,989        —          —          —          —          1,989   

Dividends declared on Class A common stock

    —          —          —          —          (48,003     —          —          —          —          —          (48,003     —          —          —          —          (48,003

Issuance of dividend equivalents upon vesting of deferred restricted stock units

    —          —          —          —          4          —          —          —          —          4        —          —          —          —          4   

Acquisition of Post Rock

    —          —          —          —          —            —          —          —          —          —          205,100        —          —          205,100        205,100   

Distribution to noncontrolling interest

    —          —          —          —          —          —          —          —          —          —          —          (1,511     —          —          (1,511     (1,511

Net loss

    —          —          —          —          —          —          (5,582     —          —          —          (5,582     —          (10,820     —          (10,820     (16,402

Other comprehensive (loss) income, net of tax

    —          —          —          —          —          —          —          (5,566     —          —          (5,566     —          —          836        836        (4,730
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balances at June 30, 2015

    69,274,442      $ 693        —        $ —        $ 874,015      $ —        $ (50,208   $ (50,634     (36,523   $ (1,027   $ 772,839      $ 733,128      $ (928   $ (8,009   $ 724,191      $ 1,497,030   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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Pattern Energy Group Inc.

Consolidated Statements of Cash Flows

(In thousands of U.S. Dollars)

(Unaudited)

 

     Six months ended June 30,  
     2015     2014  

Operating activities

    

Net loss

   $ (16,402   $ (14,732

Adjustments to reconcile net loss to net cash provided by operating activities:

    

Depreciation, amortization and accretion

     63,841        42,461   

Loss on disposal of equipment

     347        —     

Amortization of financing costs

     3,636        2,848   

Unrealized loss on derivatives

     333        20,947   

Stock-based compensation

     1,989        2,175   

Net gain on transactions

     —          (16,526

Deferred taxes

     2,616        2,033   

Equity in (earnings) losses in unconsolidated investments

     (10,719     16,236   

Unrealized loss on exchange rate changes

     823        —     

Changes in operating assets and liabilities:

    

Trade receivables

     (4,924     (13,895

Prepaid expenses and other current assets

     3,441        20,253   

Other assets (non-current)

     (99     (305

Accounts payable and other accrued liabilities

     615        348   

Related party receivable/payable

     (7     (1,053

Income taxes payable/receivable

     —          128   

Accrued interest payable

     689        (11

Contingent liabilities

     1,151        —     

Long-term liabilities

     1,270        (85
  

 

 

   

 

 

 

Net cash provided by operating activities

     48,600        60,822   
  

 

 

   

 

 

 

Investing activities

    

Cash paid for acquisitions, net of cash acquired

     (404,377     (163,589

Decrease in restricted cash

     25,277        1,316   

Increase in restricted cash

     (6,966     (2

Capital expenditures

     (216,499     (544

Distribution from unconsolidated investments

     13,847        —     

Contribution to unconsolidated investments

     —          (1,880

Reimbursable interconnection receivable

     1,246        1,417   

Other assets

     (6,074     1,236   
  

 

 

   

 

 

 

Net cash used in investing activities

     (593,546     (162,046
  

 

 

   

 

 

 

 

See accompanying notes to consolidated financial statements.

 

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Pattern Energy Group Inc.

Consolidated Statements of Cash Flows

(In thousands of U.S. Dollars)

(Unaudited)

 

     Six months ended June 30,  
     2015     2014  

Financing activities

    

Proceeds from public offering, net of expenses

     196,591        287,943   

Repurchase of shares for employee tax withholding

     (310     (55

Dividends paid

     (39,170     (22,170

Payment for deferred equity issuance costs

     (2,204     —     

Capital distributions - noncontrolling interest

     (1,511     (1,470

Decrease in restricted cash

     18,532        13,508   

Increase in restricted cash

     (21,718     (8,840

Refund of deposit for letters of credit

     3,425        —     

Payment for deferred financing costs

     (5,614     (542

Proceeds from revolving credit facility

     250,000        —     

Repayment of revolving credit facility

     (50,000     —     

Repayment of VAT facility

     —          (14,840

Proceeds from construction loan

     206,184        —     

Repayment of long-term debt

     (25,383     (22,096
  

 

 

   

 

 

 

Net cash provided by financing activities

     528,822        231,438   
  

 

 

   

 

 

 

Effect of exchange rate changes on cash and cash equivalents

     (2,596     255   
  

 

 

   

 

 

 

Net change in cash and cash equivalents

     (18,720     130,469   

Cash and cash equivalents at beginning of period

     101,656        103,569   
  

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 82,936      $ 234,038   
  

 

 

   

 

 

 

Supplemental disclosure

    

Cash payments for interest expenses, net of capitalized interest

   $ 24,447      $ 27,296   

Acquired property, plant and equipment from acquisitions

     579,712        671,068   

Schedule of non-cash activities

    

Change in fair value of designated interest rate swaps

     6,299        (20,344

Change in property, plant and equipment

     21,094        (40,729

Non-cash deemed dividends on Class B convertible common stock

     —          7,457   

See accompanying notes to consolidated financial statements.

 

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Pattern Energy Group Inc.

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

Pattern Energy Group Inc. (“Pattern Energy” or the “Company”) was organized in the state of Delaware on October 2, 2012. Pattern Energy issued 100 shares on October 17, 2012 to Pattern Renewables LP, a 100% owned subsidiary of Pattern Energy Group LP (“Pattern Development”). On September 24, 2013, Pattern Energy’s charter was amended, and the number of shares that Pattern Energy is authorized to issue was increased to 620,000,000 total shares; 500,000,000 of which are designated Class A common stock, 20,000,000 of which were designated Class B common stock, and 100,000,000 of which are designated Preferred Stock. On December 31, 2014, the Company’s outstanding Class B common stock was converted into Class A common stock on a one-for-one basis. Shares of Class B common stock converted into shares of Class A common stock were retired. The Company is not authorized to reissue shares of Class B common stock.

On May 14, 2014, the Company completed an underwritten public offering of its Class A common stock resulting in a reduction of Pattern Development’s interest in the Company from approximately 63% to 35%. Consequently, the Company is no longer subject to ASC 805-50-30-5, Transactions between Entities under Common Control. All transactions with Pattern Development after May 14, 2014 are recognized at fair value on the measurement date in accordance with the Accounting Standard Codification (“ASC”) 805 – Business Combinations . On February 9, 2015, the Company completed an underwritten public offering of its Class A common stock, resulting in a further reduction of Pattern Development’s interest in the Company from 35% to 25% causing it to no longer be entitled to certain approval rights pursuant to the Shareholder Approval Rights Agreement dated October 2, 2013.

Pattern Energy is an independent energy generation company focused on constructing, owning and operating energy projects with long-term energy sales contracts located in the United States, Canada and Chile. The Company consists of the consolidated operations of certain entities and assets contributed by, or purchased principally from, Pattern Development. The Company owns 100% of Hatchet Ridge Wind, LLC (“Hatchet Ridge”), St. Joseph Windfarm Inc. (“St. Joseph”), Spring Valley Wind LLC (“Spring Valley”), Pattern Santa Isabel LLC (“Santa Isabel”), Ocotillo Express LLC (“Ocotillo”), Logan’s Gap Wind LLC (“Logan’s Gap”) and Fowler Ridge IV Wind Farm LLC (“Amazon Wind Farm (Fowler Ridge)”). The Company owns a controlling interest in Pattern Gulf Wind Holdings LLC (“Gulf Wind”), Parque Eólico El Arrayán SpA (“El Arrayán”), Panhandle Wind Holdings LLC (“Panhandle 1”), Panhandle B Member 2 LLC (“Panhandle 2”), Lost Creek Wind, LLC (“Lost Creek”) and Post Rock Wind Power Project, LLC (“Post Rock”), and noncontrolling interests in South Kent Wind LP (“South Kent”), Grand Renewable Wind LP (“Grand”) and K2 Wind Ontario Limited Partnership (“K2”). The principal business objective of the Company is to produce stable and sustainable cash flows through the generation and sale of energy and to selectively grow its project portfolio.

2. Summary of Significant Accounting Policies

As of June 30, 2015, the Company has added the following significant accounting policies to the significant accounting policies described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014: change in depreciable lives of property, plant and equipment, asset acquisitions, temporary equity – noncontrolling interests, finite-lived intangible assets and change in presentation of deferred financing costs within short-term and long-term debt, as described below.

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements have been prepared in accordance with the U.S. generally accepted accounting principles (“U.S. GAAP”). They include the results of wholly-owned and partially-owned subsidiaries in which the Company has a controlling interest with all significant intercompany accounts and transactions eliminated.

Unaudited Interim Financial Information

The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and Article 10 of Regulation S-X issued by the U.S. Securities and Exchange Commission (“SEC”). Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, the interim financial information reflects all adjustments of a normal recurring nature, necessary for a fair presentation of the Company’s financial position at June 30, 2015, the results of operations, comprehensive income (loss), and cash flows for the three and six months ended June 30, 2015 and 2014, respectively. The consolidated balance sheet at December 31, 2014 has been derived from the audited financial statements at that date, but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements. This Form 10-Q should be read in conjunction with the consolidated financial statements and accompanying notes contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

 

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Use of Estimates

The preparation of the financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates, and such differences may be material to the financial statements.

Change in Depreciable Lives of Property, Plant and Equipment

The Company periodically reviews the estimated economic useful lives of its fixed assets. In 2015, this review indicated that the expected economic useful lives of certain wind farms were longer than the estimated economic useful lives used for depreciation purposes in the Company’s financial statements. As a result, effective January 1, 2015, the Company changed its estimate of the economic useful lives of wind farms for which construction began after 2011, from 20 to 25 years. All other wind farms continue to depreciate over an estimated economic useful life of 20 years. For the three and six months ended June 30, 2015, the effect of this change reduced depreciation expense by $3.7 million and $7.3 million, respectively, increased net income (loss) by $3.5 million and $6.9 million, net of tax, respectively, and increased Class A basic and diluted earnings per share by $0.03 for the three months ended June 30, 2015 and decreased Class A basic and diluted loss per share by $0.05 for the six months ended June 30, 2015.

Acquisitions

Business Combinations

The Company accounts for acquisitions of a controlling interest in entities that include inputs and processes and have the ability to create outputs as business combinations. The fair value of purchase consideration is allocated to the tangible and intangible assets acquired and liabilities assumed based on their estimated fair values. The excess, if any, of the fair value of purchase consideration over the fair values of these identifiable assets and liabilities is recorded as goodwill. Conversely, the excess, if any, of the net fair values of identifiable assets and liabilities over the fair value of purchase consideration is recorded as gain. Such valuations require management to make significant estimates and assumptions, especially with respect to intangible assets. These estimates and assumptions are inherently uncertain, and as a result, actual results may differ from estimates. Significant estimates include, but are not limited to, future expected cash flows, useful lives and discount rates. During the measurement period, which is one year from the acquisition date, we may record adjustments to the assets acquired and liabilities assumed, with a corresponding offset to either goodwill or gain, depending on whether the fair value of purchase consideration is in excess of or less than net assets acquired. Upon the conclusion of the measurement period, any subsequent adjustments are recorded to earnings. Transaction costs are expensed to the consolidated statements of operations in the period of acquisition.

Asset Acquisitions

When the Company acquires assets and liabilities that do not constitute a business, the fair value of the purchase consideration, including transaction costs of the asset acquisition, is assumed to be equal to the fair value of the net assets acquired and is allocated to the individual assets and liabilities assumed based on their relative fair values. Contingent consideration associated with the acquisition is generally recognized when the contingency is resolved. No goodwill is recognized in an asset acquisition.

Equity Method Investments

When the Company acquires a noncontrolling interest the investment is accounted for using the equity method of accounting and is initially recognized at cost.

Noncontrolling Interests

Noncontrolling interests represent the portion of the Company’s net income (loss), net assets and comprehensive income (loss) that is not allocable to the Company and is calculated based on ownership percentage, for applicable projects.

For the noncontrolling interests at the Company’s Gulf Wind, Panhandle 1, Panhandle 2, Lost Creek and Post Rock projects, the Company has determined that the operating partnership agreements do not allocate economic benefits pro rata to its two classes of investors and has determined that the appropriate methodology for calculating the noncontrolling interest balance that reflects the substantive profit sharing arrangement is a balance sheet approach using the hypothetical liquidation at book value (“HLBV”) method.

Under the HLBV method, the amounts reported as noncontrolling interest in the consolidated balance sheets and consolidated statements of operations represent the amounts the third party would hypothetically receive at each balance sheet reporting date under the liquidation provisions of the operating partnership agreement assuming the net assets of the projects were liquidated at recorded amounts determined in accordance with U.S. GAAP and distributed to the investors. The noncontrolling interest in the results of

 

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operations and comprehensive income (loss) of the projects is determined as the difference in noncontrolling interests in the consolidated balance sheets at the start and end of each reporting period, after taking into account any capital transactions between the projects and the third party. The noncontrolling interest balances in the projects are reported as a component of equity in the consolidated balance sheets.

Temporary Equity – Noncontrolling Interests

In connection with the May 15, 2015 acquisition of Lost Creek, the Company recorded $35.0 million in temporary equity –noncontrolling interests in the consolidated balance sheets related to the Class A membership interests in Lost Creek Wind Holdco. Refer to Note 3 – Acquisitions – Business Combinations – Wind Capital Group Acquisition for detail. The Class A membership interests hold a put option to sell the Class A shares to the Company, on April l5, 2020, at a specified amount. In accordance with ASC 480-10 –S99 – Accounting for Redeemable Equity Interests , equity instruments with redemption features that are not solely within the control of the issuer are to be classified outside of permanent equity and presented as “temporary equity” on the consolidated balance sheets, appearing after liabilities and before equity. As of June 30, 2015, the noncontrolling interest is presented at fair value in temporary equity.

Concentrations of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents, trade receivables, derivative assets and liabilities. The Company places its cash and cash equivalents with high quality institutions.

The Company sells electricity and environmental attributes, including renewable energy credits, primarily to creditworthy utilities under long-term, fixed-priced Power Sale Arrangements (“PPAs”) and, in some cases, through individual renewable energy credits sale agreements. During 2015, Standard & Poor’s Rating Services (“S&P”) further downgraded the credit rating of the Puerto Rico Electric Power Authority (“PREPA”) from CCC to CCC-. Through June 30, 2015, Moody’s Investor Service’s credit rating of PREPA remains unchanged at Caa3. As of June 30, 2015 and August 10, 2015, PREPA was current with respect to payments due under the PPA.

The following table presents significant customers who accounted for the following percentages of total revenues during the three and six months ended June 30, 2015 and 2014, respectively, and the related maximum amount of credit loss based on their respective percentages of total trade receivables for the three and six months ended June 30, 2015:

 

     Revenue     Trade Receivables  
     Three months ended June 30,     Six months ended June 30,     Three months ended June 30,     Six months ended June 30,  
     2015     2014     2015     2014     2015     2014     2015     2014  

San Diego Gas & Electric

     25.10     35.28     18.77     27.98     31.91     45.29     31.91     45.29

Manitoba Hydro

     8.28     12.77     11.28     15.98     3.58     7.25     3.58     7.25

The Independent Electricity System Operator (“IESO”) is the customer for each of the Company’s Grand, K2 and South Kent projects. The Company accounts for these projects under the equity method of accounting and as a result, the Company’s ownership interest in these projects is recorded in equity in losses of unconsolidated investments and not in revenue. As such, IESO is not included in the foregoing table of significant customers. However, we rely on a limited number of key power purchasers, including IESO, and face a concentration of credit risk from IESO as a customer.

The Company’s interest rate derivative instruments are placed with counterparties that are creditworthy institutions. An additional derivative instrument arises from an arrangement with Credit Suisse Energy LLC, the counterparty to a 10-year fixed-for-floating swap related to annual electricity generation at the Company’s Gulf Wind project. The Company’s reimbursements for prepaid interconnection network upgrades are with large creditworthy utility companies.

Finite-Lived Intangible Assets

Finite-lived intangible assets include PPAs, easements, land options and mining rights. PPA’s obtained through acquisitions are valued at the time of acquisition and the difference between the contract price and the estimated fair value results in an intangible asset or an intangible liability. If the contract price is higher than the estimated fair value, the Company will recognize an intangible asset. If the contract price is lower than the estimated fair value, the Company will recognize an intangible liability. Easements, land options and mining rights are recognized at cost.

 

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The Company amortizes intangible assets and liabilities associated with PPAs using the straight-line method over the remaining term of the related PPA, ranging from approximately 15-17 years. The Company amortizes easements, land options and mining rights using the straight-line method over the term of their estimated useful lives, which represents the term of the easements and land option and mining rights agreements, ranging from eleven months to twenty years. The Company periodically evaluates whether events or changes in circumstances have occurred that indicate the carrying amount of finite-lived intangible assets may not be recoverable, or information indicates that impairment may exist.

Reclassification

Certain prior period balances have been reclassified to conform to current period presentation of the Company’s consolidated financial statements and accompanying notes. Such reclassifications did not have an impact on consolidated net income (loss) or cash flows.

Recently Issued Accounting Standards

In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-11, “Simplifying the Measurement of Inventory” which changes the measurement principle for inventory from the lower of cost or market to the lower of cost and net realizable value . Net realizable value is defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments do not apply to inventory that is measured using last-in, first-out or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first out or average cost. ASU 2015-11 is effective for annual reporting periods beginning after December 15, 2016 and interim periods within those fiscal years. The amendments in this update should be applied prospectively. Early adoption is permitted as of the beginning of an interim or annual reporting period. The adoption of the provisions of ASU 2015-11 is not expected to have a material impact on the Company’s consolidated financial statements.

In April 2015, the FASB issued ASU 2015-03, “Interest – Imputation of Interest” to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. ASU 2015-03 is effective for public companies for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years and should be applied retrospectively. Early adoption is permitted for financial statements that have not been previously issued. Upon transition, an entity is required to comply with the applicable disclosures for a change in accounting principle. The Company adopted this standard in April 2015 and applied the change in accounting principle to the consolidated financial statements as of June 30, 2015. As a result, the Company reclassified $33.0 million and $36.8 million in total deferred financing costs to long-term debt, of which $10.2 million and $11.9 million have been reclassified to current portion of long-term debt, as of June 30, 2015 and December 31, 2014, respectively, on the Company’s consolidated balance sheets. Deferred financing costs related to the Company’s revolving credit facility remains classified as an asset on the Company’s consolidated balance sheets. The adoption of ASU 2015-03 had no impact on the Company’s results of operations and cash flows.

In February 2015, the FASB issued ASU 2015-02, “Consolidation: Amendments to the Consolidation Analysis” to modify the analysis that companies must perform in order to determine whether a legal entity should be consolidated. ASU 2015-02 simplifies current guidance by reducing the number of consolidation models; eliminating the risk that a reporting entity may have to consolidate based on a fee arrangement with another legal entity; placing more weight on the risk of loss in order to identify the party that has a controlling financial interest; reducing the number of instances that related party guidance needs to be applied when determining the party that has a controlling financial interest; and changing rules for companies in certain industries that ordinarily employ limited partnership or VIE structures. ASU 2015-02 is effective for public companies for fiscal years beginning after December 15, 2015 and interim periods within those fiscal periods. Early adoption on a modified retrospective or full retrospective basis is permitted. The Company is currently assessing the future impact of this update on its consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016. Early adoption is not permitted. The guidance permits companies to either apply the requirements retrospectively to all prior periods presented, or apply the requirements in the year of adoption, through a cumulative adjustment. In June 2015, the FASB voted to defer the effective date by one year, with early adoption permitted as of the original effective date. The Company is currently assessing the future impact of this update on its consolidated financial statements.

 

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3. Acquisitions

Business Combinations

Wind Capital Group Acquisition

On May 15, 2015, pursuant to a Purchase and Sale Agreement, the Company acquired 100% of the membership interests in Lost Creek Wind Finco, LLC (“Lost Creek Finco”) from Wind Capital Group LLC, an unrelated third party, and 100% of the membership interests in Lincoln County Wind Project Holdco, LLC (“Lincoln County Holdco”) from Lincoln County Wind Project Finco, LLC, an unrelated third party. Lost Creek Finco owns 100% of the Class B membership interests in Lost Creek Wind Holdco, LLC, (“Lost Creek Wind Holdco”) a company which owns a 100% interest in the Lost Creek wind project. Lincoln County Holdco owns 100% of the Class B membership interests in Post Rock Wind Power Project, LLC, a company which owns a 100% interest in the Post Rock wind project. The acquisition of 100% of the membership interests in Lost Creek Finco and Lincoln County Holdco was for an aggregate consideration of approximately $242.0 million, paid at closing. The Company also assumed certain project level indebtedness and ordinary course performance guarantees securing project obligations. Lost Creek is a 150 MW wind project in King City, Missouri, and Post Rock is a 201 MW wind project in Ellsworth and Lincoln Counties, Kansas.

The Company acquired assets and operating contracts for Lost Creek and Post Rock, including assumed liabilities. The identifiable assets and liabilities assumed were recorded at their fair values, which corresponded to the sum of the cash purchase price and the initial balance of the other investors’ noncontrolling interests.

The fair value of the assets acquired and liabilities assumed in connection with the acquisition are as follows (in thousands):

 

     May 15, 2015  

Cash and cash equivalents

   $ 3,501   

Restricted cash, current

     16,379   

Trade receivables

     7,910   

Prepaid expenses and other current assets

     1,676   

Property, plant and equipment

     541,300   

Finite-lived intangible assets, net of accumulated amortization

     97,400   

Other assets

     19,935   

Accounts payable and other accrued liabilities

     (2,588

Accrued interest

     (951

Derivative liabilities, current

     (4,236

Current portion of long-term debt, net of financing costs

     (7,463

Finite-lived intangible liabilities, net of accumulated amortization

     (60,300

Asset retirement obligations

     (6,994

Long-term debt, net of financing costs

     (108,838

Derivative & other long-term liabilities, less current portion

     (14,631
  

 

 

 

Total consideration before temporary equity and noncontrolling interests

     482,100   

Less: temporary equity

     (35,000

Less: noncontrolling interests

     (205,100
  

 

 

 

Total consideration after temporary equity and noncontrolling interests

   $ 242,000   
  

 

 

 

Current assets and accounts payable and other accrued liabilities were recorded at carrying value, which is representative of the fair value on the date of acquisition. Property, plant and equipment, finite-lived intangible asset, finite-lived intangible liability and debt were recorded at fair value estimated using the income approach. The fair values of other assets, derivatives and asset retirement obligations were recorded at fair value using a combination of market data, operational data and discounted cash flows and were adjusted by a discount rate factor reflecting current market conditions at the time of acquisition.

The noncontrolling interest in Post Rock was recorded at fair value estimated using a discounted cash flow approach, adjusted for a discount rate reflecting the estimated return on investment required by participants in the tax equity market. The noncontrolling interest in Lost Creek was recorded at fair value estimated using the purchase price from a purchase agreement executed on May 15, 2015 between the Company and the tax equity investor.

The accounting for this acquisition is preliminary. The fair value estimates for the assets acquired and liabilities assumed were based on preliminary calculations and valuations, and the estimates and assumptions are subject to change as additional information is obtained for the estimates during the measurement period (up to one year from the acquisition date).

 

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The Company incurred $1.9 million of transaction-related expenses which were recorded in net (loss) gain on transactions in the consolidated statements of operations for the three and six month period ended June 30, 2015, respectively.

The Company also entered into an agreement to purchase 100% of the Class A membership interests in Lost Creek Wind Holdco for an aggregate consideration of approximately $35.0 million, subject to various closing conditions. If the closing conditions are not satisfied or waived by September 30, 2015, then each of the parties has a right to terminate the agreement, provided they are not in breach of its terms. Refer to Note 22, Subsequent Events , for disclosure on the acquisition of the Class A membership interests in Lost Creek Wind Holdco.

Panhandle 2 Acquisition

On November 10, 2014, the Company acquired 100% of the membership interests in the Panhandle 2 wind project through the acquisition of Panhandle B Member 2 LLC, from Pattern Development, for a purchase price of approximately $123.8 million.

Subsequent to the closing, certain tax equity investors made capital contributions to acquire 100% of the Class A membership interests in Panhandle 2 and were admitted as noncontrolling members in the entity and the Company received 100% of the Class B membership interests, resulting in the tax equity investors and the Company holding initial ownership interests of 19% and 81%, respectively, in the project’s distributable cash flows. The 182 MW wind project, located in Carson County, Texas, achieved commercial operations on November 7, 2014. The Company has determined that the operating partnership agreement does not allocate economic benefits pro rata to its two classes of investors and will use the HLBV method to calculate the noncontrolling interest balance that reflects the substantive profit sharing arrangement.

The Company acquired the assets and operating contracts for Panhandle 2, including assumed liabilities. The identifiable assets acquired and liabilities assumed were recorded at their fair values which corresponded to the sum of the cash purchase price. The short-term debt presented in the table below consists of a construction loan that was repaid in full following the acquisition.

The accounting for the Panhandle 1 acquisition was completed as of March 31, 2015 at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of November 10, 2014 as well as adjustments made through March 31, 2015, when the allocation became final. The consolidated fair value of the assets acquired and liabilities assumed in connection with the Panhandle 2 acquisition are as follows (in thousands):

 

     November 10, 2014  

Cash and cash equivalents

   $ 240   

Trade receivables

     1,156   

Prepaid expenses and other current assets

     28,997   

Property, plant and equipment

     315,109   

Accrued construction costs

     (24,197

Related party payable

     (121

Short-term debt

     (195,351

Asset retirement obligation

     (2,003
  

 

 

 

Total consideration

   $ 123,830   
  

 

 

 

Current assets, accrued construction costs and related party payable were recorded at carrying value, which is representative of the fair value on the date of acquisition. In addition, the short-term debt was recorded at carrying value, representative of the fair value, which was repaid immediately after acquisition.

Property, plant and equipment were recorded at the cost of construction plus the developer’s profit margin, which represents fair value. The asset retirement obligation was recorded at fair value using a combination of market data, operational data and discounted cash flows and was adjusted by a discount rate factor reflecting then current market conditions.

Logan’s Gap Acquisition

On December 19, 2014, the Company acquired 100% of the membership interests in the Logan’s Gap wind project, through the acquisition of Logan’s Gap B Member LLC, from Pattern Development, for a purchase price of approximately $15.1 million and an assumed contingent liability to a third party in the amount of $8.0 million associated with the close of construction financing and the achievement of either commercial operation or tax equity funding. The wind project is currently under construction and is located in Comanche County, Texas. The construction of the project is being financed primarily by construction debt and Pattern Energy equity. Following construction, it is expected that institutional tax equity investors will invest in the project, pursuant to an executed equity commitment agreement, so that the construction loan will be paid off such that long term financing for the project will be equity based. Upon tax equity funding, it is expected that the Company and the institutional tax equity investors will have initial ownership interests of 82% and 18%, respectively, in the project’s distributable cash flows.

 

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The Company acquired the assets and operating contracts for Logan’s Gap, including assumed liabilities. The identifiable assets acquired and liabilities assumed were recorded at their fair values which corresponded to the sum of the cash purchase price.

The accounting for the Logan’s Gap acquisition was completed as of March 31, 2015 at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of December 19, 2014, as well as adjustments made through March 31, 2015, when the allocation became final. The consolidated fair value of the assets acquired and liabilities assumed in connection with the Logan’s Gap acquisition are as follows (in thousands):

 

     December 19, 2014  

Cash and cash equivalents

   $ 2   

Restricted cash, current

     5,003   

Prepaid expenses and other current assets

     1,790   

Deferred financing costs, current

     2,882   

Construction in progress

     23,821   

Property, plant and equipment

     116   

Other assets

     80   

Accrued construction costs

     (5,617

Current portion of contingent liabilities

     (7,975

Related party payable

     (5,003
  

 

 

 

Total consideration

   $ 15,099   
  

 

 

 

Current assets, current liabilities, property, plant and equipment, other assets, accrued construction costs and related party payable were recorded at carrying value, which is representative of the fair value on the date of acquisition. Construction in progress was recorded at fair value which is representative of the development effort, including the developer’s profit, and contracts acquired on the date of acquisition.

The Company recorded $8.0 million in contingent obligations, payable to a third party, at fair value upon acquisition. Of this amount, $4.0 million was paid in December 2014, upon construction financing, and the remaining $4.0 million liability is payable upon the earlier of commercial operations or tax equity funding, which is expected to occur in the third quarter of 2015.

Panhandle 1 Acquisition

On June 30, 2014, the Company acquired 100% of the Class B membership interests in the Panhandle 1 wind project, representing a 79% initial ownership interest in the project’s distributable cash flow, through the acquisition of Panhandle Wind Holdings LLC, from Pattern Development, for a purchase price of approximately $124.4 million. The 218 MW wind project, located in Carson County, Texas, achieved commercial operations on June 25, 2014.

Prior to the closing, certain tax equity investors made capital contributions to acquire 100% of the Class A membership interests in Panhandle 1 and have been admitted as noncontrolling members in the entity, with a 21% initial ownership interest in the project’s distributable cash flow. The Company has determined that the operating partnership agreement does not allocate economic benefits pro rata to its two classes of investors and will use the HLBV method to calculate the noncontrolling interest balance that reflects the substantive profit sharing arrangement.

The Company acquired the assets and operating contracts for Panhandle 1, including assumed liabilities. The identifiable assets acquired and liabilities assumed were recorded at their fair values, which corresponded to the sum of the cash purchase price and the initial balance of the other investors’ noncontrolling interests.

The accounting for the Panhandle 1 acquisition was completed as of December 31, 2014 at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of June 30, 2014, as well as adjustments made through December 31, 2014, when the allocation became final. The consolidated fair value of the assets acquired and liabilities assumed in connection with the Panhandle 1 acquisition are as follows (in thousands):

 

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     June 30, 2014  

Cash and cash equivalents

   $ 1,038   

Trade receivables

     1,850   

Prepaid expenses and other current assets

     71   

Restricted cash, non-current

     14,293   

Property, plant and equipment

     332,953   

Accounts payable and other accrued liabilities

     (148

Accrued construction costs

     (12,806

Related party payable

     (44

Asset retirement obligation

     (2,557
  

 

 

 

Total consideration before non-controlling interest

     334,650   

Less: tax equity noncontrolling interest contributions

     (210,250
  

 

 

 

Total consideration after non-controlling interest

   $ 124,400   
  

 

 

 

Current assets, restricted cash, current liabilities, accrued construction costs and related party payable were recorded at carrying value, which is representative of the fair value on the date of acquisition.

Property, plant and equipment were recorded at the cost of construction plus the developer’s profit margin, which represents fair value. The asset retirement obligation was recorded at fair value using a combination of market data, operational data and discounted cash flows and was adjusted by a discount rate factor reflecting then current market conditions.

El Arrayán Acquisition

On June 25, 2014, the Company acquired 100% of the issued and outstanding common stock of AEI El Arrayán Chile SpA (“AEI El Arrayán”), an entity holding a 38.5% indirect interest in El Arrayán, for a total purchase price of $45.3 million, pursuant to the terms of a Stock Purchase Agreement. The Company owned a 31.5% indirect interest in El Arrayán prior to acquiring the additional 38.5% interest in order to obtain majority control (70%) of the project, as a part of its growth strategy. El Arrayán is a 115 MW wind power project company, located in Ovalle, Chile, which achieved commercial operations on June 4, 2014.

Prior to the acquisition, the Company accounted for the investment under the equity method of accounting. Because the Company acquired an additional 38.5% indirect interest in El Arrayán, in accordance with ASC 805 Business Combinations, the acquisition was accounted for as a “business combination achieved in stages.” Accordingly, the Company remeasured the previously held equity interest in El Arrayán and adjusted it to fair value based on the Company’s existing equity interest in the fair value of the underlying assets and liabilities of El Arrayán. The fair value of the Company’s equity interest at the acquisition date was $37.0 million (31.5% of implied equity value of $117.5 million per below). The difference between the fair value of the Company’s ownership in El Arrayán and the Company’s carrying value of its investment of $19.1 million resulted in a gain of $17.9 million recorded in net gain on transactions in the consolidated statements of operations for the year ended December 31, 2014. The Company recognized additional deferred tax liability due to differences in accounting and tax bases resulting from the Company’s existing ownership interest in El Arrayán, which has been included in the consolidated statements of operations. The Company now holds a 70% controlling interest in the wind project and consolidates the accounts of El Arrayán.

The Company acquired the assets and operating contracts for AEI El Arrayán, including assumed liabilities. The identifiable assets acquired and liabilities assumed were recorded at their fair values.

The accounting for the AEI El Arrayán acquisition was completed as of December 31, 2014 at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of June 25, 2014, as well as adjustments made through December 31, 2014, when the allocation became final. The consolidated fair value of the assets acquired and liabilities assumed in connection with the AEI El Arrayán acquisition are as follows (in thousands):

 

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     Consolidated
interest
June 25, 2014
 

Cash and cash equivalents

   $ 713   

Trade receivables

     3,829   

VAT receivable

     17,031   

Prepaid expenses and other current assets

     174   

Restricted cash, non-current

     10,392   

Property, plant and equipment

     341,417   

Intangible assets

     1,121   

Net deferred tax assets

     5,455   

Accounts payable and other accrued liabilities

     (6,830

Accrued construction costs

     (9,495

Accrued interest

     (2,592

Derivative liabilities, current

     (1,942

Current portion of long-term debt

     (16,586

Long-term debt

     (209,295

Derivative liabilities, non-current

     (501

Asset retirement obligation

     (2,354

Net deferred tax liabilities

     (13,001
  

 

 

 

Total consideration

     117,536   

Less: non-controlling interest

     (35,259
  

 

 

 

Controlling interest

   $ 82,277   
  

 

 

 

Current assets, restricted cash, deferred tax assets, current liabilities, accrued construction costs, debt, accrued interest and deferred tax liabilities were recorded at carrying value, which is representative of the fair value on the date of acquisition. Derivative liabilities were recorded at fair value. Property, plant and equipment were recorded at the cost of construction plus the developer’s profit margin, which represents fair value. The asset retirement obligation was recorded at fair value using a combination of market data, operational data and discounted cash flows and was adjusted by a discount rate factor reflecting then current market conditions.

The Company recognized deferred tax liabilities due to differences in accounting and tax bases resulting from the Company’s acquisition of incremental interest in El Arrayán and the remeasurement of the project’s remaining noncontrolling interest at fair value.

Supplemental pro forma data

The unaudited pro forma statement of operations data below gives effect to the Lost Creek, Post Rock, Panhandle 1 and El Arrayán acquisitions as if they had occurred on January 1, 2014. The pro forma net income (loss) for the three and six month periods ended June 30, 2015 was adjusted to exclude nonrecurring transaction related expenses of $1.5 million and $1.9 million, respectively. The pro forma net loss for the three and six months ended June 30, 2014 was adjusted to exclude nonrecurring transaction related expenses of $2.5 million and $2.5 million, respectively. In addition, the 2014 pro forma net loss was adjusted to exclude a nonrecurring $17.9 million gain on acquisition of El Arrayán. The unaudited pro forma data is presented for illustrative purposes only and is not intended to be indicative of actual results that would have been achieved had these acquisitions been consummated as of January 1, 2014. The unaudited pro forma data should not be considered representative of the Company’s future financial condition or results of operations.

 

     Three months ended June 30,      Six months ended June 30,  

Unaudited pro forma data (in thousands)

   2015      2014      2015      2014  

Pro forma total revenue

   $ 92,196       $ 82,559       $ 170,800       $ 149,406   

Pro forma total expenses

     86,865         94,065         188,725         185,951   
  

 

 

    

 

 

    

 

 

    

 

 

 

Pro forma net income (loss)

     5,331         (11,506      (17,925      (36,545

Less: pro forma net loss attributable to noncontrolling interest

     (10,233      (6,810      (17,612      (16,313
  

 

 

    

 

 

    

 

 

    

 

 

 

Pro forma net income (loss) attributable to controlling interest

   $ 15,564       $ (4,696    $ (313    $ (20,232
  

 

 

    

 

 

    

 

 

    

 

 

 

Prior to the acquisition of AEI El Arrayán, the project’s net loss was recorded in equity in (losses) earnings in unconsolidated investments in the consolidated statement of operations. From January 1, 2014 to June 25, 2014, the Company recorded net loss of $0.4 million in equity in (losses) earnings on unconsolidated investments related to El Arrayán.

The following table presents the amounts included in the consolidated statements of operations for Lost Creek and Post Rock since their respective dates of acquisition:

 

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    Three months ended     Six months ended  

Unaudited data (in thousands)

  June 30, 2015     June 30, 2015  

Total revenue

  $ 5,172      $ 5,172   

Total expenses

    6,350        6,350   
 

 

 

   

 

 

 

Net loss

    (1,178     (1,178

Less: net loss attributable to noncontrolling interest

    (800     (800
 

 

 

   

 

 

 

Net loss attributable to controlling interest

  $ (378   $ (378
 

 

 

   

 

 

 

Asset Acquisition

Amazon Wind Farm (Fowler Ridge)

On April 29, 2015, the Company acquired 100% of the membership interests in Fowler Ridge IV Wind Farm LLC through the acquisition of Fowler Ridge IV B Member LLC from Pattern Development, pursuant to a Purchase and Sale Agreement, for a purchase price of approximately $37.5 million, paid at closing, in addition to $0.5 million of capitalized transaction expenses, and contingent payments of up to $29.1 million, payable upon tax equity funding. The 150 MW wind project, named Amazon Wind Farm (Fowler Ridge), located in Benton County, Indiana, is expected to reach commercial operation in late 2015.

The Company acquired certain assets and assumed certain liabilities of Amazon Wind Farm (Fowler Ridge), including various operating contracts, deferred development costs, tangible assets, real property interests, governmental approvals and other assets. The fair value of the purchase consideration, including transaction costs of the asset acquisition, is allocated to the relative fair value of the individual assets and liabilities. The preliminary fair value of the assets acquired and liabilities assumed in connection with the Amazon Wind Farm (Fowler Ridge) acquisition are as follows (in thousands):

 

     April 29, 2015  

Prepaid expenses and other current assets

   $ 1,753   

Deferred financing costs, current

     2,132   

Turbine advances

     4,000   

Construction in progress

     34,412   

Finite-lived intangible assets, net of accumulated amortization

     2,247   

Accrued construction costs

     (6,549
  

 

 

 

Total consideration

   $ 37,995   
  

 

 

 

The accounting for this acquisition is preliminary. The fair value estimates for the assets acquired and liabilities assumed were based on preliminary calculations and valuations, and the estimates and assumptions are subject to change as additional information is obtained.

In connection with the acquisition, the Company may make additional contingent payments of up to $29.1 million, consisting of a $25.1 million fixed amount and up to $4.0 million, as calculated based on final budget to actual amounts, both of which are payable to Pattern Development upon tax equity funding.

The Company also acquired a $5.0 million contingent obligation, which was paid subsequent to the close of construction financing, and assumed an estimated $7.3 million contingent liability required to connect the project into an existing transmission line. The estimated contingent payment was accrued when it became probable that the event would occur, upon close of construction financing.

In addition, the Company acquired an agreement between Pattern Development and an unrelated third party, whereby the unrelated third party is entitled to 1% of the gross revenue received by the project under the PPA, which is estimated to be approximately $2.6 million over 13 years.

Equity Method Investments

On June 17, 2015, the Company acquired from Pattern Development a one-third equity interest in K2 for approximately $128.0 million, in addition to $0.4 million of capitalized transaction expenses, plus assumed estimated proportionate debt at term conversion of approximately $221.8 million, U.S. dollar equivalent. K2 is a joint venture established to develop, construct and own a wind power project located in Ontario, Canada. The project has a 20-year PPA and commenced commercial operations in May 2015. The Company’s investment in K2 was funded through general corporate funds and borrowings under the revolving credit facility. The Company is a noncontrolling investor in K2 but does have significant influence over K2. Accordingly, the investment is accounted for under the equity method of accounting.

 

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As of the acquisition date the carrying value of the Company’s investment in K2 was $111.6 million higher than the Company’s underlying equity in the net assets of K2. This equity method basis difference was comprised of $57.9 million related to property, plant and equipment and $53.7 million related to the PPA. In accordance with ASC 323, Equity Method Investments , the basis difference related to the property, plant and equipment will be amortized over the estimated economic useful life of the underlying long-lived assets. The basis difference related to the PPA will be amortized over the remaining term of the PPA. The accounting for the acquisition is preliminary. The basis differences were based on preliminary calculations and valuations, and the estimates and assumptions are subject to change as additional information is obtained.

4. Prepaid Expenses and Other Current Assets

The following table presents the components of prepaid expenses and other current assets (in thousands):

 

     June 30,      December 31,  
     2015      2014  

Prepaid expenses

   $ 13,138       $ 15,275   

Prepaid construction costs

     3,605         5,155   

Sales tax

     62         786   

Other current assets:

     

Deposit for letters of credit

     —           3,425   

Deposit for acquisition of Class A membership interest

     3,500         —     

Deferred equity issuance costs

     4,616         2,331   

Other

     1,120         982   
  

 

 

    

 

 

 

Prepaid expenses and other current assets

   $ 26,041       $ 27,954   
  

 

 

    

 

 

 

5. Property, Plant and Equipment

The following presents the categories within property, plant and equipment (in thousands):

 

     June 30,      December 31,  
     2015      2014  

Operating wind farms

   $ 3,237,603       $ 2,624,640   

Furniture, fixtures and equipment

     4,232         4,366   

Land

     307         141   
  

 

 

    

 

 

 

Subtotal

     3,242,142         2,629,147   

Less: accumulated depreciation

     (429,939      (278,291
  

 

 

    

 

 

 

Property, plant and equipment, net

   $ 2,812,203       $ 2,350,856   
  

 

 

    

 

 

 

The Company recorded depreciation expense related to property, plant and equipment of $33.2 million and $62.5 million for the three and six months ended June 30, 2015, respectively, and recorded $20.9 million and $41.8 million of depreciation expense for the same periods in the prior year.

The cash grants in lieu of investment tax credits received from the U.S. Department of the Treasury for Ocotillo, Santa Isabel and Spring Valley reduced depreciation expense recorded in the consolidated statements of operations by approximately $2.9 million and $5.7 million for the three and six months ended June 30, 2015, respectively, and reduced depreciation expense by $3.2 million and $6.3 million for the same periods in the prior year.

 

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6. Finite-Lived Intangible Assets and Liability

The following presents the major components of the finite-lived intangible assets and liability (in thousands):

 

     June 30, 2015  
     Weighted Average
Remaining Life
     Gross      Accumulated
Amortization
     Net  

Intangible assets

           

Power purchase agreement

     15       $ 97,400       $ (837    $ 96,563   

Other intangible assets

     17         4,759         (240      4,519   
     

 

 

    

 

 

    

 

 

 

Total intangible assets

      $ 102,159       $ (1,077    $ 101,082   
     

 

 

    

 

 

    

 

 

 

Intangible liability

           

Power purchase agreement

     17       $ (60,300    $ 434       $ (59,866
     

 

 

    

 

 

    

 

 

 
     December 31, 2014  
     Weighted Average
Remaining Life
     Gross      Accumulated
Amortization
     Net  

Other intangible assets

     17       $ 1,411       $ (154    $ 1,257   
     

 

 

    

 

 

    

 

 

 

The Company amortizes the PPA asset and PPA liability in electricity sales in the consolidated statements of operations and recorded $0.8 million and ($0.4) million, respectively, for each of the three and six months ended June 30, 2015.

The following table presents estimated future amortization expense for the next five years related to PPAs and other intangible assets:

 

     Power      Other  
     purchase      intangible  

Year ended December 31,

   agreements      assets  

2015

   $ 1,543       $ 97   

2016

     3,049         276   

2017

     3,031         351   

2018

     3,031         276   

2019

     3,031         276   

Thereafter

     23,012         3,243   

 

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7. Unconsolidated Investments

The following presents projects that are accounted for under the equity method of accounting (in thousands):

 

                   Percentage of Ownership  
     June 30,      December 31,      June 30,     December 31,  
     2015      2014      2015     2014  

South Kent

   $ 9,991       $ 17,360         50.0     50.0

Grand

     12,792         11,719         45.0     45.0

K2

     124,861         —           33.3     N/A   
  

 

 

    

 

 

      

Unconsolidated investments

   $ 147,644       $ 29,079        
  

 

 

    

 

 

      

South Kent

The Company is a noncontrolling investor in a joint venture established to develop, construct, and own a wind power project located in Ontario, Canada. The project has a 20-year PPA, and commenced commercial operations in March 2014.

Grand

The Company is a noncontrolling investor in a joint venture established to develop, construct, and own a wind power project located in Ontario, Canada. The project has a 20-year PPA and commenced commercial operations in December 2014.

El Arrayán

On June 25, 2014, the Company increased its total ownership interest in El Arrayán to 70%. Refer to Note 3, Acquisitions , for disclosure on the acquisition of El Arrayán. As such, the Company has consolidated the operations of El Arrayán as of the acquisition date and is no longer accounting for this investment under the equity method of accounting.

K2

The Company is a noncontrolling investor in a joint venture established to develop, construct and own a wind power project located in Ontario, Canada. The project has a 20-year PPA and commenced commercial operations in May 2015. Refer to Note 3, Acquisitions , for disclosure on the acquisition of K2.

The following table summarizes the aggregated operating results of the unconsolidated joint ventures for the three and six months ended June 30, 2015 and 2014, respectively (in thousands):

 

     Three months ended June 30,      Six months ended June 30,  
     2015      2014      2015      2014  

Revenue

   $ 42,155       $ 27,179       $ 86,786       $ 28,696   
  

 

 

    

 

 

    

 

 

    

 

 

 

Cost of revenue

     15,361         10,333         27,676         11,072   

Operating expenses

     2,908         1,747         5,314         1,704   

Other (income) expense

     (6,842      23,059         28,449         49,546   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income (loss)

   $ 30,728       $ (7,960    $ 25,347       $ (33,626
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Significant Equity Method Investees

The following table presents summarized statements of operations information for the three and six months ended June 30, 2015 and 2014, in thousands, as required for each of the Company’s significant equity method investees, South Kent and Grand, pursuant to Regulation S-X Rule 10-01(b)(1). :

South Kent

 

     Three months ended June 30,      Six months ended June 30,  
     2015      2014      2015      2014  

Revenue

   $ 20,210       $ 25,358       $ 52,746       $ 26,875   
  

 

 

    

 

 

    

 

 

    

 

 

 

Cost of revenue

     6,733         10,333         15,122         11,072   

Operating expenses

     1,152         1,613         2,707         1,462   

Other (income) expense

     (9,208      17,446         19,432         39,225   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income (loss)

   $ 21,533       $ (4,034    $ 15,485       $ (24,884
  

 

 

    

 

 

    

 

 

    

 

 

 

Grand

 

     Three months ended June 30,      Six months ended June 30,  
     2015      2014      2015      2014  

Revenue

   $ 14,683       $ —         $ 26,778       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Cost of revenue

     5,429         —           9,355         —     

Operating expenses

     1,182         133         2,033         241   

Other expense

     562         2,858         7,213         7,238   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income (loss)

   $ 7,510       $ (2,991    $ 8,177       $ (7,479
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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8. Accounts Payable and Other Accrued Liabilities

The following table presents the components of accounts payable and other accrued liabilities (in thousands):

 

     June 30,      December 31,  
     2015      2014  

Accounts payable

   $ 1,066       $ 673   

Other accrued liabilities

     11,360         7,892   

Warranty settlement payments

     1,706         639   

LTSA upgrades liability

     814         680   

Turbine operations and maintenance payable

     705         1,310   

Land lease rent payable

     955         2,115   

Payroll liabilities

     3,182         4,453   

Property tax payable

     7,815         4,625   

Sales tax payable

     1,670         2,406   
  

 

 

    

 

 

 

Accounts payable and other accrued liabilities

   $ 29,273       $ 24,793   
  

 

 

    

 

 

 

9. Revolving Credit Facility

As of June 30, 2015 and December 31, 2014, outstanding loan balances under the $350.0 million revolving credit facility were $250.0 million and $50.0 million, respectively. In addition, as of June 30, 2015 and December 31, 2014, letters of credit of $49.2 million and $45.1 million, respectively, were issued under the revolving credit facility.

10. Long-term Debt

The Company’s long-term debt, which consists of limited recourse or nonrecourse indebtedness, is presented below, as of June 30, 2015 and December 31, 2014 (in thousands):

 

    As of June 30, 2015    
          Unamortized           Contractual     Effective     Contractual    
    Principal     Financing Cost     Net     Interest Rate     Interest Rate     Interest Type   Maturity

Hatchet Ridge term loan

  $ 220,152      $ (2,409   $ 217,743        1.43     1.43   Imputed   December 2032

Gulf Wind term loan

    154,076        (4,011     150,065        3.28     6.59 % (1)     Variable   March 2020

St. Joseph term loan

    172,550        (843     171,707        5.88     5.95   Fixed   May 2031

Spring Valley term loan

    164,344        (5,905     158,439        2.65     5.51 % (1)     Variable   June 2030

Santa Isabel term loan

    111,746        (4,066     107,680        4.57     4.57   Fixed   September 2033

El Arrayán commercial term loan

    98,354        (91     98,263        2.94     5.64 % (1)     Variable   March 2029

El Arrayán EKF term loan

    108,190        (101     108,089        5.56     5.56   Fixed   March 2029

Ocotillo commercial term loan

    221,075        (6,408     214,667        2.03     3.92 % (1)     Variable   August 2020

Ocotillo development term loan

    102,780        (2,979     99,801        2.38     4.55 % (1)     Variable   August 2033

Logan’s Gap construction loan

    183,642        (2,341     181,301        1.57     1.57 % (1)     Variable   December 2015

Amazon Wind (Fowler Ridge) construction loan

    81,233        (3,895     77,338        1.62     1.62 % (1)     Variable   December 2015

Lost Creek term loan

    114,786        —          114,786        3.15     6.52 % (1)     Variable   March 2021
 

 

 

   

 

 

   

 

 

         
    1,732,928        (33,049     1,699,879           

Add: unamortized premium

    1,482        —          1,482           

Less: current portion (including construction loans)

    (342,392     10,166        (332,226        
 

 

 

   

 

 

   

 

 

         
  $ 1,392,018      $ (22,883   $ 1,369,135           
 

 

 

   

 

 

   

 

 

         

 

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    As of December 31, 2014    
          Unamortized           Contractual     Effective     Contractual    
    Principal     Financing Cost     Net     Interest Rate     Interest Rate     Interest Type   Maturity

Hatchet Ridge term loan

  $ 228,288      $ (2,546   $ 225,742        1.43     1.43   Imputed   December 2032

Gulf Wind term loan

    156,122        (4,360     151,762        3.23     6.59 % (1)     Variable   March 2020

St. Joseph term loan

    189,472        (960     188,512        5.88     5.95   Fixed   May 2031

Spring Valley term loan

    167,261        (6,232     161,029        2.62     5.51 % (1)     Variable   June 2030

Santa Isabel term loan

    112,609        (4,240     108,369        4.57     4.57   Fixed   September 2033

El Arrayán commercial term loan

    99,665        (94     99,571        2.92     5.64 % (1)     Variable   March 2029

El Arrayán EKF term loan

    109,630        (103     109,527        5.56     5.56   Fixed   March 2029

Ocotillo commercial term loan

    222,175        (7,021     215,154        1.98     3.92 % (1)     Variable   August 2020

Ocotillo development term loan

    106,700        (3,372     103,328        2.33     4.55 % (1)     Variable   August 2033

Logan’s Gap construction loan

    58,691        (7,827     50,864        1.64     1.64   Variable   December 2015
 

 

 

   

 

 

   

 

 

         
    1,450,613        (36,755     1,413,858           

Less: current portion (including construction loans)

    (121,561     11,868        (109,693        
 

 

 

   

 

 

   

 

 

         
  $ 1,329,052      $ (24,887   $ 1,304,165           
 

 

 

   

 

 

   

 

 

         

 

(1) Includes impact of interest rate derivatives. Refer to Note 12, Derivative Instruments , for discussion of interest rate derivatives.

The following table presents a reconciliation of interest expense presented in the Company’s consolidated statements of operations for the three and six months ended June 30, 2015 and 2014 (in thousands):

 

     Three months ended June 30,      Six months ended June 30,  
     2015      2014      2015      2014  

Interest and commitment fees incurred

   $ 18,136       $ 13,850       $ 34,568       $ 27,307   

Capitalized interest, commitment fees, and letter of credit fees

     (2,258      (597      (3,573      (1,880

Letter of credit fees incurred

     1,172         1,100         2,233         2,153   

Amortization of financing costs

     1,893         1,454         3,633         2,848   
  

 

 

    

 

 

    

 

 

    

 

 

 

Interest expense

   $ 18,943       $ 15,807       $ 36,861       $ 30,428   
  

 

 

    

 

 

    

 

 

    

 

 

 

Gulf Wind

On June 26, 2015, the Company received a one-month extension of the scheduled term loan principal repayment of approximately $5.6 million, due on June 30, 2015, until July 31, 2015. The scheduled interest payment of approximately $2.6 million due on June 30, 2015 was paid on schedule as required by the Credit Agreement. Subsequent to June 30, 2015, the Company acquired the noncontrolling interest in the Gulf Wind project and prepaid the outstanding balance of the Gulf Wind project’s term loan facility. Refer to Note 22, Subsequent Events , for additional information.

Lost Creek

On October 22, 2009, Lost Creek entered into a $231.5 million credit facility that provided construction financing, a letter of credit facility and a term loan facility. In 2010, the construction facility was partially repaid through proceeds from a $107.7 million government grant and the remaining $123.3 million was repaid through a term loan. The letter of credit facility was released upon achieving commercial operations. On April 5, 2011, Lost Creek entered into an Amended and Restated Credit Agreement (“Amended Credit Agreement”), replacing the existing credit facility. The existing term loan was refinanced and increased by $23.0 million, for an aggregate term loan of $144.0 million, maturing on March 31, 2021. In connection with the term loan, Lost Creek entered into interest rate swaps for the term of the loan to hedge its exposure to variable interest over the term of the facility and to hedge its exposure to re-financing rate risk.

The term loan is a LIBOR loan and accrues interest at LIBOR plus an applicable margin of 2.5% during the period commencing on the effective date of the term loan and increasing by 0.25% on every third anniversary of the effective date of the term loan, ending on the day prior to the ninth anniversary date.

Collateral under the Lost Creek Amended Credit Agreement includes a collateral account agreement that requires proceeds from the sale of energy from the Lost Creek wind project be remitted directly to the depositary agent of the Amended Credit Agreement to provide for debt service payments and operating costs required under the Amended Credit Agreement.

 

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The Amended Credit Agreement is subject to certain covenants, including limitations on additional indebtedness, limitations on liens, requirements for periodic financial and operational information, and compliance with certain required financial ratios. The Amended Credit Agreement also contains voluntary prepayment provisions which provide for the right to prepay the term loan without premium or penalty and contains mandatory prepayments for such events as upwind array events. As of June 30, 2015, there has been no requirement to make any such mandatory prepayments of amounts borrowed under the term loan. Additionally, the Amended Credit Agreement restricts payment of dividends, distributions, and returns of capital to affiliates of Lost Creek unless provided by the Amended Credit Agreement.

Amazon Wind Farm (Fowler Ridge)

On April 29, 2015, Amazon Wind Farm (Fowler Ridge) entered into a $199.1 million construction loan facility and $22.5 million of letter of credit facilities, as required by the PPA and renewable energy credit agreement. Under the financing agreement, the construction loan facility will be repaid at the earlier of commercial operations or February 29, 2016, the scheduled maturity date, through capital contributions from both the equity investors and the Company. The Company also entered into a Letter of Credit, Reimbursement and Loan Agreement pursuant to which the $11.2 million REC letter of credit facility expires on April 29, 2016 and the $11.3 million PPA letter of credit facility expires on April 29, 2020.

Collateral under the Amazon Wind Farm (Fowler Ridge) financing agreement consists of Amazon Wind Farm (Fowler Ridge)’s tangible assets and contractual rights, and a cash on deposit with the depository agent. The loan agreement contains a broad range of covenants that, subject to certain exceptions, restrict Amazon Wind Farm (Fowler Ridge)’s ability to incur debt, grant liens, sell or lease assets, transfer equity interests, dissolve, pay distributions and change its business.

11. Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated cost of decommissioning the turbines, removing above-ground installations and restoring the sites at the end of its estimated economic useful life. Effective January 1, 2015, the Company changed its estimate of the useful lives of wind farms for which construction began after 2011, from 20 years to 25 years. As a result, during the six months ended June 30, 2015, the Company recorded a one-time adjustment of $1.9 million to reduce the carrying balance of the asset retirement obligations to reflect the change in estimate associated with the timing of the original undiscounted cash flows.

The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligations as of June 30, 2015 and 2014 (in thousands):

 

     Six months ended June 30,  
     2015      2014  

Beginning asset retirement obligations

   $ 29,272       $ 20,834   

Net additions during the year

     10,811         4,912   

Foreign currency translation adjustment

     (177      5   

Adjustment related to change in useful life

     (1,907      —     

Accretion expense

     941         643   
  

 

 

    

 

 

 

Ending asset retirement obligations

   $ 38,940       $ 26,394   
  

 

 

    

 

 

 

12. Derivative Instruments

The Company employs derivative instruments to manage its exposure to fluctuations in currency exchange rates, interest rates and electricity prices. The Company’s objectives for holding these derivative instruments include reducing, eliminating and efficiently managing the economic impact of these exposures as effectively as possible.

 

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The following tables present the amounts that are recorded in the Company’s financial statements (in thousands):

Undesignated Derivative Instruments Classified as Assets (Liabilities):

 

                          For the period ended  
              Fair Market Value     QTD Gain (Loss)     YTD Gain (Loss)  
                          Recognized into     Recognized into  

Derivative Type

  Quantity     Maturity Dates   Current Portion     Long-Term Portion     Income     Income  

June 30, 2015

           

Interest rate swaps

    6      6/30/2030   $ (3,212   $ 4,467      $ 5,239      $ 2,135   

Interest rate cap

    1      12/31/2024     —          330        (54     (22

Energy derivative

    1      4/30/2019     18,131        43,314        (6,002     (3,030

Foreign currency forward contracts

    13      Various through

3/31/2017

    284        107        (240     391   

Interest rate swaps

    5      9/30/2015     (1,634     —          (7     (7

Interest rate swaps

    5      3/31/2021     (552     (849     81        81   
     

 

 

   

 

 

   

 

 

   

 

 

 
      $ 13,017      $ 47,369      $ (983   $ (452
     

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2014

           

Interest rate swaps

    6      6/30/2030   $ (3,403   $ 2,523      $ (5,040   $ (11,339

Interest rate cap

    1      12/31/2024     —          352        (29     (329

Energy derivative

    1      4/30/2019     18,506        45,969        7,265        (3,878
     

 

 

   

 

 

   

 

 

   

 

 

 
      $ 15,103      $ 48,844      $ 2,196      $ (15,546
     

 

 

   

 

 

   

 

 

   

 

 

 

June 30, 2014

           

Interest rate swaps

    6      6/30/2030   $ (3,842   $ 7,897      $ (2,855   $ (6,404

Interest rate cap

    1      12/31/2024     —          420        (87     (261

Energy derivative

    1      4/30/2019     12,449        41,622        (6,549     (14,282
     

 

 

   

 

 

   

 

 

   

 

 

 
      $ 8,607      $ 49,939      $ (9,491   $ (20,947
     

 

 

   

 

 

   

 

 

   

 

 

 

Designated Derivative Instruments Classified as Assets (Liabilities):

 

                            For the period ended  
                Fair Market Value     QTD Gain (Loss)     YTD Gain (Loss)  

Derivative Type

  Quantity     Maturity Dates     Current Portion     Long-Term Portion     Recognized in OCI     Recognized into OCI  

June 30, 2015

           

Interest rate swaps

    6        6/30/2033      $ (1,863   $ 2,136      $ 3,884      $ 1,665   

Interest rate swaps

    3        3/31/2032        (1,747     (2,357     2,152        770   

Interest rate swaps

    7        3/15/2020        (4,466     (6,332     1,664        836   

Interest rate swaps

    2        6/28/2030        (4,247     (5,322     4,928        2,091   

Interest rate swaps

    5        9/30/2027        (2,067     (12,161     868        868   

Interest rate swaps

    5        9/30/2027        —          (474     69        69   
     

 

 

   

 

 

   

 

 

   

 

 

 
      $ (14,390   $ (24,510   $ 13,565      $ 6,299   
     

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2014

           

Interest rate swaps

    6        6/30/2033      $ (1,917   $ 525      $ (3,722   $ (8,912

Interest rate swaps

    3        3/31/2032        (1,822     (3,338     (1,863     (1,983

Interest rate swaps

    7        3/15/2020        (4,719     (6,915     (425     1,094   

Interest rate swaps

    2        6/28/2030        (4,446     (7,214     (3,889     (9,869
     

 

 

   

 

 

   

 

 

   

 

 

 
      $ (12,904   $ (16,942   $ (9,899   $ (19,670
     

 

 

   

 

 

   

 

 

   

 

 

 

June 30, 2014

           

Interest rate swaps

    6        6/30/2033      $ (2,105   $ 4,869      $ (1,998   $ (4,756

Interest rate swaps

    3        3/31/2032        (1,915     (673     (116     (116

Interest rate swaps

    7        3/15/2020        (5,136     (7,943     (377     (351

Interest rate swaps

    2        6/28/2030        (4,806     (3,230     (3,056     (6,246
     

 

 

   

 

 

   

 

 

   

 

 

 
      $ (13,962   $ (6,977   $ (5,547   $ (11,469
     

 

 

   

 

 

   

 

 

   

 

 

 

Gulf Wind

In 2010, Gulf Wind entered into interest rate swaps with each of its lenders to manage exposure to interest rate risk on its long-term debt. The fixed interest rate is set at 6.6% for years two through eight and 7.1% and 7.6% for the last two years of the loan term, respectively. The interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three and six months ended June 30, 2015 and 2014, respectively. The Company reclassified $1.3 million and $2.6 million related to cash settlements into net loss from accumulated other comprehensive loss during the three and six months ended

 

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June 30, 2015, respectively, and $1.4 million and $2.8 million for the same periods in the prior year. The Company estimates that $4.5 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months. Subsequent to June 30, 2015, the Company terminated the interest rate swaps. Refer to Note 22, Subsequent Events , for additional information.

In 2010, Gulf Wind also entered into an interest rate cap to manage exposure to future interest rates when its long-term debt is expected to be refinanced at the end of the ten-year term. The cap protects the Company if future interest rates exceed approximately 6.0%. The cap has an effective date of March 31, 2020, terminates on December 31, 2024, and has a notional amount of $42.1 million, which reduces quarterly during its term. The cap is a derivative but does not qualify for hedge accounting and has not been designated. The Company recognized immaterial unrealized losses for each of the three and six months ended June 30, 2015, respectively, and $0.1 million and $0.3 million for the same periods in the prior year, in unrealized loss on derivatives, net in the consolidated statements of operations. Subsequent to June 30, 2015, the Company terminated the interest rate cap. Refer to Note 22, Subsequent Events , for additional information.

In 2010, Gulf Wind acquired an energy derivative instrument to manage its exposure to variable electricity prices. The energy price swap fixes the price of approximately 58% of its electricity generation through April 2019. The energy derivative instrument is a derivative but did not meet the criteria required to adopt hedge accounting. The energy derivative instrument’s fair value as of June 30, 2015 and December 31, 2014 was $61.4 million and $64.5 million, respectively. Gulf Wind recognized unrealized losses of $6.0 million and $3.0 million for the three and six months ended June 30, 2015, respectively, and unrealized losses of $6.5 million and $14.3 million for the same periods in the prior year, in unrealized loss on energy derivative in the consolidated statement of operations.

Spring Valley

In 2011, Spring Valley entered into interest rate swaps with its lenders to manage exposure to interest rate risk on its long-term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 5.5% for the first four years of its term debt and increases by 0.25% every four years, thereafter. The interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three and six months ended June 30, 2015 and 2014, respectively. The Company reclassified $1.2 million and $2.4 million related to cash settlements into net loss from accumulated other comprehensive loss during the three and six months ended June 30, 2015, respectively, and $1.3 million and $2.5 million for the same periods in the prior year. The Company estimates that $4.2 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months.

Ocotillo

In October 2012, Ocotillo entered into interest rate swaps with its lenders to manage exposure to interest rate risk on its long-term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 2.5% and 2.2% for the development bank term loans and the commercial bank term loans, respectively. The fixed interest rate payments of the commercial bank term loan will increase by 0.25% on the fourth anniversary of the closing date. The interest rate swaps for the development bank loans qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three and six months ended June 30, 2015 and 2014, respectively. The Company reclassified $0.5 million and $1.1 million related to cash settlements into net loss from accumulated other comprehensive loss during each of the three and six months ended June 30, 2015, respectively, and $0.5 million and $1.0 million for the same periods in the prior year. The Company estimates that $1.9 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months. The interest rate swaps for the commercial bank loans are undesignated derivatives that are used to mitigate exposure to variable interest rate debt.

El Arrayán

In May 2012, El Arrayán entered into three interest rate swaps with its lenders to manage exposure to interest rate risk on its long-term debt. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 3.4% for the first two years of its term debt and subsequently increased to 5.8%, and increases by 0.25% on every fourth anniversary of the closing date, thereafter. The interest rate swaps qualify for hedge accounting and were designated as cash flow hedges. No ineffectiveness was recorded for the three and six months ended June 30, 2015 and 2014, respectively. The Company reclassified $0.4 million and $0.9 million related to cash settlements into net loss from accumulated other comprehensive loss, net of tax, during the three and six months ended June 30, 2015, respectively. The Company reclassified $0.2 million, net of tax, related to cash settlements into net loss from accumulated other comprehensive income for each of the three and six months ended June 30, 2014. The Company estimates that $1.7 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months.

 

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Lost Creek

In September 2010, Lost Creek entered into interest rate swaps with its lenders to manage exposure to its interest rate risk on its long-term debt and anticipated refinancing. The interest rate swaps exchange variable interest rate payments for fixed interest rate payments of approximately 3.77% for the initial five-year period of the term loan. Lost Creek also entered into interest rate swaps to exchange variable interest rate payments for fixed interest rate payments of approximately 5.10%, for the anticipated refinancing of the balloon payment in 2015, over a 12-year period. In April 5, 2011, Lost Creek entered into an amended and restated credit facility to increase the term loan by $23.0 million to an aggregate term loan of $144.0 million. As a result, Lost Creek entered into additional interest rate swaps on the additional loan amount of $23.0 million, exchanging variable interest rate payments for fixed interest payments of 3.51% over a 10-year period and exchanging variable interest rate payments for fixed interest rate payments of 5.58% for the anticipated refinancing of the balloon payment of the amended term loan in March 2021 through September 2027.

As a result of the Wind Capital acquisition, interest rate swaps related to the anticipated refinancing of the term loan were designated as cash flow hedges. During the three and six months ended June 30, 2015, the Company recorded ineffectiveness of $0.1 million, respectively, related to the designated cash flow hedges. The interest rate swaps related to the initial long-term debt maturing in September 2015 and additional term loan maturing in March 2021 have been de-designated as they do not qualify for cash flow hedge accounting.

During the three and six months ended June 30, 2015, there were no cash settlements related to the designated derivatives at Lost Creek. The Company estimates that $2.1 million in accumulated other comprehensive loss will be reclassified into earnings within the next twelve months.

Foreign Currency Forward Contracts

In January 2015, the Company established a currency risk management program. The objective of the program is to mitigate the foreign exchange rate risk arising from transactions or cash flows that have a direct or underlying exposure in non-U.S. dollar denominated currencies in order to reduce volatility in the Company’s cash flow, which may have an adverse impact to our short-term liquidity or financial condition. A majority of the Company’s power sale agreements and operating expenditures are transacted in U.S. dollars, with a growing portion transacted in currencies other than the U.S. dollar, primarily the Canadian dollar. In 2015, the Company entered into foreign currency forward contracts to mitigate the currency exchange rate risk on Canadian dollar denominated cash flows. These instruments have an initial maturity ranging from five to twenty-three months. The foreign currency forward contracts are considered non-designated derivative instruments and are not used for trading or speculative purposes.

As of June 30, 2015, the total notional amount of foreign currency forward contracts outstanding was C$57.6 million and the total fair value of these contracts was $0.4 million. For the three and six months ended June 30, 2015, the Company recognized a change in fair value of the foreign currency forward contracts of $(0.2) million and $0.4 million, respectively, in unrealized loss on derivatives, net in the consolidated statement of operations.

13. Accumulated Other Comprehensive Loss

The following tables summarize the changes in the accumulated other comprehensive loss balance by component, net of tax, for the six months ended June 30, 2015 and 2014 (in thousands):

 

           Effective Portion of     Proportionate        
     Foreign     Change in Fair Value     Share of Equity        
     Currency     of Derivatives     Investee’s OCI     Total  

Balances at December 31, 2014

   $ (19,338   $ (26,672   $ (7,903   $ (53,913

Other comprehensive loss before reclassifications

     (9,692     (657     (2,382     (12,731

Amounts reclassified from accumulated other comprehensive loss

     —          6,956        1,045        8,001   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net current period other comprehensive loss

     (9,692     6,299        (1,337     (4,730
  

 

 

   

 

 

   

 

 

   

 

 

 

Balances at June 30, 2015

   $ (29,030   $ (20,373   $ (9,240   $ (58,643
  

 

 

   

 

 

   

 

 

   

 

 

 
           Effective Portion of     Proportionate        
     Foreign     Change in Fair Value     Share of Equity        
     Currency     of Derivatives     Investee’s OCI     Total  

Balances at December 31, 2013

   $ (8,463   $ (7,002   $ (1,912   $ (17,377

Other comprehensive loss before reclassifications

     (869     (17,989     (4,283     (23,141

Amounts reclassified from accumulated other comprehensive loss

     —          6,520        —          6,520   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net current period other comprehensive loss

     (869     (11,469     (4,283     (16,621
  

 

 

   

 

 

   

 

 

   

 

 

 

Balances at June 30, 2014

   $ (9,332   $ (18,471   $ (6,195   $ (33,998
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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Amounts reclassified from accumulated other comprehensive loss into income for the effective portion of change in fair value of derivatives is recorded to interest expense in the consolidated statements of operations. Amounts reclassified from accumulated other comprehensive loss into income for the Company’s proportionate share of equity investee’s other comprehensive loss is recorded to equity in losses in unconsolidated investments in the consolidated statements of operations.

14. Fair Value Measurements

Short-term financial instruments consist principally of cash and cash equivalents, restricted cash, trade receivables, related party receivable/payable, reimbursable interconnection costs, accounts payable and other accrued liabilities, accrued construction costs,

accrued interest, dividends payable and current portion of contingent liabilities. Based on the nature and short maturity of these instruments, their fair value is approximated using carrying cost and they are presented in the Company’s financial statements at carrying cost. The fair values of cash and cash equivalents and restricted cash are classified as Level 1 in the fair value hierarchy. The fair values of trade receivables, related party receivable/payable, reimbursable interconnection costs, accounts payable and other accrued liabilities, accrued construction costs, accrued interest and dividends payable are classified as Level 2 in the fair value hierarchy.

The Company’s financial assets and (liabilities) which require fair value measurement on a recurring basis are classified within the fair value hierarchy as follows (in thousands):

 

     Fair Value  
     Level 1      Level 2      Level 3      Total  

June 30, 2015

           

Interest rate swaps

   $ —         $ (40,680    $ —         $ (40,680

Interest rate cap

     —           330         —           330   

Energy derivative

     —           —           61,445         61,445   

Foreign currency forward contracts

     —           391         —           391   

Contingent liabilities

     —           —           (1,320      (1,320
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ —         $ (39,959    $ 60,125       $ 20,166   
  

 

 

    

 

 

    

 

 

    

 

 

 

December 31, 2014

           

Interest rate swaps

   $ —         $ (30,726    $ —         $ (30,726

Interest rate cap

     —           352         —           352   

Energy derivative

     —           —           64,475         64,475   

Contingent liabilities

     —           —           (175      (175
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ —         $ (30,374    $ 64,300       $ 33,926   
  

 

 

    

 

 

    

 

 

    

 

 

 

Level 2 Inputs

Derivative instruments subject to remeasurement are presented in the financial statements at fair value. The Company’s interest rate swaps and interest rate cap were valued by discounting the net cash flows using the forward LIBOR curve with the valuations adjusted by the Company’s credit default hedge rate. The Company’s foreign currency forward contracts were valued using the income approach based on the present value of the forward rates less the contract rates, multiplied by the notional amounts. There were no transfers between Level 1 and Level 2 during the periods presented.

Level 3 Inputs

Energy Derivative

The energy derivative instrument is valued by discounting the projected net cash flows over the remaining life of the derivative instrument using forward energy curves adjusted by a nonperformance risk factor. The significant unobservable input in calculating the fair value of the energy derivative instrument is forward electricity prices, which are derived from and impacted by changes in forward natural gas prices. Significant increases or decreases in this unobservable input would result in a significantly lower or higher fair value measurement.

The following table presents a reconciliation of the energy derivative contract measured at fair value, in thousands, on a recurring basis using significant unobservable inputs (Level 3) for the six months ended June 30, 2015 and 2014, respectively. There were no transfers between Level 2 and Level 3 during the periods presented.

 

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     Energy Derivative  
     Six months ended June 30,  
     2015      2014  

Balances, beginning of period

   $ 64,475       $ 68,353   

Settlements

     (12,097      (6,718

Change in fair value

     9,067         (7,564
  

 

 

    

 

 

 

Balances, end of period

   $ 61,445       $ 54,071   
  

 

 

    

 

 

 

Contingent Liabilities

The Company’s contingent liabilities relate to turbine availability guarantees associated with long-term turbine service arrangements with its turbine service and maintenance providers. Pursuant to these guarantees, if a turbine operates at less than minimum availability during the guarantee period, the service provider is obligated to pay, as liquidated damages, an amount for each percent that the turbine operates below the minimum availability threshold. In addition, pursuant to certain of these guarantees, if a turbine operates at more than a specified availability during the guarantee period, the Company has an obligation to pay a bonus to the service provider. The fair value of the contingent liabilities is based on actual and forecasted data. The significant unobservable inputs in calculating the fair value of the contingent liabilities are the forecasted turbine availability percentages.

The following table presents a reconciliation of contingent liabilities measured at fair value, in thousands, on a recurring basis using significant unobservable inputs (Level 3) for the six months ended June 30, 2015 and 2014, respectively. There were no transfers between Level 2 and Level 3 during the periods presented.

 

     Contingent Liabilities  
     Six months ended June 30,  
     2015      2014  

Balances, beginning of period

   $ (175    $ —     

Payments

     —           —     

Change in estimate

     (1,145      —     
  

 

 

    

 

 

 

Balances, end of period

   $ (1,320    $ —     
  

 

 

    

 

 

 

The following table presents the carrying amount and fair value, in thousands, and the fair value hierarchy of the Company’s financial liabilities that are not measured at fair value in the consolidated balance sheets as of June 30, 2015 and December 31, 2014, but for which fair value is disclosed.

 

     As reflected on      Fair Value  
     the balance sheet      Level 1      Level 2      Level 3      Total  

June 30, 2015

              

Long-term debt, including current portion

   $ 1,701,361       $ —         $ 1,656,070       $ —         $ 1,656,070   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

December 31, 2014

              

Long-term debt, including current portion

   $ 1,413,858       $ —         $ 1,416,744       $ —         $ 1,416,744   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Long-term debt is presented on the consolidated balance sheets at amortized cost, net of unamortized deferred financing costs. The fair value of variable interest rate long-term debt is approximated by its carrying cost. The fair value of fixed interest rate long-term debt is estimated based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied, using the net present value of cash flow streams over the term using estimated market rates for similar instruments and remaining terms.

15. Income Taxes

The Company accounts for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of the differences between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The Company recognizes deferred tax assets to the extent that the Company believes these assets are more likely than not to be realized. In making such a determination, the Company considers all available positive and negative evidence, including future reversals of existing

 

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taxable temporary differences, projected future taxable income, tax-planning and results of recent operations. If the Company determines that it would be able to realize 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 Company files income tax returns in various jurisdictions and is subject to examination by various tax authorities. The Company records uncertain tax positions in accordance with ASC 740 on the basis of a two-step process whereby (1) the Company 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 Company recognizes the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with the related tax authority. The Company has a policy to classify interest and penalties associated with uncertain tax positions together with the related liability, and the expenses incurred related to such accruals, if any, are included as a component of income tax expense.

16. Stockholders’ Equity

Common Stock

On February 9, 2015, the Company completed an underwritten public offering of its Class A common stock. In total, 12,000,000 shares of the Company’s Class A common stock were sold. Of this amount, the Company issued and sold 7,000,000 shares of its Class A common stock and Pattern Development, the selling stockholder, sold 5,000,000 shares of Class A common stock. The Company received net proceeds of approximately $196.2 million after deducting underwriting discounts and commissions and estimated offering expenses payable by the Company. The Company did not receive any proceeds from the sale of shares sold by Pattern Development.

Dividends

The following table presents cash dividends declared on Class A common stock for the periods presented:

 

     Dividends                       
     Per Share      Declaration Date      Record Date      Payment Date  

2015:

           

Second Quarter

   $ 0.3520         April 20, 2015         June 30, 2015         July 30, 2015   

First Quarter

   $ 0.3420         February 24, 2015         March 31, 2015         April 30, 2015   

Noncontrolling Interests

The following table presents the noncontrolling interest balances, reported in stockholders’ equity in the consolidated balance sheets, by project, as of June 30, 2015 and December 31, 2014 (in thousands):

 

                   Noncontrolling Ownership Percentage  
     June 30,      December 31,      June 30,     December 31  
     2015      2014      2015     2014  

Gulf Wind

   $ 94,946       $ 97,061         60     60

El Arrayán

     34,531         35,624         30     30

Panhandle 1

     200,875         205,333         21     21

Panhandle 2

     189,539         192,568         19     19

Post Rock

     204,300         —           40     N/A   
  

 

 

    

 

 

      

Noncontrolling interest

   $ 724,191       $ 530,586        
  

 

 

    

 

 

      

17. Stock-based Compensation

On April 10, 2015, the Company granted between 0% and 150% of the “Target” (56,844) restricted stock awards (“RSAs”) to certain senior management personnel which vest at the later of three-year performance period (January 1, 2015 – December 31, 2017), or the end of the requisite service period, which shall be no later than March 15, 2018, in accordance with the level of Total Shareholder Return achieved relative to a peer group during the specified period. Following the date of grant, rights to dividends will accrue on the maximum number of shares and may be forfeited if the market or service conditions are not achieved.

 

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The Company measures the fair value of the RSA’s at the grant date using a Monte Carlo simulation model and recognizes stock-based compensation over the longer of the requisite service period or performance period. For the three and six months ended June 30, 2015, the total stock-based compensation expense for market-based restricted stock awards was approximately $0.2 million.

Total stock-based compensation expense related to restricted stock awards, restricted stock units and stock options for the three and six months ended June 30, 2015 was $1.2 million and $2.0 million, respectively, and $1.6 million and $2.2 million for the same periods in the prior year, respectively.

18. Earnings (Loss) per Share

The Company computes basic earnings (loss) per share using net income (loss) attributable to controlling interest to Class A common stockholders and the weighted average number of Class A common shares outstanding during the period. The Company computes diluted earnings (loss) per share using net income (loss) attributable to controlling interest to Class A common stockholders and the weighted average number of common shares outstanding plus potentially dilutive securities outstanding for the period.

Potentially dilutive securities are determined by applying the treasury stock method to the assumed exercise of in-the-money stock options and the assumed vesting of outstanding restricted stock awards and release of restricted stock units.

On December 31, 2014, the Company’s Class B common stock was converted to Class A common stock on a one-to-one basis. For the three and six months ended June 30, 2014, the Company computed Class A and Class B basic loss per share using the two-class method and computed diluted loss per share for Class A and Class B common stock using either the two-class method or the if-converted method, whichever was more dilutive.

The computations for Class A basic and diluted earnings (loss) per share are as follows (in thousands except share data):

 

     Three months ended June 30,      Six months ended June 30,  
     2015      2014      2015      2014  

Numerator for basic and diluted earnings (loss) per share:

           

Net income (loss) attributable to controlling interest

   $ 14,317       $ 11,199       $ (5,582    $ (3,690

Less: dividends declared on Class A common shares

     (24,380      (14,981      (48,003      (26,138

Less: deemed dividends on Class B common shares

     —           (7,457      —           (7,457
  

 

 

    

 

 

    

 

 

    

 

 

 

Net loss attributable to common stockholders

   $ (10,063    $ (11,239    $ (53,585    $ (37,285

Denominator for earnings (loss) per share:

           

Weighted average number of shares:

           

Class A common stock—basic

     68,943,707         41,174,697         67,426,286         38,331,595   

Add dilutive effect of:

           

Stock options

     67,564         107,979         59,517         100,814   

Restricted stock awards

     126,558         227,543         115,079         227,543   

Restricted stock units

     9,431         —           16,703         —     

Class B common stock

     —           15,555,000         —           15,555,000   
  

 

 

    

 

 

    

 

 

    

 

 

 

Class A common stock—fully diluted

     69,147,260         57,065,219         67,617,585         54,214,952   

Less: antidilutive securities

           

Stock options

     —           —           (59,517      (100,814

Restricted stock awards

     —           —           (115,079      (227,543

Restricted stock units

     —           —           (16,703      —     

Class B common stock

     —           (15,555,000      —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Class A common stock—diluted (excluding antidilutive securities)

     69,147,260         41,510,219         67,426,286         53,886,595   

Class B common stock—basic and diluted

     —           15,555,000         —           15,555,000   

Calculation of basic and diluted earnings (loss) per share:

           

Class A common stock:

           

Dividends

   $ 0.35       $ 0.36       $ 0.71       $ 0.68   

Undistributed loss

     (0.15      (0.20      (0.79      (0.69
  

 

 

    

 

 

    

 

 

    

 

 

 

Basic earnings (loss) per share

   $ 0.21       $ 0.17       $ (0.08    $ (0.01

Class A common stock:

           

Diluted earnings (loss) per share

   $ 0.21       $ 0.16       $ (0.08    $ (0.07
  

 

 

    

 

 

    

 

 

    

 

 

 

Class B common stock:

           

Deemed dividends

   $ —         $ 0.48       $ —         $ 0.48   

Undistributed loss

     —           (0.20      —           (0.69
  

 

 

    

 

 

    

 

 

    

 

 

 

Basic and diluted earnings (loss) per share

   $ —         $ 0.28       $ —         $ (0.21
  

 

 

    

 

 

    

 

 

    

 

 

 

Dividends declared per Class A common share

   $ 0.35       $ 0.32       $ 0.71       $ 0.63   
  

 

 

    

 

 

    

 

 

    

 

 

 

Deemed dividends per Class B common share

   $ —         $ 0.48       $ —         $ 0.48   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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19. Geographic Information

The table below provides information, by country, about the Company’s combined operations. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located (in thousands):

 

     Revenue     Property, Plant and Equipment, net  
     Three months ended June 30,     Six months ended June 30,     June 30,      December 31,  
     2015      2014     2015      2014     2015      2014  

United States

   $ 66,955       $ 54,065      $ 114,730       $ 90,387      $ 2,275,556       $ 1,784,219   

Canada

     9,344         11,024        21,097         24,308        210,568         233,690   

Chile

     8,372         (150     13,710         (139     326,079         332,947   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ 84,671       $ 64,939      $ 149,537       $ 114,556      $ 2,812,203       $ 2,350,856   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

20. Commitments and Contingencies

From time to time, the Company has become involved in claims and legal matters arising in the ordinary course of business. Management is not currently aware of any matters that will have a material adverse effect on the financial position, results of operations, or cash flows of the Company.

Power Sale Agreements

The Company has various PPAs that terminate from 2025 to 2039. The terms of the PPAs generally provide for the annual delivery of a minimum amount of electricity at fixed prices and in some cases include price escalation over the term of the respective PPAs. As of June 30, 2015, under the terms of the PPAs, the Company issued irrevocable letters of credit totaling $88.6 million to ensure its performance for the duration of the PPAs.

Project Finance Agreements

The Company has various project finance agreements that obligate the Company to provide certain reserves to enhance its credit worthiness and facilitate the availability of credit. As of June 30, 2015, the Company issued irrevocable letters of credit totaling $115.1 million, of which $49.2 million was from the Company’s revolving credit facility, to ensure performance under these various project finance agreements.

Land Leases

The Company has entered into various long-term land lease agreements. As of June 30, 2015, total outstanding lease commitments were $305.7 million. During the three and six months ended June 30, 2015, the Company recorded rent expense of $2.7 million and $5.1 million, respectively, in project expense in the consolidated statements of operations. During the three and six months ended June 30, 2014, the Company recorded rent expense of $1.8 million and $3.7 million, respectively, in project expense in the consolidated statements of operations.

Service and Maintenance Agreements

The Company has entered into service and maintenance agreements with third party contractors to provide operations and maintenance services, modifications and upgrades for varying periods over the next eleven years. Based on the terms of these agreements, the third party contractors will receive a daily base fee per turbine that may, or may not, be subject to periodic price adjustments for inflation, over the terms of the agreements. As of June 30, 2015, outstanding commitments with these third party contractors were $367.1 million, including an estimated annual price adjustment for inflation of 2%, where applicable, payable over the full term of these agreements.

Purchase, Construction and Other Commitments

The Company has entered into various commitments with service providers related to the Company’s projects and operations of its business. Outstanding commitments with these vendors, excluding turbine operations and maintenance commitments were $13.9 million as of June 30, 2015. The Company also has construction-related open commitments of $148.7 million as of June 30, 2015. In addition, the Company has a commitment to purchase $6.3 million of wind turbine spare parts from a third party contractor under a maintenance and service agreement.

The Company has total commitments of $8.1 million over approximately the next 20 years to local community and government organizations surrounding certain wind farms.

 

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Purchase and Sales Agreements

On April 29, 2015, the Company acquired 100% of the membership interests in Fowler Ridge IV Wind Farm LLC through the acquisition of Fowler Ridge IV B Member LLC from Pattern Development. Subject to the terms of this agreement, the Company may make additional contingent payments of up to $29.1 million, consisting of a $25.1 million fixed amount and up to $4.0 million as calculated based on final budget to actual amounts, both of which are payable to Pattern Development upon tax equity funding.

In addition, the Company acquired an agreement between Pattern Development and an unrelated third party, whereby the unrelated third party is entitled to 1% of the gross revenue received by the project under the PPA, which is estimated to be approximately $2.6 million over 13 years.

On December 20, 2013, the Company acquired a 45.0% equity interest in Grand from Pattern Development. Subject to the terms of this agreement, to the extent that the project makes a special distribution as result of construction cost underruns, the Company may make an additional contingent payment of up to C$5.0 million, or $4.0 million based on the exchange rate as of June 30, 2015, as calculated based on final budget to actual amounts and distributions payable to Pattern Development upon term conversion.

Turbine Availability Warranties

The Company has various turbine availability warranties from its turbine manufacturers. Pursuant to these warranties, if a turbine operates at less than minimum availability during the warranty period, the turbine manufacturer is obligated to pay, as liquidated damages, an amount for each percent that the turbine operates below the minimum availability threshold. In addition, pursuant to certain of these warranties, if a turbine operates at more than a specified availability during the warranty period, the Company has an obligation to pay a bonus to the turbine manufacturer. As of June 30, 2015, the Company recorded liabilities of $0.5 million associated with bonuses payable to the turbine manufacturers. No such liability was recorded as of June 30, 2014. In 2013, the Company entered into warranty settlements with a turbine manufacturer for blade related wind turbine outages. The warranty settlements provide for total liquidated damage payments of approximately $21.9 million for the year ended December 31, 2013. During the year ended December 31, 2013, the Company received payments of $24.1 million in connection with these warranty settlements. As of June 30, 2015, the Company accrued a liability of $1.7 million related to the maximum potential future refund of liquidated damage payments to this turbine manufacturer. The warranty settlements received, net of the maximum potential future refund to the wind turbine manufacturer, has been recorded as other revenue in the consolidated statements of operations.

Long-Term Service Guarantees

The Company has service guarantees from its turbine service and maintenance providers. These service guarantees are associated with long-term turbine service arrangements which commenced on various dates in 2014 and will commence on various dates in 2015 for certain wind projects. Pursuant to these guarantees, if a turbine operates at less than minimum availability during the guarantee period, the service provider is obligated to pay, as liquidated damages, an amount for each percent that the turbine operates below the minimum availability threshold. In addition, pursuant to certain of these guarantees, if a turbine operates at more than a specified availability during the guarantee period, the Company has an obligation to pay a bonus to the service provider. As of June 30, 2015, the Company recorded liabilities of $0.8 million associated with bonuses payable to service providers.

Contingent Liabilities

In December 2014, the Company recorded a contingent obligation, payable to a third party, related to the acquisition of Logan’s Gap. Pursuant to the agreement, the Company is obligated to pay an additional $4.0 million upon the earlier of commercial operations or tax equity funding, which is expected to occur in the fourth quarter of 2015.

In June 2015, the Company recorded a $7.3 million contingent payment, payable to third-parties, required to connect the Amazon Wind Farm (Fowler Ridge) into an existing transmission line. The estimated contingent payment was accrued when it became probable that the future event would occur, upon close of construction financing. The payment is due upon energization of the transmission line.

Indemnity

The Company provides a variety of indemnities in the ordinary course of business to contractual counterparties and to our lenders and other financial partners. Hatchet Ridge agreed to indemnify the lender that provided financing for Hatchet Ridge against certain tax losses in connection with its sale-leaseback financing transaction in December 2010. The indemnity agreement is effective for the duration of the sale-leaseback financing.

The Company is party to certain indemnities for the benefit of the Spring Valley, Santa Isabel, Ocotillo, Panhandle 1, Panhandle 2, Logan’s Gap and Amazon Wind (Fowler Ridge) project finance lenders and tax equity partners. These indemnity obligations consist principally of indemnities that protect the project finance lenders from the potential effect of any recapture by the U.S. Department of the Treasury of any amount of the Cash Grants previously received by the projects and eligibility of production tax credits. The Cash Grant indemnity obligations guarantee amounts of any Cash Grant made to each of the respective projects that may subsequently be recaptured. In addition, the Company is also party to an indemnity of its Ocotillo project finance lenders in connection with certain legal matters, which is limited to the amount of certain related costs and expenses.

 

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The Company agreed to indemnify unrelated third parties against certain tax losses in connection with monetization of tax credits under the Economic Incentives for the Development of Puerto Rico Act of May 28, 2008 for $7.2 million.

21. Related Party Transactions

From inception to October 1, 2013, the Company’s project management and administrative activities were provided by Pattern Development. Costs associated with these activities were allocated to the Company and recorded in its consolidated statements of operations. Allocated costs include cash and non-cash compensation, other direct, general and administrative costs, and non-operating costs deemed allocable to the Company. Measurement of allocated costs is based principally on time devoted to the Company by officers and employees of Pattern Development. The Company believes the allocated costs presented in its consolidated statements of operations are a reasonable estimate of actual costs incurred to operate the business. The allocated costs are not the result of arms-length, free-market dealings.

Management Services Agreement and Shared Management

Effective October 2, 2013, the Company entered into a bilateral Management Services Agreement with Pattern Development which provides for the Company and Pattern Development to benefit, primarily on a cost-reimbursement basis plus a 5% fee on certain direct costs, from the parties’ respective management and other professional, technical and administrative personnel, all of whom will report to and be managed by the Company’s executive officers. Pursuant to the Management Services Agreement, certain of the Company’s executive officers, including its Chief Executive Officer, will also serve as executive officers of Pattern Development and devote their time to both the Company and Pattern Development as is prudent in carrying out their executive responsibilities and fiduciary duties. The Company’s Chief Executive Officer also serves as the Chief Executive Officer of Pattern Development. The Company refers to the employees who will serve as executive officers of both the Company and Pattern Development as the “shared PEG executives.” The shared PEG executives will have responsibilities for both the Company and Pattern Development and, as a result, these individuals will not devote all of their time to the Company’s business. Under the terms of the Management Services Agreement, Pattern Development is required to reimburse the Company for an allocation of the compensation paid to such executives reflecting the percentage of time spent providing services to Pattern Development.

The following table presents net bilateral management service cost reimbursements included in the consolidated statements of operations (in thousands):

 

     Three months ended June 30,      Six months ended June 30,  
     2015      2014      2015      2014  

Related party general and administrative

   $ 1,621       $ 1,383       $ 3,429       $ 2,663   

Related party income

     (756      (444    $ (1,424      (1,072
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 865       $ 939       $ 2,005       $ 1,591   
  

 

 

    

 

 

    

 

 

    

 

 

 

As of June 30, 2015 and December 31, 2014, the amounts payable to Pattern Development for bilateral management service cost reimbursements were $0.9 million and $0.8 million, respectively. In addition, the Company had a related party receivable of zero and $0.1 million as of June 30, 2015 and December 31, 2014, respectively, for IPO cost reimbursements due from Pattern Development.

Letters of Credit, Indemnities and Guarantees

Pattern Development agreed to guarantee $14.0 million of El Arrayán’s payment obligations to a lender that has provided a $20.0 million credit facility for financing of El Arrayán’s recoverable, construction-period value-added tax payments. The remaining $6.0 million of the credit facility has been guaranteed by another investor in El Arrayán.

Purchase and Sales Agreements

On June 17, 2015, the Company acquired a one-third equity interest in K2 from Pattern Development for a purchase price of approximately $128.0 million, plus assumed estimated proportionate debt at term conversion of approximately $221.8 million, U.S. dollar equivalent. This represents a 90 MW interest in the 270 MW wind project, located in the Township of Ashfield-Colborne-Wawanosh, Ontario.

On April 29, 2015, the Company acquired 100% of the membership interests in Fowler Ridge IV Wind Farm LLC through the acquisition of Fowler Ridge IV B Member LLC from Pattern Development for a purchase price of approximately $37.5 million, paid at closing, in addition to $0.5 million of capitalized transaction expenses. In addition, the Company has contingent payments of up to $29.1 million to Pattern Development payable upon tax equity funding. Amazon Wind Farm (Fowler Ridge) is a 150 MW wind project located in Benton County, Indiana.

 

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On December 19, 2014, the Company acquired 100% of the membership interests in Logan’s Gap from Pattern Development, for a purchase price of approximately $15.1 million. In addition, the Company has a contingent payment of up to $4.0 million to an unrelated third party at the earlier of commercial operations or tax equity funding. Logan’s Gap is a 164 MW wind project located in Comanche County, Texas.

On November 10, 2014, the Company completed its acquisition of 100% of the Class B membership interests in the Panhandle 2 wind project, representing a 81% initial ownership interest in the project’s distributable cash flow, through the acquisition of Panhandle B Member 2, from Pattern Development, for a purchase price of approximately $123.8 million, in addition to debt assumed of $195.4 million that was repaid immediately after acquisition. This represents a 147 MW interest in the 182 MW wind project, located in Carson County, Texas.

On September 5, 2014, the Company exercised its right to acquire the name “Pattern” and the Pattern logo from Pattern Development pursuant to a Service Mark Purchase and Sale Agreement for a purchase price of $1. The Company granted to Pattern Development a license to use the name “Pattern” and the Pattern logo.

On June 30, 2014, the Company acquired 100% of the Class B membership interests in the Panhandle 1 wind project, representing a 79% initial ownership interest in the project’s distributable cash flow, through the acquisition of Panhandle Wind Holdings LLC, from Pattern Development, for a purchase price of approximately $124.4 million. This represents a 172 MW interest in the 218 MW wind project, located in Carson County, Texas.

On June 25, 2014, the Company acquired a 100% equity interest in AEI El Arrayán, an entity holding a 38.5% indirect interest in El Arrayán, for a total purchase price of approximately $45.3 million. The Company owned a 31.5% indirect interest in El Arrayán prior to acquiring the additional 38.5% interest in order to obtain majority control, or 70% interest, in the project. El Arrayán is a 115 MW wind power project, located in Ovalle, Chile.

Management Fees

The Company provides management services and receives a fee for such services under agreements with its joint venture investees, South Kent, Grand, K2 and El Arrayán, prior to the Company’s acquisition of the controlling interest of El Arrayán on June 25, 2014, in addition to various Pattern Development subsidiaries. Management fees of $0.9 million and $1.7 million were recorded as related party revenue in the consolidated statements of operations for the three and six months ended June 30, 2015, respectively, and $1.0 million and $1.5 million for the same periods in the prior year. A related party receivable of $0.8 million and $0.7 million was recorded in the consolidated balance sheets as of June 30, 2015 and December 31, 2014, respectively. Subsequent to the acquisition of control of El Arrayán, Panhandle 1 and Panhandle 2, the related management fees are eliminated upon consolidation. Additionally, the Company eliminates the intercompany profit from management fees related to its ownership interest in the joint ventures.

22. Subsequent Events

On July 30, 2015, the Company acquired 100% of the Class A membership interests in Lost Creek Wind Holdco for a cash purchase price of approximately $35.2 million, less an initial deposit of $3.5 million, pursuant to a Purchase Agreement dated May 15, 2015.

On July 30, 2015, subsequent to the acquisitions of the noncontrolling interests in the Gulf Wind project, the Company prepaid 100% of the outstanding balance of the Gulf Wind project’s term loan of $154.1 million, resulting in a loss on debt settlement of approximately $4.0 million and terminated the related interest rate swaps with an aggregate fair value of $11.2 million and interest rate cap with a fair value of $0.2 million, resulting in a total net loss of $11.0 million.

On July 28, 2015, the Company acquired Pattern Development’s 40% interest in the Gulf Wind project for a cash purchase price of approximately $13.0 million. Concurrently, the Company acquired MetLife Capital, Limited Partnership’s (“MetLife Capital”) membership interest in the Gulf Wind project for a cash purchase price of approximately $72.8 million. As a result of the acquisitions, the Company owns 100% of the membership interests in the Gulf Wind project.

 

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On July 28, 2015, the Company completed an underwritten public offering of its Class A common stock. In total, 5,435,000 shares of its Class A common stock were sold. The Company has granted the underwriters a 30-day option to purchase up to an additional $18.8 million, or 815,250 shares of its Class A common stock, solely to cover over-allotments, if any. Net proceeds generated for the Company were approximately $120.2 million after deduction of underwriting discounts, commissions and transaction expenses. Concurrently, the Company issued $225.0 million aggregate principal amount of 4.00% Convertible Senior Notes due 2020 (“2020 4.00% Notes”). The Company has granted initial purchasers of the notes offering a 30-day option to purchase up to an additional $33.8 million aggregate principal amount of notes solely to cover over-allotments, if any. Net proceeds generated for the Company were approximately $218.8 million, after deducting the initial purchasers’ discount, commissions and transaction expenses. The 2020 4.00% Notes bear interest at a rate of 4.00% per year, payable semiannually in arrears on January 15 and July 15, beginning on January 15, 2016. The notes will mature on July 15, 2020, unless earlier repurchased or converted. The notes are guaranteed on a senior unsecured basis by a subsidiary of the Company.

On July 21, 2015, the Company declared an increased dividend for the third quarter, payable on October 30, 2015, to holders of record on September 30, 2015, in the amount of $0.3630 per Class A share, or $1.452 on an annualized basis. This is a three percent increase from the second quarter 2015 dividend of $0.3520.

 

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and related notes thereto included as part of our Annual Report on Form 10-K for the year ended December 31, 2014 and our unaudited consolidated financial statements for the three and six months ended June 30, 2015 and other disclosures (including the disclosures under “Part II. Item 1A. Risk Factors”) included in this Quarterly Report on Form 10-Q. Our consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles and are presented in U.S. dollars. Unless the context provides otherwise, references herein to “we,” “our,” “us,” “our company” and “Pattern Energy” refer to Pattern Energy Group Inc., a Delaware corporation, together with its consolidated subsidiaries.

Overview

We are an independent power company focused on owning and operating power projects with stable long-term cash flows in attractive markets with potential for continued growth of our business. We hold interests in 16 wind power projects located in the United States, Canada and Chile that use proven, best-in-class technology and have a total owned capacity of 2,282 MW, including the interests in the Gulf Wind project we acquired in July 2015. These projects consist of 14 operating projects with two projects under construction. Our construction projects, the Logan’s Gap project, which we acquired from Pattern Development in December 2014 and the Amazon Wind Farm (Fowler Ridge) project, which we acquired from Pattern Development in April 2015, are scheduled to commence commercial operations prior to the end of 2015. Each of our projects has contracted to sell all or a majority of its output pursuant to a long-term, fixed-price power sale agreement with a creditworthy counterparty. The credit rating of one of our counterparties, PREPA, was downgraded in 2014 and further downgraded in 2015. Refer to Item 1A “Risk Factors – Our projects rely on a limited number of key power purchasers. The power purchaser for our Santa Isabel project has been downgraded” of our Form 10-K for the year ended December 31, 2014. Eighty-nine percent of the electricity to be generated by our projects will be sold under these power sale agreements, which have a weighted average remaining contract life of approximately 15 years (inclusive of our acquisition of the membership interests in the Gulf Wind project).

We intend to maximize long-term value for our stockholders in an environmentally responsible manner and with respect for the communities in which we operate. Our business is built around the core values of creating a safe, high-integrity and exciting work environment; applying rigorous analysis to all aspects of our business; and proactively working with our stakeholders in addressing environmental and community concerns. Our financial objectives, which we believe will maximize long-term value for our stockholders, are to produce stable and sustainable cash available for distribution, selectively grow our project portfolio and our dividend and maintain a strong balance sheet and flexible capital structure.

Our growth strategy is focused on the acquisition of operational and construction-ready power projects from Pattern Development and other third parties that we believe will contribute to the growth of our business and enable us to increase our dividend per Class A share over time. We expect our continuing relationship with Pattern Development, a leading developer of renewable energy and transmission projects, will be an important source of growth for our business. In addition, we expect opportunities in Japan and Mexico will form part of our growth strategy. Currently, Pattern Development has a 5,900 MW pipeline of development projects, all of which are subject to our right of first offer. We target achieving a total owned capacity of 5,000 MW by year end 2019 through a combination of acquisitions from Pattern Development and other third parties capitalizing on the large and fragmented global wind power market.

Recent Developments

On July 30, 2015, we acquired 100% of the Class A membership interests in Lost Creek Wind Holdco (the “Lost Creek Tax Equity Buyout”) for a cash purchase price of approximately $35.2 million, less an initial deposit of $3.5 million, pursuant to a Purchase Agreement dated May 15, 2015.

On July 30, 2015, subsequent to the acquisitions of the noncontrolling interests in the Gulf Wind project, we prepaid 100% of the outstanding balance of the Gulf Wind project’s term loan of $154.1 million, resulting in a loss on debt settlement of approximately $4.0 million and terminated the related interest rate swaps with an aggregate fair value amount of $0 million and interest rate cap with a fair value of $0.2 million, resulting in a total net loss of $11.0 million. Previously, on June 26, 2015, in anticipation of our acquisition of the noncontrolling interests in the Gulf Wind project, we received a one-month extension of the scheduled term loan principal repayment of approximately $5.6 million, due on June 30, 2015, until July 31, 2015. The scheduled interest payment of approximately $2.6 million due on June 30, 2015 was paid on schedule as required by the credit agreement.

 

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On July 28, 2015, we acquired Pattern Development’s 40% interest in the Gulf Wind project for a cash purchase price of approximately $13.0 million. Concurrently, we acquired MetLife Capital, Limited Partnership’s (“MetLife Capital”) membership interest in the Gulf Wind project for a cash purchase price of approximately $72.8 million. As a result of the acquisitions, we own 100% of the membership interests in the Gulf Wind project.

On July 28, 2015, we completed an underwritten public offering of our Class A common stock. In total, 5,435,000 shares of our Class A common stock were sold. We granted the underwriters a 30-day option to purchase up to an additional $18.8 million, or 815,250 shares of our Class A common stock, solely to cover over-allotments. Net proceeds generated to us were approximately $120.2 million after deduction of underwriting discounts, commissions and transaction expenses. Concurrently, we issued $225.0 million aggregate principal amount of 4.00% Convertible Senior Notes due 2020 (“2020 4.00% Notes”). We have granted initial purchasers of the notes offering a 30-day option to purchase up to an additional $33.8 million aggregate principal amount of notes solely to cover over-allotments, if any. Net proceeds generated for us were approximately $218.8 million, after deducting the initial purchasers’ discount, commissions and transaction expenses. The 2020 4.00% Notes bear interest at a rate of 4.00% per year, payable semiannually in arrears on January 15 and July 15, beginning on January 15, 2016. The notes will mature on July 15, 2020, unless earlier repurchased or converted. The notes are guaranteed on a senior unsecured basis by one of our subsidiaries.

On July 21, 2015, we declared an increased dividend for the third quarter, payable on October 30, 2015, to holders of record on September 30, 2015, in the amount of $0.3630 per Class A share, or $1.452 on an annualized basis. This is a three percent increase from the second quarter 2015 dividend of $0.3520.

On July 13, 2015, our Grand project entered into settlement agreements with Samsung C&T Canada Ltd. (a subsidiary of Samsung C&T Corporation), the project construction provider, to settle claims for cost increases and schedule relief in the construction of the Grand project asserted by the project construction provider against Grand and the third party owner of an adjacent 100 MW solar project that jointly owns transmission facilities with Grand that were constructed by the project construction provider, on the one hand, and claims asserted by Grand and the solar project owner against the project construction provider, on the other hand. The settlement agreements provide for a net payment by Grand of C$14.3 million.

On July 3, 2015, we amended our Bilateral Management Services Agreement with Pattern Development to change the terms upon which the employees of Pattern Development and its subsidiaries may become our employees (the “Reintegration Event”). The Reintegration Event is no longer conditioned upon our achievement of $2.5 billion in market capitalization. Instead, we have the option, exercisable at any time until January 1, 2017, to require the Reintegration Event to occur.

On June 17, 2015, we acquired a one-third limited partnership interest in K2 Wind Ontario Limited Partnership (“K2”), as well as 100% of the issued and outstanding shares in Pattern K2 GP Holdings Inc., from Pattern Development, pursuant to a Purchase and Sale Agreement, for a consideration of approximately $128.0 million, paid at closing, in addition to $0.4 million of capitalized transaction expenses, plus assumed estimated proportionate debt at term conversion of approximately $221.8 million. K2 has completed construction of the wind power project which has achieved commercial operations. K2 now operates the approximately 270 MW wind power project located in the Township of Ashfield-Colborne-Wawanosh, Ontario. K2 consists of 140 Siemens 2.3 MW wind turbines and operates under a 20-year power sale agreement with the IESO. As a result of the acquisition, we directly own a one-third limited partnership interest in K2 and 25% of the issued and outstanding shares of K2 Wind Ontario Inc., the general partner, and indirectly hold a 0.0025% general partnership interest in K2.

On May 15, 2015, pursuant to a Purchase and Sale Agreement and for an aggregate consideration of approximately $242.0 million, paid at closing, we acquired: (1) from Wind Capital Group, LLC, an unrelated third party, 100% of the membership interests in Lost Creek Wind Finco, LLC, which owns 100% of the Class B membership interests in Lost Creek Wind Holdco, LLC, which owns 100% of the membership interests in Lost Creek Wind, LLC, which owns and operates a 150 MW wind power project in King City, Missouri; and (2) from Lincoln County Wind Project Finco, LLC, an unrelated third party, 100% of the membership interests in Lincoln County Wind Project Holdco, LLC, which owns 100% of the Class B membership interests in Post Rock Wind Power Project, LLC, which owns and operates a 201 MW wind power project in Ellsworth and Lincoln Counties, Kansas. We also assumed certain project-level indebtedness and ordinary course performance guarantees securing project obligations. Lost Creek operates with General Electric wind turbines and achieved commercial operations in May 2010. It has a power sale agreement with Associated Electric Cooperative Incorporated (rated AA) expiring in 2030. Post Rock, in which we have 120 MW owned capacity, operates with General Electric wind turbines and achieved commercial operations in October 2012. It has a power sale agreement with Westar (rated BBB+) expiring in 2032.

On April 29, 2015, we acquired 100% of the membership interests in Fowler Ridge IV Wind Farm LLC through the acquisition of Fowler Ridge IV B Member LLC, from Pattern Development, pursuant to a Purchase and Sale Agreement, for a purchase price of approximately $37.5 million, paid at closing, in addition to $0.5 million of capitalized transaction expenses, and contingent payments of up to $29.1 million, payable upon tax equity funding. The 150 MW wind project (of which we have 116 MW owned capacity) named Amazon Wind Farm (Fowler Ridge), located in Benton County, Indiana, is expected to reach commercial operation in late 2015. The project consists of 65 Siemens 2.3 wind turbines and has a power sale agreement with Amazon (not rated) expiring in 2028. The power sale agreement provides for 50% of the energy to be delivered starting on the targeted commercial operations date (December 31, 2015), increasing to 100% 18 months later.

 

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On April 6, 2015, we announced an increase to our growth target for cash available for distribution per Class A share to a compound annual growth rate of 12-15% for the three-year period following 2014. The growth target was increased due to the acquisitions of K2, Lost Creek and Post Rock described above, the advancement in the development of our Identified ROFO Projects described below and the expansion of Pattern Development’s development pipeline.

The following table sets forth each of our construction projects as well as their respective power capacities and our anticipated date of their commencement of commercial operations:

 

 

Projects

   Location    Construction
Start
     Commercial
Operations
     MW  
            Rated      Owned  

Logan’s Gap

   Texas      Q4 2014         Q3 2015         200         164   

Amazon Wind Farm (Fowler Ridge)

   Indiana      Q2 2015         Q4 2015         150         116   
           

 

 

    

 

 

 
              350         280   
           

 

 

    

 

 

 

Since March 2015, we have added seven new identified Right of First Offer Projects (“Identified ROFO Projects”) to our list of projects that we expect to acquire from Pattern Development in connection with our purchase rights.

 

    On June 24, 2015, we announced the addition of the following six projects to our Identified ROFO Projects list:

 

    398 MW of a 497 MW New Mexico/California wind power project based in Curry County, New Mexico. The project, which is being built in multiple phases, will deliver wind power directly into California. The project is at an advanced stage of development. Terms of the 20-year/25-year power sale agreements for multiple phases have been agreed upon and are in final documentation.

 

    63 MW of the 125 MW Tsugaru wind power project located in Aomori, Japan. The project, which is in late-stage development, has qualified for a power sale agreement under Japan’s Feed-In Tariff law.

 

    31 MW of the 33 MW Ohorayama wind power project located in Kochi, Japan. The project has qualified for a 20-year power sale agreement with Shikoku Electric Power Company.

 

    17 MW of the 42 MW Futtsu Solar project under construction in Chiba, Japan. This solar power project has a 20-year power sale agreement with Tokyo Electric Power Company.

 

    12 MW of the 12 MW Otsuki wind power facility located in Kochi, Japan. This operational facility has a 12-year power sale agreement with Shikoku Electric Power Company.

 

    5 MW of the 14 MW Kanagi Solar project under construction in Shimane, Japan. This solar power project has a 20-year power sale agreement with Chugoku Electric Power Company.

 

    On April 21, 2015, Pattern Development announced that it had entered into a 20-year PPA with the IESO in Ontario in connection with a 100 MW wind power project proposed to be built in Chatham-Kent, Ontario (“North Kent”). Pattern Development expects to retain an owned capacity in the North Kent project of approximately 43 MW. The North Kent project is expected to begin commercial operation in late 2017.

Below is a summary of our Identified ROFO Projects that we expect to acquire from Pattern Development in connection with our purchase right. For additional discussion on certain of the Identified ROFO Projects, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Recent Transactions”, in our Annual Report on Form 10-K for the year ended December 31, 2014.

 

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                                    Capacity (MW)  

Identified

ROFO Projects

   Status    Location    Construction
Start (1)
     Commercial
Operations  (2)
     Contract
Type
     Rated (3)      Pattern
Development-
Owned (4)
 

Armow

   In construction    Ontario      2014         2015         PPA         180         90   

Meikle

   In construction    British Columbia      2015         2016         PPA         185         180   

Conejo Solar

   In construction    Chile      2015         2016         PPA         104         84   

Belle River

   Securing final permits    Ontario      2016         2017         PPA         100         50   

Henvey Inlet

   Late stage development    Ontario      2016         2017         PPA         300         150   

Mont Sainte-Marguerite

   Late stage development    Québec      2016         2017         PPA         147         147   

North Kent

   Late stage development    Ontario      2016         2017         PPA         100         43   

New Mexico/California

   Late stage development    New Mexico      2016         2016/2017         PPA         497         398   

Tsugaru

   Late stage development    Japan      2015         2018         PPA         125         63   

Ohorayama

   Late stage development    Japan      2015         2017         PPA         33         31   

Kanagi Solar

   In construction    Japan      2014         2016         PPA         14         5   

Futtsu Solar

   In construction    Japan      2014         2016         PPA         42         17   

Otsuki

   Operational    Japan      2009         2016         PPA         12         12   
                 

 

 

    

 

 

 
                    1,839         1,270   
                 

 

 

    

 

 

 

 

(1) Represents year of actual or anticipated commencement of construction.
(2) Represents year of actual or anticipated commencement of commercial operations.
(3) Rated capacity represents the maximum electricity generating capacity of a project in MW. As a result of wind and other conditions, a project or a turbine will not operate at its rated capacity at all times and the amount of electricity generated will be less than its rated capacity. The amount of electricity generated may vary based on a variety of factors discussed elsewhere in this Form 10-Q.
(4) Pattern Development-owned capacity represents the maximum, or rated, electricity generating capacity of the project multiplied by Pattern Development’s percentage ownership interest in the distributable cash flow of the project.

Key Metrics

We regularly review a number of financial measurements and operating metrics to evaluate our performance, measure our growth and make strategic decisions. In addition to traditional U.S. GAAP performance and liquidity measures, such as revenue, cost of revenue, net income (loss) and cash provided by (used in) operating activities, we also consider proportional MWh sold, average realized electricity price and Adjusted EBITDA in evaluating our operating performance and cash available for distribution as supplemental liquidity measures. Adjusted EBITDA and cash available for distribution are non-GAAP financial measures which management believes may assist investors in evaluating the Company’s financial performance and its ability to pay dividends. Each of these key metrics is discussed below.

Proportional MWh Sold and Average Realized Electricity Price

The number of MWh sold and the average realized price per MWh sold are the operating metrics that determine our revenue, as well as the revenue of our unconsolidated investments. Proportional MWh sold for any period presented, represents the sum of the product of (i) the number of MWh sold by each of our projects multiplied by (ii) our percentage interest in each projects’ distributable cash flow. For any period presented, average realized electricity price represents (i) the sum of the products of: (a) total revenue from electricity sales and energy derivative settlements at each of our projects and (b) our percentage interest in each project’s distributable cash flow divided by (ii) our proportional MWh sold.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) before net interest expense, income taxes and depreciation and accretion, including our proportionate share of net interest expense, income taxes and depreciation and accretion of joint venture investments that are accounted for under the equity method. Adjusted EBITDA also excludes the effect of certain mark-to-market adjustments and infrequent items not related to normal or ongoing operations, such as early payment of debt and realized derivative gain or loss from refinancing transactions, and gain or loss related to acquisitions or divestitures. In calculating Adjusted EBITDA, we exclude mark-to-market adjustments to the value of our derivatives because we believe that it is useful for investors to understand, as a supplement to net income (loss) and other traditional measures of operating results, the results of our operations without regard to periodic, and sometimes material, fluctuations in the market value of such assets or liabilities.

 

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Adjusted EBITDA is a non-U.S. GAAP measure. The most directly comparable U.S. GAAP measure to adjusted EBITDA is net income (loss). The following table reconciles net income (loss) to Adjusted EBITDA for the periods presented (unaudited and in thousands):

 

     Three months ended June 30,      Six months ended June 30,  
     2015      2014      2015      2014  

Net income (loss)

   $ 5,657       $ 7,167       $ (16,402    $ (14,732

Plus:

           

Interest expense, net of interest income

     18,715         15,525         36,414         29,943   

Tax provision

     3,603         4,065         2,857         2,033   

Depreciation, amortization and accretion

     34,785         21,284         63,841         42,461   
  

 

 

    

 

 

    

 

 

    

 

 

 

EBITDA

   $ 62,760       $ 48,041       $ 86,710       $ 59,705   
  

 

 

    

 

 

    

 

 

    

 

 

 

Unrealized loss on energy derivative

     6,002         6,549         3,030         14,282   

Interest rate derivative settlements

     960         1,035         1,919         2,052   

Unrealized (gain) loss on derivatives, net

     (5,138      2,942         (2,697      6,665   

Net loss (gain) on transactions

     1,305         (14,537      2,589         (14,537

Plus, proportionate share from equity accounted investments:

           

Interest expense, net of interest income

     5,181         4,944         10,619         5,197   

Tax provision

     —           102         —           102   

Depreciation, amortization and accretion

     4,991         4,537         9,500         4,724   

Unrealized (gain) loss on interest rate and currency derivatives, net

     (9,240      5,236         1,894         17,831   

Realized loss on interest rate and currency derivatives

     —           —           —           22   
  

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted EBITDA

   $ 66,821       $ 58,849       $ 113,564       $ 96,043   
  

 

 

    

 

 

    

 

 

    

 

 

 

Cash Available for Distribution

We define cash available for distribution as net cash provided by operating activities as adjusted for certain other cash flow items that we associate with our operations. It is a non-U.S. GAAP measure of our ability to generate cash to service our dividends. Our definition of cash available for distribution has been modified from prior periods to include distributions from unconsolidated investments to the extent such distributions were derived from operating cash flows. Cash available for distribution represents cash provided by operating activities as adjusted to (i) add or subtract changes in operating assets and liabilities, (ii) subtract net deposits into restricted cash accounts, which are required pursuant to the cash reserve requirements of financing agreements, to the extent they are paid from operating cash flows during a period, (iii) subtract cash distributions paid to noncontrolling interests, (iv) subtract scheduled project-level debt repayments in accordance with the related loan amortization schedule, to the extent they are paid from operating cash flows during a period, (v) subtract non-expansionary capital expenditures, to the extent they are paid from operating cash flows during a period, (vi) add cash distributions received from unconsolidated investments, to the extent such distributions were derived from operating cash flows and (vii) add or subtract other items as necessary to present the cash flows we deem representative of our core business operations.

The most directly comparable U.S. GAAP measure to cash available for distribution is net cash provided by operating activities. The following table is a reconciliation of our net cash provided by operating activities to cash available for distribution for the periods presented (unaudited and in thousands):

 

     Three months ended June 30,      Six months ended June 30,  
     2015      2014      2015      2014  

Net cash provided by operating activities

   $ 32,361       $ 44,417       $ 48,600       $ 60,822   

Changes in operating assets and liabilities

     2,521         (12,336      (2,136      (5,685

Other

     (148      —           (292      —     

Network upgrade reimbursement

     618         618         1,236         1,236   

Release of restricted cash to fund project and general and administrative costs

     1,501         7         1,501         61   

Operations and maintenance capital expenditures

     (283      (40      (321      (94

Transaction costs for acquisitions

     1,357         1,128         1,777         1,128   

Distributions from unconsolidated investment

     7,771         —           13,847         —     

Less:

           

Distributions to noncontrolling interests

     (763      (1,470      (1,511      (1,470

Principal payments paid from operating cash flows

     (16,948      (16,266      (25,383      (22,096
  

 

 

    

 

 

    

 

 

    

 

 

 

Cash available for distribution

   $ 27,987       $ 16,058       $ 37,318       $ 33,902   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Results of Operations

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

The following table presents selected operating performance metrics for the periods presented (unaudited):

 

     Three months ended June 30,                
     2015      2014      Change      % Change  

Proportional MWh sold

     1,201,940         769,619         432,321         56.2

Average realized electricity price per MWh

   $ 82       $ 100       $ (18      -18.0

Proportional MWh sold and average realized electricity price. Our proportional MWh sold for the three months ended June 30, 2015 was 1,201,940 MWh, as compared to 769,619 MWh for the three months ended June 30, 2014, an increase of 432,321, or 56.2%. This increase in proportional MWh sold was primarily attributable to the commencement of commercial operations at both Panhandle 1 and El Arrayán in June 2014 and Panhandle 2 in November 2014 and the acquisition of Lost Creek and Post Rock in May 2015. Our average realized electricity price was approximately $82 per MWh for the three months ended June 30, 2015 as compared to approximately $100 per MWh for the three months ended June 30, 2014. The $18 per MWh decrease in the average realized electricity price was due to lower PPA pricing related to Panhandle 1 and Panhandle 2 projects and the impact of foreign exchange on revenue denominated in the Canadian dollar at St. Joseph, partially offset by higher PPA pricing related to El Arrayán and Grand. Low wind levels in the second quarter of 2015 resulted in a 10% negative variance in our production compared to our long-term expectation after adjusting for certain production losses, which are unrelated to wind and are compensated by contractual counterparties.

The following table provides selected financial information for the periods presented and is unaudited (in thousands, except percentages):

 

     Three months ended June 30,                
     2015      2014      $ Change      % Change  

Revenue

   $ 84,671       $ 64,939       $ 19,732         30.4
  

 

 

    

 

 

    

 

 

    

 

 

 

Project expense

     27,981         16,700         11,281         67.6

Depreciation and accretion

     34,342         21,284         13,058         61.4
  

 

 

    

 

 

    

 

 

    

 

 

 

Total cost of revenue

     62,323         37,984         24,339         64.1
  

 

 

    

 

 

    

 

 

    

 

 

 

Gross profit

     22,348         26,955         (4,607      -17.1
  

 

 

    

 

 

    

 

 

    

 

 

 

General and administrative

     8,870         6,288         2,582         41.1

Related party general and administrative

     1,621         1,383         238         17.2
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating expenses

     10,491         7,671         2,820         36.8
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating income

     11,857         19,284         (7,427      -38.5

Total other expense

     (2,597      (8,052      5,455         -67.7
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income before income tax

     9,260         11,232         (1,972      -17.6

Tax provision

     3,603         4,065         (462      -11.4
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income

     5,657         7,167         (1,510      -21.1

Net loss attributable to noncontrolling interest

     (8,660      (4,032      (4,628      114.8
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income attributable to controlling interest

   $ 14,317       $ 11,199       $ 3,118         27.8
  

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted EBITDA

   $ 66,821       $ 58,849       $ 7,972         13.5
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Revenue. Revenue for the three months ended June 30, 2015 was $84.7 million as compared to $64.9 million for the three months ended June 30, 2014, an increase of $19.7 million, or 30.4%. This increase in revenue was primarily attributable to increased electricity sales due to the commencement of commercial operations at El Arrayán, Panhandle 1, and Panhandle 2 at various times in 2014 and the acquisition of Lost Creek and Post Rock in the second quarter of 2015.

We also realized an increase of $1.9 million in energy derivative settlements during the second quarter of 2015. The value of our energy derivative, and the amount of unrealized gain or loss we record, increases and decreases due to our monthly derivative settlements and changes in forward electricity prices, which are derived from and impacted by changes in forward natural gas prices.

Cost of revenue. Cost of revenue for the three months ended June 30, 2015 was $62.3 million as compared to $38.0 million for the three months ended June 30, 2014, an increase of $24.3 million, or 64.1%. The increase in cost of revenue was primarily attributable to the commencement of commercial operations at Panhandle 1, Panhandle 2, and El Arrayán at various times in 2014 and the acquisition of Lost Creek and Post Rock in the second quarter of 2015. As each new project commences commercial operations, we incur new incremental and ongoing costs for maintenance and services agreements, property taxes, insurance, land lease, depreciation and other costs associated with managing, operating and maintaining the facility, including adding site employees and other operations staff.

Operating expenses. Operating expenses for the three months ended June 30, 2015 were $10.5 million as compared to $7.7 million for the three months ended June 30, 2014, an increase of $2.8 million, or 36.8%. The increase in operating expenses was primarily attributable to increases in general and administrative expense to support new projects acquired in 2014 and 2015 and acquisition-related activity in the second quarter of 2015.

Other expense . Other expense for the three months ended June 30, 2015 was $2.6 million compared to $8.1 million for the three months ended June 30, 2014, a decrease of $5.5 million, or 67.7%. The decrease in other expense was primarily attributable to a $17.5 million favorable variance between equity in earnings from unconsolidated investments of $13.8 million in the second quarter of 2015 and equity in losses from unconsolidated investments of $3.7 million in the second quarter of 2014, which is primarily a result of unrealized gains from the valuation of interest rate derivatives on the unconsolidated investees’ financial statements. In addition, we recorded a $5.1 million unrealized gain on derivatives in the second quarter of 2015 compared to a $2.9 million loss in the second quarter of 2014 primarily related to the valuation of interest rate derivatives at Ocotillo. The changes in unrealized gains and losses on interest rate derivatives were due to an increase in the forward interest rate curve in the second quarter of 2015 compared to a decrease in the forward interest rate curve in the second quarter of 2014. Offsetting these decreases to other expense in the second quarter of 2015 was the absence of an $18.0 million gain recorded in net gain on transactions in the second quarter of 2014, related to our acquisition of an additional 38.5% interest in the El Arrayán project. In addition, interest expense increased by $3.1 million primarily related to debt at El Arrayán and Lost Creek, and the revolving credit facility in the second quarter of 2015, partially offset by a decrease in interest expense at Ocotillo due to the repricing of the debt in the fourth quarter of 2014.

Tax provision. The tax provision was $3.6 million for the three months ended June 30, 2015 compared to $4.1 million for the three months ended June 30, 2014, a decrease of $0.5 million, or 11.4%. The tax provision in the second quarter of 2015 was the result of recording deferred tax liabilities on equity in earnings in unconsolidated investments at South Kent, Grand, and K2, tax expense at our Canadian and Puerto Rican operations, and foreign withholding taxes on intercompany transactions in certain foreign jurisdictions, partially offset by recognizing a deferred tax asset on losses at El Arrayán. The expense provision in the second quarter of 2014 was primarily the result of recording a discrete expense on a gain related to the fair value re-measurement of our initial 31.5% interest in El Arrayán.

Net loss attributable to noncontrolling interest. The net loss attributable to noncontrolling interest was $8.7 million for the three months ended June 30, 2015 compared to $4.0 million for the three months end June 30, 2014, an increase of $4.6 million, or 114.8%, primarily due to net loss attributable to noncontrolling interests from Panhandle 1 and Panhandle 2, which commenced commercial operations at various times in 2014 and Lost Creek and Post Rock, both of which were acquired in the second quarter of 2015, partially offset by an increase in derivative hedge settlements at Gulf Wind.

Adjusted EBITDA . Adjusted EBITDA for the three months ended June 30, 2015 was $66.8 million compared to $58.8 million for the same period in the prior year, an increase of $8.0 million, or 13.5%. The increase in adjusted EBITDA was primarily attributable to the commencement of commercial operations at South Kent, Grand, Panhandle 1, Panhandle 2, and El Arrayán at various times in 2014 and the acquisition of Lost Creek and Post Rock in the second quarter of 2015.

 

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