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TABLE OF CONTENTS
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
ý |
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
|
For the quarterly period ended June 30, 2011 |
||
OR |
||
o |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
|
For the transition period from to |
COMMISSION FILE NUMBER 001-34691
ATLANTIC POWER CORPORATION
(Exact name of registrant as specified in its charter)
British Columbia, Canada (State or other jurisdiction of incorporation or organization) |
55-0886410 (I.R.S. Employer Identification No.) |
|
200 Clarendon Street, Floor 25 Boston, MA (Address of principal executive offices) |
02116 (Zip code) |
(617) 977-2400
(Registrant's telephone number, including area code)
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 ý No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o | Accelerated filer o | Non-accelerated filer ý (Do not check if a smaller reporting company) |
Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
The number of shares outstanding of the registrant's Common Stock as of August 10, 2011 was 68,963,203.
ATLANTIC POWER CORPORATION
FORM 10-Q
THREE AND SIX MONTHS ENDED JUNE 30, 2011
In this Quarterly Report on Form 10-Q, references to "Cdn$" and "Canadian dollars" are to the lawful currency of Canada and references to "$" and "US$" and "U.S. dollars" are to the lawful currency of the United States. All dollar amounts herein are in U.S. dollars, unless otherwise indicated.
Unless otherwise stated, or the context otherwise requires, references in this Quarterly Report on Form 10-Q to "we," "us," "our" and "Atlantic Power" refer to Atlantic Power Corporation, those entities owned or controlled by Atlantic Power Corporation and predecessors of Atlantic Power Corporation.
2
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
ATLANTIC POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands of U.S. dollars)
|
June 30, 2011 |
December 31, 2010 |
||||||
---|---|---|---|---|---|---|---|---|
|
(unaudited) |
|
||||||
Assets |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 46,551 | $ | 45,497 | ||||
Restricted cash |
21,034 | 15,744 | ||||||
Accounts receivable |
20,028 | 19,362 | ||||||
Note receivablerelated party (Note 14) |
7,326 | 22,781 | ||||||
Current portion of derivative instruments asset (Notes 8 and 9) |
9,297 | 8,865 | ||||||
Prepayments, supplies, and other |
8,451 | 8,480 | ||||||
Refundable income taxes |
1,611 | 1,593 | ||||||
Total current assets |
114,298 | 122,322 | ||||||
Property, plant, and equipment, net |
308,051 |
271,830 |
||||||
Transmission system rights |
184,208 | 188,134 | ||||||
Equity investments in unconsolidated affiliates (Note 4) |
276,962 | 294,805 | ||||||
Other intangible assets, net |
77,425 | 88,462 | ||||||
Goodwill |
12,453 | 12,453 | ||||||
Derivative instruments asset (Notes 8 and 9) |
18,865 | 17,884 | ||||||
Other assets |
16,718 | 17,122 | ||||||
Total assets |
$ | 1,008,980 | $ | 1,013,012 | ||||
Liabilities |
||||||||
Current Liabilities: |
||||||||
Accounts payable and accrued liabilities |
$ | 16,333 | $ | 20,530 | ||||
Current portion of long-term debt (Note 6) |
21,962 | 21,587 | ||||||
Current portion of derivative instruments liability (Notes 8 and 9) |
7,410 | 10,009 | ||||||
Interest payable on convertible debentures (Note 7) |
1,948 | 3,078 | ||||||
Dividends payable |
6,490 | 6,154 | ||||||
Other current liabilities |
7 | 5 | ||||||
Total current liabilities |
54,150 | 61,363 | ||||||
Long-term debt (Note 6) |
263,111 |
244,299 |
||||||
Convertible debentures (Note 7) |
209,703 | 220,616 | ||||||
Derivative instruments liability (Notes 8 and 9) |
24,822 | 21,543 | ||||||
Deferred income taxes |
23,594 | 29,439 | ||||||
Other non-current liabilities |
2,121 | 2,376 | ||||||
Commitments and contingencies (Note 15) |
| | ||||||
Total liabilities |
577,501 | 579,636 | ||||||
Equity |
||||||||
Common shares, no par value, unlimited authorized shares; 68,639,654 and 67,118,154 issued and outstanding at June 30, 2011 and December 31, 2010 , respectively |
644,001 | 626,108 | ||||||
Accumulated other comprehensive income (Note 9) |
24 | 255 | ||||||
Retained deficit |
(215,782 | ) | (196,494 | ) | ||||
Total Atlantic Power Corporation shareholders' equity |
428,243 | 429,869 | ||||||
Noncontrolling interest |
3,236 | 3,507 | ||||||
Total equity |
431,479 | 433,376 | ||||||
Total liabilities and equity |
$ | 1,008,980 | $ | 1,013,012 | ||||
See accompanying notes to consolidated financial statements.
3
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands of U.S. dollars, except per share amounts)
(Unaudited)
|
Three months ended June 30, |
Six months ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2011 | 2010 | 2011 | 2010 | ||||||||||
Project revenue: |
||||||||||||||
Energy sales |
$ | 17,865 | $ | 16,659 | $ | 36,367 | $ | 32,572 | ||||||
Energy capacity revenue |
27,651 | 23,195 | 54,789 | 46,389 | ||||||||||
Transmission services |
7,491 | 7,729 | 15,135 | 15,373 | ||||||||||
Other |
251 | 321 | 632 | 791 | ||||||||||
|
53,258 | 47,904 | 106,923 | 95,125 | ||||||||||
Project expenses: |
||||||||||||||
Fuel |
14,316 | 15,771 | 31,384 | 31,928 | ||||||||||
Operations and maintenance |
7,801 | 6,442 | 18,873 | 12,402 | ||||||||||
Depreciation and amortization |
10,924 | 10,071 | 21,803 | 20,142 | ||||||||||
|
33,041 | 32,284 | 72,060 | 64,472 | ||||||||||
Project other income (expense): |
||||||||||||||
Change in fair value of derivative instruments |
(4,574 | ) | 992 | (1,013 | ) | (11,202 | ) | |||||||
Equity in earnings of unconsolidated affiliates |
1,962 | 3,026 | 3,273 | 8,462 | ||||||||||
Interest expense, net |
(4,543 | ) | (4,308 | ) | (9,190 | ) | (8,719 | ) | ||||||
Other income (expense), net |
(31 | ) | 211 | (33 | ) | 211 | ||||||||
|
(7,186 | ) | (79 | ) | (6,963 | ) | (11,248 | ) | ||||||
Project income |
13,031 | 15,541 | 27,900 | 19,405 | ||||||||||
Administrative and other expenses (income): |
||||||||||||||
Administration |
4,671 | 3,843 | 8,725 | 7,943 | ||||||||||
Interest, net |
3,510 | 2,518 | 7,478 | 5,312 | ||||||||||
Foreign exchange (gain) loss (Note 9) |
(535 | ) | 4,224 | (1,193 | ) | 2,432 | ||||||||
Other income, net |
| (26 | ) | | (26 | ) | ||||||||
|
7,646 | 10,559 | 15,010 | 15,661 | ||||||||||
Income from operations before income taxes |
5,385 | 4,982 | 12,890 | 3,744 | ||||||||||
Income tax expense (benefit) (Note 10) |
(7,684 | ) | 3,618 | (6,161 | ) | 8,491 | ||||||||
Net income (loss) |
13,069 | 1,364 | 19,051 | (4,747 | ) | |||||||||
Net loss attributable to noncontrolling interest |
(117 | ) | (81 | ) | (271 | ) | (129 | ) | ||||||
Net income (loss) attributable to Atlantic Power Corporation |
$ | 13,186 | $ | 1,445 | $ | 19,322 | $ | (4,618 | ) | |||||
Net income (loss) per share attributable to Atlantic Power Corporation shareholders: (Note 12) |
||||||||||||||
Basic |
$ | 0.19 | $ | 0.02 | $ | 0.28 | $ | (0.08 | ) | |||||
Diluted |
$ | 0.18 | $ | 0.02 | $ | 0.28 | $ | (0.08 | ) | |||||
Weighted average number of common shares |
||||||||||||||
Basic |
68,573 | 60,481 | 68,116 | 60,443 | ||||||||||
Diluted |
82,939 | 60,890 | 82,973 | 60,443 |
See accompanying notes to consolidated financial statements.
4
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands of U.S. dollars)
(Unaudited)
|
Six months ended June 30, |
|||||||
---|---|---|---|---|---|---|---|---|
|
2011 | 2010 | ||||||
Cash flows from operating activities: |
||||||||
Net income (loss) |
$ | 19,051 | $ | (4,747 | ) | |||
Adjustments to reconcile to net cash provided by operating activities: |
||||||||
Depreciation and amortization |
21,803 | 20,142 | ||||||
Long-term incentive plan expense |
1,639 | 2,149 | ||||||
Gain on step-up valuation of Rollcast acquisition |
| (211 | ) | |||||
Equity in earnings from unconsolidated affiliates |
(3,273 | ) | (8,462 | ) | ||||
Distributions from unconsolidated affiliates |
11,584 | 5,718 | ||||||
Unrealized foreign exchange loss |
4,499 | 5,199 | ||||||
Change in fair value of derivative instruments |
1,013 | 11,202 | ||||||
Change in deferred income taxes |
(5,691 | ) | 7,416 | |||||
Change in other operating balances |
||||||||
Accounts receivable |
(666 | ) | (953 | ) | ||||
Prepayments, refundable income taxes and other assets |
1,244 | (481 | ) | |||||
Accounts payable and accrued liabilities |
(4,996 | ) | (1,970 | ) | ||||
Other liabilities |
(1,492 | ) | 976 | |||||
Net cash provided by operating activities |
44,715 | 35,978 | ||||||
Cash flows used in by investing activities: |
||||||||
Acquisitions and investments, net of cash acquired |
| 324 | ||||||
Change in restricted cash |
(5,290 | ) | 280 | |||||
Proceeds from sale of equity investments |
8,500 | | ||||||
Repayments from related party loan |
15,455 | | ||||||
Biomass development costs |
(587 | ) | (948 | ) | ||||
Purchase of property, plant and equipment |
(42,898 | ) | (1,520 | ) | ||||
Net cash used in investing activities |
(24,820 | ) | (1,864 | ) | ||||
Cash flows used in by financing activities: |
||||||||
Proceeds from project-level debt |
29,890 | | ||||||
Repayment of project-level debt |
(10,341 | ) | (9,141 | ) | ||||
Equity investment from noncontrolling interest |
| 200 | ||||||
Proceeds from revolving credit facility borrowings |
| 20,000 | ||||||
Dividends paid |
(38,390 | ) | (31,709 | ) | ||||
Net cash used in financing activities |
(18,841 | ) | (20,650 | ) | ||||
Net increase in cash and cash equivalents |
1,054 | 13,464 | ||||||
Cash and cash equivalents at beginning of period |
45,497 | 49,850 | ||||||
Cash and cash equivalents at end of period |
$ | 46,551 | $ | 63,314 | ||||
Supplemental cash flow information |
||||||||
Interest paid |
$ | 17,600 | $ | 11,437 | ||||
Income taxes paid (refunded), net |
$ | (436 | ) | $ | 1,045 |
See accompanying notes to consolidated financial statements.
5
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of presentation and summary of significant accounting policies
Overview
Atlantic Power Corporation owns and operates a diverse fleet of power generation and infrastructure assets in the United States. Our power generation projects sell electricity to utilities and other large commercial customers under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,948 megawatts (or "MW") in which our ownership interest is approximately 871 MW. Our current portfolio consists of interests in 12 operational power generation projects across nine states, one biomass project under construction in Georgia, and a 500 kilovolt 84-mile electric transmission line located in California. We also own a majority interest in Rollcast Energy, a biomass power plant developer with several projects under development. Six of our projects are wholly-owned subsidiaries: Lake Cogen, Ltd., Pasco Cogen, Ltd., Auburndale Power Partners, L.P., Cadillac Renewable Energy, LLC, Piedmont Green Power, LLC and Atlantic Path 15, LLC.
The interim consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission ("SEC") regulations for interim financial information and with the instructions to Form 10-Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2010. Interim results are not necessarily indicative of results for the full year.
In our opinion, the accompanying unaudited interim consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly our consolidated financial position as of June 30, 2011, the results of operations for the three and six-month periods ended June 30, 2011 and 2010, and our cash flows for the six-month periods ended June 30, 2011 and 2010.
Use of estimates:
The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment and power purchase agreements ("PPAs"), the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the valuation of shares associated with our long-term incentive plan and the fair value of financial instruments and derivatives. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets if indications of impairment exist during the period. These estimates and assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying assumptions and estimates change, the recorded amounts could change by a material amount.
6
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. Basis of presentation and summary of significant accounting policies (Continued)
Reclassifications:
Certain prior year amounts have been reclassified to conform to the current year presentation.
Recently issued accounting standards:
Adopted
In December 2010, the FASB issued changes to the disclosure of pro forma information for business combinations. These changes clarify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Also, the existing supplemental pro forma disclosures were expanded to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. We adopted these changes beginning January 1, 2011. Upon adoption, we determined these changes did not impact the consolidated financial statements.
In December 2010, the FASB issued changes to the testing of goodwill for impairment. These changes require an entity to perform all steps in the test for a reporting unit whose carrying value is zero or negative if it is more likely than not (more than 50%) that a goodwill impairment exists based on qualitative factors, resulting in the elimination of an entity's ability to assert that such a reporting unit's goodwill is not impaired and additional testing is not necessary despite the existence of qualitative factors that indicate otherwise. We adopted these changes beginning January 1, 2011. Based on the most recent impairment review of our goodwill (2010 fourth quarter), we determined these changes did not impact the consolidated financial statements.
In January 2010, the FASB issued changes to disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose, in the reconciliation of fair value measurements using significant unobservable inputs (Level 3), separate information about purchases, sales, issuances, and settlements (that is, on a gross basis rather than as one net number) of these Level 3 financial instruments. We adopted these changes beginning January 1, 2011. We determined that these changes did not have an impact on the consolidated financial statements.
In April 2010, the FASB issued changes to the classification of certain employee share-based payment awards. These changes clarify that there is not an indication of a condition that is other than market, performance, or service if an employee share-based payment award's exercise price is denominated in the currency of a market in which a substantial portion of the entity's equity securities trade and differs from the functional currency of the employer entity or payroll currency of the employee. An employee share-based payment award is required to be classified as a liability if the award does not contain a market, performance, or service condition. These changes were adopted beginning on January 1, 2011. We determined that these changes did not have an impact on the consolidated financial statements.
Issued
In May 2011, the FASB issued changes to conform existing guidance regarding fair value measurement and disclosure between GAAP and International Financial Reporting Standards. These changes both clarify the FASB's intent about the application of existing fair value measurement and
7
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1. Basis of presentation and summary of significant accounting policies (Continued)
disclosure requirements and amend certain principles or requirements for measuring fair value or for disclosing information about fair value measurements. The clarifying changes relate to the application of the highest and best use and valuation premise concepts, measuring the fair value of an instrument classified in a reporting entity's shareholders' equity, and disclosure of quantitative information about unobservable inputs used for Level 3 fair value measurements. The amendments relate to measuring the fair value of financial instruments that are managed within a portfolio; application of premiums and discounts in a fair value measurement; and additional disclosures concerning the valuation processes used and sensitivity of the fair value measurement to changes in unobservable inputs for those items categorized as Level 3, a reporting entity's use of a nonfinancial asset in a way that differs from the asset's highest and best use, and the categorization by level in the fair value hierarchy for items required to be measured at fair value for disclosure purposes only. These changes become effective on January 1, 2012. We are currently evaluating the potential impact of these changes on the consolidated financial statements.
In June 2011, the FASB issued changes to the presentation of comprehensive income. These changes give an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements; the option to present components of other comprehensive income as part of the statement of changes in stockholders' equity was eliminated. The items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income were not changed. Additionally, no changes were made to the calculation and presentation of earnings per share. These changes become effective on January 1, 2012. We are currently evaluating these changes to determine which option will be chosen for the presentation of comprehensive income. Other than the change in presentation, we have determined these changes will not have an impact on the consolidated financial statements
2. Comprehensive income (loss)
The following table summarizes the components of comprehensive income (loss) for the three and six-month periods ended June 30, 2011 and 2010:
|
Three months ended June 30, |
Six months ended June 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2011 | 2010 | 2011 | 2010 | |||||||||
Net income (loss) |
$ | 13,069 | $ | 1,364 | $ | 19,051 | $ | (4,747 | ) | ||||
Unrealized gain (loss) on hedging activity |
(107 | ) | 652 | 1,097 | 992 | ||||||||
less income tax (benefit) expense |
(43 | ) | 261 | 439 | 397 | ||||||||
Comprehensive income (loss) |
$ | 13,005 | $ | 1,755 | $ | 19,709 | $ | (4,152 | ) | ||||
8
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. Acquisitions and divestitures
- (a)
- Capital Power Income L.P.
On June 20, 2011, Atlantic Power, Capital Power Income L.P. ("CPILP"), CPI Income Services Ltd., the general partner of CPILP, and CPI Investments Inc., a unitholder of CPILP that is owned by EPCOR Utilities Inc. and Capital Power Corporation, entered into the Arrangement Agreement, which provides that Atlantic Power will acquire, directly or indirectly, all of the issued and outstanding CPILP units pursuant to the Plan of Arrangement under the Canada Business Corporations Act. Under the terms of the Plan of Arrangement, CPILP unitholders will be permitted to exchange each of their CPILP units for, at their election, Cdn$19.40 in cash or 1.3 Atlantic Power common shares. All cash elections will be subject to proration if total cash elections exceed approximately Cdn$506.5 million and all share elections will be subject to proration if total share elections exceed approximately 31.5 million Atlantic Power common shares.
Pursuant to the Plan of Arrangement, CPILP will sell its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power, for approximately Cdn$121.0 million which equates to approximately Cdn$2.15 per unit of CPILP. Additionally, in connection with the Plan of Arrangement, the management agreements between certain subsidiaries of Capital Power and CPILP and certain of its subsidiaries will be terminated (or assigned) in consideration of a payment of Cdn$10.0 million. Atlantic Power or its subsidiaries will assume the management of CPILP and enter into a transitional services agreement with Capital Power for a term of 6 to 9 months following the completion of the Plan of Arrangement, which will facilitate the integration of CPILP into Atlantic Power.
The Arrangement Agreement contains customary representations, warranties and covenants. Among these covenants, CPILP and CPI Income Services Ltd. have each agreed not to solicit alternative transactions, except that CPILP may respond to an alternative transaction proposal that constitutes, or would reasonably expect to lead to, a superior proposal that we would have the right to match. In addition, Atlantic Power or CPILP may be required to pay a Cdn$35.0 million fee if the Arrangement Agreement is terminated in certain unlikely circumstances.
The completion of the Plan of Arrangement is subject to the receipt of all necessary court and regulatory approvals in Canada and the United States and certain other closing conditions. Atlantic Power and CPILP currently expect to complete the Plan of Arrangement in the fourth quarter of 2011, subject to receipt of required shareholder/unitholder, court and regulatory approvals and the satisfaction or waiver of the financing and other conditions to the Plan of Arrangement described in the Arrangement Agreement.
- (b)
- Topsham
On February 28, 2011, we entered into a purchase and sale agreement with an affiliate of ArcLight Capital Partners, LLC ("ArcLight") for the purchase of our lessor interest in the project. The transaction closed on May 6, 2011 and we received proceeds of $8.5 million, resulting in no gain or loss on the sale.
9
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. Equity method investments
The following summarizes the operating results for the three and six months ended June 30, 2011 and 2010, respectively, for our equity earnings interest in our equity method investments:
|
Three-months ended June 30, |
Six-months ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2011 | 2010 | 2011 | 2010 | ||||||||||
Revenue |
||||||||||||||
Chambers |
13,009 | 13,329 | 26,278 | 28,746 | ||||||||||
Badger Creek |
1,334 | 3,213 | 4,655 | 7,103 | ||||||||||
Gregory |
7,633 | 7,687 | 14,814 | 16,553 | ||||||||||
Orlando |
9,375 | 10,321 | 19,302 | 20,760 | ||||||||||
Selkirk |
12,961 | 12,564 | 23,861 | 26,043 | ||||||||||
Other |
3,132 | 1,930 | 4,952 | 3,170 | ||||||||||
|
47,444 | 49,044 | 93,862 | 102,375 | ||||||||||
Project expenses |
||||||||||||||
Chambers |
9,545 | 10,026 | 18,925 | 20,292 | ||||||||||
Badger Creek |
1,414 | 2,755 | 4,398 | 6,225 | ||||||||||
Gregory |
6,900 | 6,472 | 13,530 | 14,697 | ||||||||||
Orlando |
9,605 | 9,869 | 19,068 | 19,915 | ||||||||||
Selkirk |
12,631 | 11,921 | 25,289 | 24,749 | ||||||||||
Other |
2,366 | 1,349 | 3,795 | 2,443 | ||||||||||
|
42,461 | 42,392 | 85,005 | 88,321 | ||||||||||
Project other income (expense) |
||||||||||||||
Chambers |
(663 | ) | (844 | ) | (1,090 | ) | (1,751 | ) | ||||||
Badger Creek |
(7 | ) | 193 | (11 | ) | 195 | ||||||||
Gregory |
(194 | ) | (891 | ) | (231 | ) | (685 | ) | ||||||
Orlando |
(13 | ) | (33 | ) | (44 | ) | (66 | ) | ||||||
Selkirk |
(929 | ) | (1,988 | ) | (2,566 | ) | (3,087 | ) | ||||||
Other |
(1,215 | ) | (63 | ) | (1,642 | ) | (198 | ) | ||||||
|
(3,021 | ) | (3,626 | ) | (5,584 | ) | (5,592 | ) | ||||||
Project income (loss) |
||||||||||||||
Chambers |
2,801 | 2,459 | 6,263 | 6,703 | ||||||||||
Badger Creek |
(87 | ) | 651 | 246 | 1,073 | |||||||||
Gregory |
539 | 324 | 1,053 | 1,171 | ||||||||||
Orlando |
(243 | ) | 419 | 190 | 779 | |||||||||
Selkirk |
(599 | ) | (1,345 | ) | (3,994 | ) | (1,793 | ) | ||||||
Other |
(449 | ) | 518 | (485 | ) | 529 | ||||||||
|
1,962 | 3,026 | 3,273 | 8,462 |
10
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. Accumulated depreciation and amortization
The following table presents accumulated depreciation of property, plant and equipment and the accumulated amortization of transmission system rights and other intangible assets as of June 30, 2011 and December 31, 2010:
|
June 30, 2011 |
December 31, 2010 |
|||||
---|---|---|---|---|---|---|---|
Property, plant and equipment |
$ | 98,248 | $ | 91,851 | |||
Transmission system rights |
47,461 | 43,535 | |||||
Other intangible assets |
68,472 | 57,000 |
6. Long-term debt
Long-term debt represents project-level long-term debt of our consolidated subsidiaries and the unamortized balance of purchase accounting adjustments that were recorded in connection with the Path 15 acquisition in order to adjust the debt to its fair value on the acquisition date. Project-level debt is non-recourse to Atlantic Power and generally amortizes during the term of the respective revenue generating contracts of the projects.
|
June 30, 2011 |
December 31, 2010 |
|||||
---|---|---|---|---|---|---|---|
Project debt, interest rates ranging from 5.1% to 9.0% maturing through 2028 |
$ | 274,131 | $ | 254,581 | |||
Purchase accounting fair value adjustments |
10,942 | 11,305 | |||||
Less: current portion of long-term debt |
(21,962 | ) | (21,587 | ) | |||
Long-term debt |
$ | 263,111 | $ | 244,299 | |||
Project-level debt is secured by the respective project and its contracts with no other recourse to us. The loans have certain financial covenants that must be met. At June 30, 2011, all of our projects were in compliance with the covenants contained in the project-level debt. However, the holding company for our investment in the Chambers project, Epsilon Power Partners and the Delta-Person project had not achieved the levels of debt service coverage ratios required by the project-level debt arrangements as a condition to make distributions and were therefore restricted from making distributions to us.
As of June 30, 2011 the inception to date balance on the Piedmont construction debt funded by the related bridge loan was $29.9 million. The Piedmont debt outstanding is funded by the bridge loan. The terms of the Piedmont project-level debt refinancing include an $82.0 million construction and term loan and a $51.0 million bridge loan for approximately 95.0% of the stimulus grant expected to be received from the U.S. Treasury 60 days after the start of commercial operations. The $51.0 million bridge loan will be repaid in 2012 and repayment of the expected $82.0 million term loan will commence in 2013.
11
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. Convertible debentures
The following table contains details related to outstanding convertible debentures:
|
6.5% Debentures due 2014 |
6.25% Debentures due 2017 |
5.6% Debentures due 2017 |
|||||||
---|---|---|---|---|---|---|---|---|---|---|
Balance at December 31, 2010 (Cdn$) |
55,801 | 83,124 | 80,500 | |||||||
Principal amount converted to equity (Cdn$) |
(8,899 | ) | (8,267 | ) | | |||||
Balance at June 30, 2011 (Cdn$) |
46,902 | 74,857 | 80,500 | |||||||
Balance at June 30, 2011 (US$) |
48,628 | 77,612 | 83,463 | |||||||
Common shares issued on conversion during the six-months ended June 30, 2011 |
717,653 |
635,919 |
|
Aggregate interest expense related to the convertible debentures was $3.0 million and $2.1 million for the three-month periods ended June 30, 2011 and 2010, respectively, and $6.4 million and $4.4 million for the six-month periods ended June 30, 2011 and 2010, respectively.
8. Fair value of financial instruments
The following represents our financial assets and liabilities that were recognized at fair value as of June 30, 2011 and December 31, 2010. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
|
June 30, 2011 | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Level 1 | Level 2 | Level 3 | Total | ||||||||||
Assets: |
||||||||||||||
Cash and cash equivalents |
$ | 46,551 | $ | | $ | | $ | 46,551 | ||||||
Restricted cash |
21,034 | | | 21,034 | ||||||||||
Derivative instruments asset |
| 28,162 | | 28,162 | ||||||||||
Total |
$ | 67,585 | $ | 28,162 | $ | | $ | 95,747 | ||||||
Liabilities: |
||||||||||||||
Derivative instruments liability |
$ | | $ | 32,232 | $ | | $ | 32,232 | ||||||
Total |
$ | | $ | 32,232 | $ | | $ | 32,232 | ||||||
|
December 31, 2010 | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Level 1 | Level 2 | Level 3 | Total | ||||||||||
Assets: |
||||||||||||||
Cash and cash equivalents |
$ | 45,497 | $ | | $ | | $ | 45,497 | ||||||
Restricted cash |
15,744 | | | 15,744 | ||||||||||
Derivative instruments asset |
| 26,749 | | 26,749 | ||||||||||
Total |
$ | 61,241 | $ | 26,749 | $ | | $ | 87,990 | ||||||
Liabilities: |
||||||||||||||
Derivative instruments liability |
$ | | $ | 31,552 | $ | | $ | 31,552 | ||||||
Total |
$ | | $ | 31,552 | $ | | $ | 31,552 | ||||||
12
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. Fair value of financial instruments (Continued)
The fair value of our derivative instruments are based on price quotes from brokers in active markets who regularly facilitate those transactions and we believe such price quotes are executable. We adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating or the credit rating of our counterparties. As of June 30, 2011, the credit reserve resulted in a $0.6 million net increase in fair value, which is attributable to a $0.4 million pre-tax gain in other comprehensive income and a $0.4 million gain in change in fair value of derivative instruments, partially offset by a $0.2 million loss in foreign exchange. As of December 31, 2010, the credit reserve resulted in a $0.6 million net increase in fair value, which is attributable to a $0.2 million pre-tax gain in other comprehensive income and a $0.5 million gain in change in fair value of derivative instruments, partially offset by a $0.1 million loss in foreign exchange.
9. Accounting for derivative instruments and hedging activities
Fair value of derivative instruments
We have elected to disclose derivative instrument assets and liabilities on a trade-by-trade basis and do not offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities:
|
June 30, 2011 | |||||||
---|---|---|---|---|---|---|---|---|
|
Derivative Assets |
Derivative Liabilities |
||||||
Derivative instruments designated as cash flow hedges: |
||||||||
Interest rate swaps current |
$ | | $ | 1,923 | ||||
Interest rate swaps long-term |
| 2,914 | ||||||
Total derivative instruments designated as cash flow hedges |
| 4,837 | ||||||
Derivative instruments not designated as cash flow hedges: |
||||||||
Interest rate swaps current |
| 2,317 | ||||||
Interest rate swaps long-term |
2,580 | 2,910 | ||||||
Foreign currency forward contracts current |
9,297 | | ||||||
Foreign currency forward contracts long-term |
16,285 | | ||||||
Natural gas swaps current |
| 3,170 | ||||||
Natural gas swaps long-term |
| 18,998 | ||||||
Total derivative instruments not designated as cash flow hedges |
28,162 | 27,395 | ||||||
Total derivative instruments |
$ | 28,162 | $ | 32,232 | ||||
13
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Accounting for derivative instruments and hedging activities (Continued)
|
December 31, 2010 | |||||||
---|---|---|---|---|---|---|---|---|
|
Derivative Assets | Derivative Liabilities | ||||||
Derivative instruments designated as cash flow hedges: |
||||||||
Interest rate swaps current |
$ | | $ | 2,124 | ||||
Interest rate swaps long-term |
| 2,626 | ||||||
Total derivative instruments designated as cash flow hedges |
| 4,750 | ||||||
Derivative instruments not designated as cash flow hedges: |
||||||||
Interest rate swaps current |
| 1,286 | ||||||
Interest rate swaps long-term |
3,299 | 2,000 | ||||||
Foreign currency forward contracts current |
8,865 | | ||||||
Foreign currency forward contracts long-term |
14,585 | | ||||||
Natural gas swaps current |
| 6,599 | ||||||
Natural gas swaps long-term |
| 16,917 | ||||||
Total derivative instruments not designated as cash flow hedges |
26,749 | 26,802 | ||||||
Total derivative instruments |
$ | 26,749 | $ | 31,552 | ||||
Natural gas swaps
The Lake project's operating margin is exposed to changes in natural gas spot market prices through the expiration of its PPA on July 31, 2013. The Auburndale project purchases natural gas under a fuel supply agreement which provides approximately 80% of the project's fuel requirements at fixed prices through June 30, 2012. The remaining 20% is purchased at spot market prices and therefore the project is exposed to changes in natural gas prices for that portion of its gas requirements through the termination of the fuel supply agreement and 100% of its natural gas requirements from the expiration of the fuel supply agreement in mid-2012 until the termination of its PPA at the end of 2013.
In October 2010, we entered into natural gas swaps that are effective in 2014 and 2015. The natural gas swaps are related to our 50% share of expected fuel purchases at our Orlando project as its operating margin is exposed to changes in natural gas prices following the expiration of its fuel contract at the end of 2013. In 2014, both the projected natural gas prices and the prices of these natural gas swaps are lower than the current price of natural gas being purchased under the project's gas contract. These financial swaps effectively fix the price of 1.2 million Mmbtu of natural gas at the Orlando project at a weighted average price of $5.76/Mmbtu and represent approximately 25% of our share of the expected natural gas purchases at the project during 2014 and 2015. These swap agreements were entered into by us and not at the project level. Orlando is accounted for under the equity method of accounting.
Our strategy to mitigate the future exposure to changes in natural gas prices at Lake, Auburndale and Orlando consists of periodically entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheet at fair value.
14
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Accounting for derivative instruments and hedging activities (Continued)
Interest Rate Swaps
We have executed an interest rate swap at our consolidated Auburndale project to economically fix a portion of its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the project-level Auburndale debt agreement. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 3.12%. The notional amount of the swap matches the outstanding principal balance over the remaining life of Auburndale's debt. The interest rate swap was executed in November 2009 and expires on November 30, 2013.
The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.02% from February 16, 2011 to February 15, 2015, 6.14% from February 16, 2015 to February 15, 2019, 6.26% from February 16, 2019 to February 15, 2023, and 6.38% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac's debt. This swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025.
We executed two interest rate swaps at our consolidated Piedmont project to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreements are not designated as hedges and changes in their fair market value are recorded in the consolidated statements of operations. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.75% from March 31, 2011 to February 29, 2016. From February 2016 until the maturity of the debt in November 2017, the fixed rate of the swap is 4.47% and the applicable margin is 4.0%, resulting in an all-in rate of 8.47%. The swap continues at the fixed rate of 4.47% from the maturity of the debt in November 2017 until November 2030. The notional amounts of the interest rate swap agreements match the estimated outstanding principal balance of Piedmont's cash grant bridge loan and the construction loan facility which will convert to a term loan. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively.
Impact of derivative instruments on the consolidated income statements
Unrealized gains (losses) on interest rate swaps designated as cash flow hedges have been recorded, net of tax, in shareholders' equity in other comprehensive income as a loss of $0.1 million and a gain of $0.4 million for the three-month periods ended June 30, 2011 and 2010, respectively, and a gain of $0.7 million and $0.6 million for the six-month periods ended June 30, 2011 and 2010 respectively. Settlements of these interest rate swaps of $0.6 million and $0.4 million were recorded in interest expense, net for the three-month periods ended June 30, 2011 and 2010, respectively, and $1.2 million and $0.7 million for the six-month periods ended June 30, 2011 and 2010, respectively.
Unrealized gains and losses on natural gas swaps previously designated as cash flow hedges are recorded in other comprehensive income. In the period in which the unrealized gains and losses are settled, the cash settlement payments are recorded as fuel expense. A $5.1 million loss was recorded in other comprehensive loss for natural gas swap contracts accounted for as cash flow hedges prior to July 1, 2009 when hedge accounting for these natural gas swaps was discontinued prospectively. Amortization of the remaining loss in other comprehensive income of $(0.2) million and $0.4 million was recorded in change in fair value of derivative instruments for the three-month periods ended
15
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Accounting for derivative instruments and hedging activities (Continued)
June 30, 2011 and 2010, respectively, and $(0.3) million and $0.8 million for the six-month periods ended June 30, 2011 and 2010, respectively.
Unrealized gains and losses on derivative instruments not designated as cash flow hedges are recorded in change in fair value of derivative instruments in the consolidated statements of operations.
The following table summarizes realized (gains) and losses for derivative instruments not designated as cash flow hedges:
|
|
Three months ended | Six months ended | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Classification of (gain) loss recognized in income |
June 30, 2011 |
June 30, 2010 |
June 30, 2011 |
June 30, 2010 |
||||||||||
Natural gas swaps |
Fuel | $ | 2,055 | $ | 2,621 | $ | 4,531 | $ | 4,439 | ||||||
Foreign currency forwards |
Foreign exchange (gain) loss | (3,155 | ) | (1,599 | ) | (5,692 | ) | (2,767 | ) | ||||||
Interest rate swaps |
Interest, net | 955 | 474 | 1,931 | 949 |
Unrealized gains and losses associated with changes in the fair value of derivative instruments not designated as cash flow hedges and ineffectiveness of derivatives designated as cash flow hedges are reflected in current period earnings. The following table summarizes the pre-tax gains and (losses) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:
|
Three months ended June 30, |
Six months ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2011 | 2010 | 2011 | 2010 | ||||||||||
Change in fair value of derivative instruments: |
||||||||||||||
Interest rate swaps |
$ | (3,337 | ) | $ | (120 | ) | $ | (2,659 | ) | $ | (166 | ) | ||
Natural gas swaps |
(1,237 | ) | 1,112 | 1,646 | (11,036 | ) | ||||||||
|
$ | (4,574 | ) | $ | 992 | $ | (1,013 | ) | $ | (11,202 | ) | |||
Volume of forecasted transactions
We entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the normal purchases and normal sales exception as of June 30, 2011:
|
Units | June 30, 2011 |
||||
---|---|---|---|---|---|---|
Interest rate swaps |
Interest (US$) | $ | 55,147 | |||
Currency forwards |
Dollars (Cdn$) | $ | 181,900 | |||
Natural gas swaps |
Natural Gas (Mmbtu) | 13,660 |
16
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Accounting for derivative instruments and hedging activities (Continued)
Foreign currency forward contracts
We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates, as we generate cash flow in U.S. dollars but pay dividends to shareholders and interest on convertible debentures predominantly in Canadian dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on the long-term sustainability of dividends to shareholders. We have executed this strategy by entering into forward contracts to purchase Canadian dollars at a fixed rate to hedge approximately 86% of our expected dividend and convertible debenture interest payments through 2013. Changes in the fair value of the forward contracts partially offset foreign exchange gain or losses on the U.S. dollar equivalent of our Canadian dollar obligations. The forward contracts consist of (1) monthly purchases through the end of 2013 of Cdn$6.0 million at an exchange rate of Cdn$1.134 per U.S. dollar and (2) purchases in both April and October 2011 of Cdn$1.9 million at an exchange rate of Cdn$1.1075 per U.S. dollar.
It is our intention to periodically consider extending the length of these forward contracts.
The foreign exchange forward contracts are recorded at fair value based on quoted market prices and our estimation of the counterparty's credit risk. The fair value of our forward foreign currency contracts is $25.6 million and $23.4 million at June 30, 2011 and December 31, 2010, respectively. Changes in the fair value of the foreign currency forward contracts are recorded in foreign exchange (gain) loss in the consolidated statements of operations.
The following table contains the components of recorded foreign exchange (gain) loss for the three and six-month periods ended June 30, 2011 and 2010:
|
Three months ended June 30, |
Six months ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2011 | 2010 | 2011 | 2010 | ||||||||||
Unrealized foreign exchange (gain) loss: |
||||||||||||||
Convertible debentures |
$ | 1,317 | $ | (6,486 | ) | $ | 6,632 | $ | (2,505 | ) | ||||
Forward contracts and other |
1,303 | 12,309 | (2,133 | ) | 7,704 | |||||||||
|
2,620 | 5,823 | 4,499 | 5,199 | ||||||||||
Realized foreign exchange gains on forward contract settlements |
(3,155 | ) | (1,599 | ) | (5,692 | ) | (2,767 | ) | ||||||
|
$ | (535 | ) | $ | 4,224 | $ | (1,193 | ) | $ | 2,432 | ||||
The following table illustrates the impact on our financial instruments of a 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar as of June 30, 2011:
Convertible debentures, at carrying value |
$ | 20,970 | ||
Foreign currency forward contracts |
$ | (20,548 | ) |
17
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Accounting for derivative instruments and hedging activities (Continued)
The following table summarizes the changes in the accumulated other comprehensive income (loss) ("OCI") balance attributable to derivative financial instruments designated as a hedge, net of tax:
For the three month period ended June 30, 2011
|
Interest Rate Swaps |
Natural Gas Swaps |
Total | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Accumulated OCI balance at March 31, 2011 |
$ | (66 | ) | $ | 593 | $ | 527 | |||
Change in fair value of cash flow hedges |
(64 | ) | | (64 | ) | |||||
Realized from OCI during the period |
(349 | ) | (90 | ) | (439 | ) | ||||
Accumulated OCI balance at June 30, 2011 |
$ | (479 | ) | $ | 503 | $ | 24 | |||
For the three month period ended June 30, 2010
|
Interest Rate Swaps |
Natural Gas Swaps |
Total | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Accumulated OCI balance at March 31, 2010 |
$ | (554 | ) | $ | (73 | ) | $ | (627 | ) | |
Change in fair value of cash flow hedges |
391 | | 391 | |||||||
Realized from OCI during the period |
(211 | ) | 253 | 42 | ||||||
Accumulated OCI balance at June 30, 2010 |
$ | (374 | ) | $ | 180 | $ | (194 | ) | ||
For the six month period ended June 30, 2011
|
Interest Rate Swaps |
Natural Gas Swaps |
Total | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Accumulated OCI balance at December 31, 2010 |
$ | (427 | ) | $ | 682 | $ | 255 | |||
Change in fair value of cash flow hedges |
658 | | 658 | |||||||
Realized from OCI during the period |
(710 | ) | (179 | ) | (889 | ) | ||||
Accumulated OCI balance at June 30, 2011 |
$ | (479 | ) | $ | 503 | $ | 24 | |||
For the six month period ended June 30, 2010
|
Interest Rate Swaps |
Natural Gas Swaps |
Total | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Accumulated OCI balance at December 31, 2009 |
$ | (538 | ) | $ | (321 | ) | $ | (859 | ) | |
Change in fair value of cash flow hedges |
595 | | 595 | |||||||
Realized from OCI during the period |
(431 | ) | 501 | 70 | ||||||
Accumulated OCI balance at June 30, 2010 |
$ | (374 | ) | $ | 180 | $ | (194 | ) | ||
18
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
10. Income taxes
The difference between the actual tax benefit of $7.7 million and $6.2 million for the three and six months ended June 30, 2011, respectively, and the expected income tax expense, based on the Canadian enacted statutory rate of 26.5%, of $1.4 million and $3.4 million, respectively is primarily due to the change in basis of the Idaho Wind assets due to the receipt of the proceeds of the stimulus grant as well as a decrease in the valuation allowance and various other permanent differences.
|
Three months ended June 30, |
Six months ended June 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2011 | 2010 | 2011 | 2010 | |||||||||
Current income tax expense (benefit) |
$ | 18 | $ | 1,038 | $ | (470 | ) | $ | 1,075 | ||||
Deferred tax expense (benefit) |
(7,702 | ) | 2,580 | (5,691 | ) | 7,416 | |||||||
Total income tax expense (benefit) |
$ | (7,684 | ) | $ | 3,618 | $ | (6,161 | ) | $ | 8,491 | |||
Valuation Allowance
As of June 30, 2011, we have recorded a valuation allowance of $78.4 million. This amount is comprised primarily of provisions against available Canadian and U.S net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.
11. Long-Term Incentive Plan
The following table summarizes the changes in outstanding LTIP notional units during the six months ended June 30, 2011:
|
Units | Grant Date Weighted-Average Price per Unit |
|||||
---|---|---|---|---|---|---|---|
Outstanding at December 31, 2010 |
600,981 | $ | 10.28 | ||||
Granted |
153,094 | $ | 14.18 | ||||
Forfeited |
(101,559 | ) | $ | 11.61 | |||
Additional shares from dividends |
20,302 | $ | 10.95 | ||||
Vested and redeemed |
(263,523 | ) | $ | 9.40 | |||
Outstanding at June 30, 2011 |
409,295 | $ | 11.85 | ||||
Certain awards have a market condition based on our total shareholder return during the performance period compared to a group of peer companies. Compensation expense for notional units granted in 2011 is recorded net of estimated forfeitures. See further details as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010.
19
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. Long-Term Incentive Plan (Continued)
The calculation of simulated total shareholder return under the Monte Carlo model for the remaining time in the performance period for awards with market conditions included the following assumptions as of June 30, 2011:
Weighted average risk free rate of return |
0.39% 0.72% | |
Dividend yield |
7.5% | |
Expected volatilityCompany |
20.5% 25.9% | |
Expected volatilitypeer companies |
15.2% 92.7% | |
Weighted average remaining measurement period |
1.26 years |
12. Basic and diluted earnings (loss) per share
Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average common shares outstanding during their respective period. Diluted earnings (loss) per share is computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include shares that would be issued if all of the convertible debentures were converted into shares at January 1, 2011. Dilutive potential shares also include the weighted average number of shares, as of the date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP were vested and redeemed for shares under the terms of the LTIP.
Because we reported a loss for the six months ended June 30, 2010, diluted earnings per share are equal to basic earnings per share as the inclusion of potentially dilutive shares in the computation is
20
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. Basic and diluted earnings (loss) per share (Continued)
anti-dilutive. The following table sets forth the diluted net income (loss) and potentially dilutive shares utilized in the per share calculation for the three and six month periods ended June 30, 2011 and 2010:
|
Three months ended June 30, |
Six months ended June 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2011 | 2010 | 2011 | 2010 | |||||||||
Numerator: |
|||||||||||||
Net income (loss) attributable to Atlantic Power Corporation |
$ | 13,186 | $ | 1,445 | $ | 19,322 | $ | (4,618 | ) | ||||
Add: interest expense for potentially dilutive convertible debentures, net(1) |
1,931 | | 3,985 | | |||||||||
Diluted net income (loss) attributable to Atlantic Power Corporation |
15,117 | 1,445 | 23,307 | (4,618 | ) | ||||||||
- (1)
- The above adjustment for net interest on the potential common shares that would be issued on the conversion of the convertible debentures has been excluded as the impact would be anti-dilutive for the three and six months ended June 30, 2010.
|
Three months ended June 30, |
Six months ended June 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2011 | 2010 | 2011 | 2010 | ||||||||||
Denominator: |
||||||||||||||
Weighted average basic shares outstanding |
68,573 | 60,481 | 68,116 | 60,443 | ||||||||||
Dilutive potential shares: |
||||||||||||||
Convertible debentures |
14,055 | 11,473 | 14,430 | 11,473 | ||||||||||
LTIP notional units |
311 | 409 | 427 | 402 | ||||||||||
Potentially dilutive shares |
82,939 | 72,363 | 82,973 | 72,318 | ||||||||||
Diluted EPS |
$ | 0.18 | $ | 0.02 | $ | 0.28 | $ | (0.08 | ) | |||||
Potentially dilutive shares from convertible debentures for the three and six-month periods ended June 30, 2010 have been excluded from fully diluted because their impact would be anti-dilutive.
13. Segment and related information
We have six reportable segments: Path 15, Auburndale, Lake, Pasco, Chambers and Other Project Assets.
We analyze the performance of our operating segments based on Project Adjusted EBITDA which is defined as project income plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are
21
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Segment and related information (Continued)
required to be recorded at fair value. A reconciliation of project income to Project Adjusted EBITDA is included in the table below.
|
Path 15 | Auburndale | Lake | Pasco | Chambers | Other Project Assets |
Un-allocated Corporate |
Consolidated | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Three month period ended June 30, 2011: |
|||||||||||||||||||||||||
Operating revenues |
$ | 7,491 | $ | 20,434 | $ | 16,844 | $ | 3,382 | $ | 0 | $ | 5,107 | $ | 0 | $ | 53,258 | |||||||||
Segment assets |
207,838 | 98,152 | 105,782 | 37,564 | 147,572 | 329,052 | 83,020 | 1,008,980 | |||||||||||||||||
Project Adjusted EBITDA |
$ | 7,186 | $ | 11,606 | $ | 8,424 | $ | 1,469 | $ | 4,307 | $ | 9,862 | $ | 0 | $ | 42,854 | |||||||||
Change in fair value of derivative instruments |
| 1,145 | (297 | ) | | 200 | 3,778 | | 4,826 | ||||||||||||||||
Depreciation and amortization |
2,005 | 4,959 | 2,290 | 757 | 844 | 6,806 | | 17,661 | |||||||||||||||||
Interest, net |
2,943 | 282 | (2 | ) | | 1,413 | 2,452 | | 7,088 | ||||||||||||||||
Other project (income) expense |
| | | | 201 | 47 | | 248 | |||||||||||||||||
Project income |
2,238 | 5,220 | 6,433 | 712 | 1,649 | (3,221 | ) | | 13,031 | ||||||||||||||||
Interest, net |
| | | | | | 3,510 | 3,510 | |||||||||||||||||
Administration |
| | | | | | 4,671 | 4,671 | |||||||||||||||||
Foreign exchange gain |
| | | | | | (535 | ) | (535 | ) | |||||||||||||||
Income (loss) from operations before income taxes |
2,238 | 5,220 | 6,433 | 712 | 1,649 | (3,221 | ) | (7,646 | ) | 5,385 | |||||||||||||||
Income tax expense (benefit) |
| | | | | | (7,684 | ) | (7,684 | ) | |||||||||||||||
Net income (loss) |
2,238 | 5,220 | 6,433 | 712 | 1,649 | (3,221 | ) | 38 | 13,069 | ||||||||||||||||
|
Path 15 | Auburndale | Lake | Pasco | Chambers | Other Project Assets | Un-allocated Corporate | Consolidated | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Three month period ended June 30, 2010: |
|||||||||||||||||||||||||
Operating revenues |
$ | 7,729 | $ | 19,570 | $ | 17,842 | $ | 2,763 | $ | 0 | $ | 0 | $ | 0 | $ | 47,904 | |||||||||
Segment assets |
213,904 | 121,303 | 115,822 | 40,620 | 136,351 | 131,560 | 102,964 | 862,524 | |||||||||||||||||
Project Adjusted EBITDA |
$ | 7,062 | $ | 10,431 | $ | 7,299 | $ | 1,002 | $ | 4,141 | $ | 8,591 | $ | 0 | $ | 38,526 | |||||||||
Change in fair value of derivative instruments |
| 597 | (1,709 | ) | | (207 | ) | 1,529 | | 210 | |||||||||||||||
Depreciation and amortization |
2,095 | 4,950 | 2,267 | 746 | 839 | 5,699 | | 16,596 | |||||||||||||||||
Interest, net |
3,096 | 415 | (4 | ) | | 1,651 | 939 | | 6,097 | ||||||||||||||||
Other project (income) expense |
| | | | 204 | (122 | ) | | 82 | ||||||||||||||||
Project income |
1,871 | 4,469 | 6,745 | 256 | 1,654 | 546 | | 15,541 | |||||||||||||||||
Interest, net |
| | | | | | 2,518 | 2,518 | |||||||||||||||||
Administration |
| | | | | | 3,843 | 3,843 | |||||||||||||||||
Foreign exchange loss |
| | | | | | 4,224 | 4,224 | |||||||||||||||||
Other expense, net |
| | | | | | (26 | ) | (26 | ) | |||||||||||||||
Income (loss) from operations before income taxes |
1,871 | 4,469 | 6,745 | 256 | 1,654 | 546 | (10,559 | ) | 4,982 | ||||||||||||||||
Income tax expense (benefit) |
990 | | | | | | 2,628 | 3,618 | |||||||||||||||||
Net income (loss) |
881 | 4,469 | 6,745 | 256 | 1,654 | 546 | (13,187 | ) | 1,364 | ||||||||||||||||
22
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Segment and related information (Continued)
|
Path 15 | Auburndale | Lake | Pasco | Chambers | Other Project Assets | Un-allocated Corporate | Consolidated | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Six month period ended June 30, 2011: |
|||||||||||||||||||||||||
Operating revenues |
$ | 15,135 | $ | 42,216 | $ | 33,968 | $ | 5,902 | $ | 0 | $ | 9,702 | $ | 0 | $ | 106,923 | |||||||||
Segment assets |
207,838 | 98,152 | 105,782 | 37,564 | 147,572 | 329,052 | 83,020 | 1,008,980 | |||||||||||||||||
Project Adjusted EBITDA |
$ | 13,756 | $ | 21,919 | $ | 16,914 | $ | 392 | $ | 9,031 | $ | 16,835 | $ | 0 | $ | 78,847 | |||||||||
Change in fair value of derivative instruments |
| 184 | (1,862 | ) | | (552 | ) | 4,272 | | 2,042 | |||||||||||||||
Depreciation and amortization |
3,979 | 9,918 | 4,580 | 1,514 | 1,679 | 13,428 | | 35,098 | |||||||||||||||||
Interest, net |
5,934 | 595 | (5 | ) | | 2,801 | 4,003 | | 13,328 | ||||||||||||||||
Other project (income) expense |
| | | | 400 | 79 | | 479 | |||||||||||||||||
Project income |
3,843 | 11,222 | 14,201 | (1,122 | ) | 4,703 | (4,947 | ) | | 27,900 | |||||||||||||||
Interest, net |
| | | | | | 7,478 | 7,478 | |||||||||||||||||
Administration |
| | | | | | 8,725 | 8,725 | |||||||||||||||||
Foreign exchange gain |
| | | | | | (1,193 | ) | (1,193 | ) | |||||||||||||||
Income (loss) from operations before income taxes |
3,843 | 11,222 | 14,201 | (1,122 | ) | 4,703 | (4,947 | ) | (15,010 | ) | 12,890 | ||||||||||||||
Income tax expense (benefit) |
| | | | | | (6,161 | ) | (6,161 | ) | |||||||||||||||
Net income (loss) |
3,843 | 11,222 | 14,201 | (1,122 | ) | 4,703 | (4,947 | ) | (8,849 | ) | 19,051 | ||||||||||||||
|
Path 15 | Auburndale | Lake | Pasco | Chambers | Other Project Assets | Un-allocated Corporate | Consolidated | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Six month period ended June 30, 2010: |
|||||||||||||||||||||||||
Operating revenues |
$ | 15,373 | $ | 40,037 | $ | 34,083 | $ | 5,632 | $ | 0 | $ | 0 | $ | 0 | $ | 95,125 | |||||||||
Segment assets |
213,904 | 121,303 | 115,822 | 40,620 | 136,351 | 131,560 | 102,964 | 862,524 | |||||||||||||||||
|
3,535 | ||||||||||||||||||||||||
Project Adjusted EBITDA |
$ | 14,115 | $ | 19,802 | $ | 14,612 | $ | 2,417 | $ | 10,129 | $ | 16,200 | $ | 0 | $ | 77,275 | |||||||||
Change in fair value of derivative instruments |
| 4,809 | 6,226 | | (380 | ) | 2,074 | | 12,729 | ||||||||||||||||
Depreciation and amortization |
4,194 | 9,898 | 4,536 | 1,492 | 1,676 | 11,186 | | 32,982 | |||||||||||||||||
Interest, net |
6,242 | 886 | (6 | ) | | 3,327 | 1,429 | | 11,878 | ||||||||||||||||
Other project (income) expense |
| | | | 403 | (122 | ) | | 281 | ||||||||||||||||
Project income |
3,679 | 4,209 | 3,856 | 925 | 5,103 | 1,633 | | 19,405 | |||||||||||||||||
Interest, net |
| | | | | | 5,312 | 5,312 | |||||||||||||||||
Administration |
| | | | | | 7,943 | 7,943 | |||||||||||||||||
Foreign exchange gain |
| | | | | | 2,432 | 2,432 | |||||||||||||||||
Other expense, net |
| | | | | | (26 | ) | (26 | ) | |||||||||||||||
Income (loss) from operations before income taxes |
3,679 | 4,209 | 3,856 | 925 | 5,103 | 1,633 | (15,661 | ) | 3,744 | ||||||||||||||||
Income tax expense (benefit) |
1,739 | | | | | | 6,752 | 8,491 | |||||||||||||||||
Net income (loss) |
1,940 | 4,209 | 3,856 | 925 | 5,103 | 1,633 | (22,413 | ) | (4,747 | ) | |||||||||||||||
Progress Energy Florida and the California Independent System Operator ("CAISO") provide for 69% and 14%, respectively, of total consolidated revenues for the three-months ended June 30, 2011 and 77% and 16% for the three-months ended June 30, 2010. Progress Energy Florida and CAISO provide for 70% and 14%, respectively, of total consolidated revenues for the six-months ended June 30, 2011 and 77% and 16% for the six-months ended June 30, 2010. Progress Energy Florida purchases electricity from Auburndale and Lake, and the CAISO makes payments to Path 15.
23
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. Related party transactions
On February 28, 2011, we entered into a purchase and sale agreement with an affiliate of ArcLight for the purchase of our lessor interest in the Topsham project. The transaction closed on May 6, 2011 and we received proceeds of $8.5 million, resulting in no gain or loss on the sale.
During 2010, we made short-term loans totaling $22.8 million to Idaho Wind to provide temporary funding for construction of the project until a portion of the project-level construction financing is completed. Member loans will be paid down with a combination of excess proceeds from the federal stimulus grant after repaying the cash grant facility, funds from a third closing for additional debt and project cash flow. The federal stimulus grant was approved in June of 2011 and the funds have been received. The third closing from additional debt is expected by the end of the year. The outstanding loans bear interest at a prime rate plus 10% (13.25% as June 30, 2011). During the six-months ended June 30, 2011, we received $1.2 million in interest payments related to the member loans. As of August 10, 2011, $15.5 million of the loans have been repaid.
Prior to December 31, 2009, Atlantic Power was managed by Atlantic Power Management, LLC (the "Manager"), which was owned by two private equity funds managed by ArcLight. On December 31, 2009, we terminated our management agreements with the Manager and have agreed to pay the ArcLight funds an aggregate of $15.0 million, to be satisfied by a payment of $6.0 million that was made at the termination date, and additional payments of $5.0 million, $3.0 million and $1.0 million on the respective first, second and third anniversaries of the termination date. The remaining liability associated with the termination fee is recorded at its estimated fair value of $3.8 million at June 30, 2011. The contract termination liability is being accreted to the final amounts due over the term of these payments.
15. Commitments and contingencies
Our Lake project is currently involved in a dispute with Progress Energy Florida over off-peak energy sales in 2010. All amounts billed for off-peak energy during 2010 by the Lake project have been paid in full by Progress. The Lake project has filed a claim against Progress in which we seek to confirm our contractual right to sell off-peak energy at the contractual price for such sales. Progress filed a counter-claim against the Lake project, seeking, among other things, the return of amounts paid for off-peak power sales during 2010 and a declaratory order clarifying Lake's rights and obligations under the PPA. The Lake project has stopped dispatching during off-peak periods pending the outcome of the dispute. However, we strongly believe that the court will confirm our contractual right to sell off-peak power using the contractual price that was used during 2010 and that we will be able to continue such off-peak power sales for the remainder of the term of the PPA. We have not recorded any reserves related to this dispute and expect that the outcome will not have a material adverse effect on our financial position or results of operations.
From time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending as of June 30, 2011 which are expected to have a material adverse impact on our financial position or results of operations.
24
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
16. Subsequent event
On July 27, 2011, August 3, 2011 and August 5, 2011 we executed a series of financial transactions with an exercise date of January 18, 2012, to economically hedge a portion of the foreign currency exchange risk associated with the closing of the CPILP transaction.
The July 27, 2011 transactions include a forward purchase of $32.0 million at $0.9460 per Cdn$1.00, a call option to purchase $84.7 million at $0.94565 per Cdn$1.00 and a put option to sell $116.7 million at $0.90 per Cdn$1.00. The August 3, 2011 transactions include a forward purchase of $76.0 million at $0.9665 per Cdn$1.00, a call option to purchase $14.5 million at $0.9665 per Cdn$1.00 and a put option to sell $90.5 million at $0.90 per Cdn$1.00. The August 5, 2011 transactions include a forward purchase of $81.2 million at $0.9872 per Cdn$1.00, a call option to purchase $9.3 million at $0.9872 per Cdn$1.00 and a put option to sell $90.5 million at $0.90 per Cdn$1.00.
25
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Quarterly Report on Form 10-Q constitute "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements generally can be identified by the use of forward-looking terminology such as "outlook," "objective," "may," "will," "expect," "intend," "estimate," "anticipate," "believe," "should," "plans," "continue," or similar expressions suggesting future outcomes or events. Examples of such statements in this Quarterly Report on Form 10-Q include, but are not limited to, statements with respect to the following:
-
- the amount of distributions expected to be received from the projects for the full year 2011 and 2012;
-
- our expectation of higher operating cash flow in 2012, primarily attributable to increased distributions from Selkirk;
-
- our expectation of a significant increase in cash distributions from Orlando beginning in 2014;
-
- our forecast of expected annual cash distributions from the Lake and Auburndale projects through 2012;
-
- the expected resumption of distributions from the holding company on our Chambers project in 2012;
-
- the expectation of the Piedmont Construction to be completed in late 2012; and
-
- the expectation to complete the Plan of Arrangement in the fourth quarter.
Such forward-looking statements reflect our current expectations regarding future events and operating performance and speak only as of the date of this Quarterly Report on Form 10-Q. Such forward-looking statements are based on a number of assumptions which may prove to be incorrect, including, but not limited to the assumption that the projects will operate and perform in accordance with our expectations. Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not or the times at or by which such performance or results will be achieved. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking statements, including, but not limited to, the factors discussed under "Risk Factors" included in the filings we make from time to time with the SEC. Our business is both competitive and subject to various risks.
These risks include, without limitation:
-
- a reduction in revenue upon expiration or termination of power purchase agreements;
-
- the dependence of our projects on their electricity, thermal energy and transmission services customers;
-
- exposure of certain of our projects to fluctuations in the price of electricity or natural gas;
-
- projects not operating according to plan;
-
- the impact of significant environmental and other regulations on our projects;
-
- increased competition, including for acquisitions;
-
- our limited control over the operation of certain minority owned projects;
-
- the failure to receive, on a timely basis or otherwise, the required approvals by Atlantic Power shareholders, CPILP
unitholders and government or regulatory agencies (including the terms of such approvals) for the Plan of Arrangement; and
-
- the risk that a condition to closing of the transaction contemplated by the Arrangement Agreement may not be satisfied.
26
Other factors, such as general economic conditions, including exchange rate fluctuations, also may have an effect on the results of our operations. Many of these risks and uncertainties can affect our actual results and could cause our actual results to differ materially from those expressed or implied in any forward-looking statement made by us or on our behalf.
Material factors or assumptions that were applied in drawing a conclusion or making an estimate set out in the forward-looking information include third party projections of regional fuel and electric capacity and energy prices or cash flows that are based on assumptions about future economic conditions and courses of action. Although the forward-looking statements contained in this Quarterly Report on Form 10-Q are based upon what are believed to be reasonable assumptions, investors cannot be assured that actual results will be consistent with these forward-looking statements, and the differences may be material. Certain statements included in this Quarterly Report on Form 10-Q may be considered "financial outlook" for the purposes of applicable securities laws, and such financial outlook may not be appropriate for purposes other than this Quarterly Report on Form 10-Q.
These forward-looking statements are made as of the date of this Form 10-Q, except as expressly required by applicable law, we assume no obligation to update or revise them to reflect new events or circumstances.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of the financial condition and results of operations of Atlantic Power Corporation should be read in conjunction with the interim consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report on Form 10-Q.
OVERVIEW
Atlantic Power Corporation owns and operates a diverse fleet of power generation and infrastructure assets in the United States. Our power generation projects sell electricity to utilities and other large commercial customers under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,948 MW in which our ownership interest is approximately 871 MW. Our current portfolio consists of interests in 12 operational power generation projects across nine states, one biomass project under construction in Georgia, and a 500 kilovolt 84-mile electric transmission line located in California. We also own a majority interest in Rollcast Energy, a biomass power plant developer with several projects under development. We sell the capacity and energy from our power generation projects under power purchase agreements (or "PPAs") with a variety of utilities and other parties. Under the PPAs, which have expiration dates ranging from 2011 to 2037, we receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). We also sell steam from a number of our projects under steam sales agreements to industrial purchasers. The transmission system rights (or "TSRs") we own in our power transmission project entitle us to payments indirectly from the utilities that make use of the transmission line.
Our power generation projects generally operate pursuant to long-term fuel supply agreements, typically accompanied by fuel transportation arrangements. In most cases, the fuel supply and transportation arrangements correspond to the term of the relevant PPAs and many of the PPAs and steam sales agreements provide for the indexing or pass-through of fuel costs to our customers. In cases where there is not a pass-through of fuel costs, we use a financial hedging strategy designed to mitigate a portion of the market price risk of fuel purchases.
We partner with recognized leaders in the independent power industry to operate and maintain our projects, including Caithness Energy, LLC, Power Plant Management Services, Delta Power
27
Services and the Western Area Power Administration. Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.
We completed our initial public offering on the Toronto Stock Exchange (TSX: ATP) in November 2004. Our shares began trading on the NYSE under the symbol "AT" on July 23, 2010.
As of August 10, 2011, we had 68,963,203 common shares, Cdn$45.2 million ($47.5 million) principal amount of 6.50% convertible secured debentures due October 31, 2014 (the "2006 Debentures"), Cdn$72.4million ($76.1 million) principal amount of 6.25% convertible debentures due March 15, 2017 (the "2009 Debentures"), and Cdn$80.5 million ($84.6 million) principal amount of 5.60% convertible debentures due June 30, 2017 (the "2010 Debentures" and together with the 2006 and 2009 Debentures, the "Debentures") outstanding. The 2006 Debentures, 2009 Debentures and 2010 Debentures are convertible at any time, at the option of the holder, into 80.645, 76.923 and 55.249, respectively, common shares per Cdn$1,000 principal amount of Debentures, representing a conversion price of Cdn$12.40, Cdn$13.00 and Cdn$18.10, respectively, per common share. Holders of common shares currently receive a monthly dividend at a current annual rate of Cdn$1.094 per common share.
RECENT DEVELOPMENTS
On June 20, 2011, Atlantic Power, Capital Power Income L.P. ("CPILP"), CPI Income Services Ltd., the general partner of CPILP, and CPI Investments Inc., a unitholder of CPILP that is owned by EPCOR Utilities Inc. and Capital Power Corporation, entered into the Arrangement Agreement, which provides that Atlantic Power will acquire, directly or indirectly, all of the issued and outstanding CPILP units pursuant to the Plan of Arrangement under the Canada Business Corporations Act. Under the terms of the Plan of Arrangement, CPILP unitholders will be permitted to exchange each of their CPILP units for, at their election, Cdn$19.40 in cash or 1.3 Atlantic Power common shares. All cash elections will be subject to proration if total cash elections exceed approximately Cdn$506.5 million and all share elections will be subject to proration if total share elections exceed approximately 31.5 million Atlantic Power common shares.
Pursuant to the Plan of Arrangement, CPILP will sell its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power, for approximately Cdn$121.0 million which equates to approximately Cdn$2.15 per unit of CPILP. Additionally, in connection with the Plan of Arrangement, the management agreements between certain subsidiaries of Capital Power and CPILP and certain of its subsidiaries will be terminated (or assigned) in consideration of a payment of Cdn$10.0 million. Atlantic Power or its subsidiaries will assume the management of CPILP and enter into a transitional services agreement with Capital Power for a term of up to 6 to 9 months following the completion of the Plan of Arrangement, which will facilitate the integration of CPILP into Atlantic Power.
The Arrangement Agreement contains customary representations, warranties and covenants. Among these covenants, CPILP and CPI Income Services Ltd. have each agreed not to solicit alternative transactions, except that CPILP may respond to an alternative transaction proposal that constitutes, or would reasonably expect to lead to, a superior proposal, that we have a right to match. In addition, Atlantic Power or CPILP may be required to pay a Cdn$35.0 million fee if the Arrangement Agreement is terminated in certain unlikely circumstances.
The completion of the Plan of Arrangement is subject to the receipt of all necessary court and regulatory approvals in Canada and the United States and certain other closing conditions. Atlantic Power and CPILP currently expect to complete the Plan of Arrangement in the fourth quarter of 2011, subject to receipt of required shareholder/unitholder, court and regulatory approvals and other conditions to the Plan of Arrangement described in the Arrangement Agreement.
On May 6, 2011 we closed the sale of our 50.0% lessor interest in the Topsham project for $8.5 million, resulting in no gain or loss on the sale.
28
OUR POWER PROJECTS
The following table outlines our portfolio of power generating and transmission assets in operation and under construction as of August10, 2011, including our interest in each facility. Management believes the portfolio is well diversified in terms of electricity and steam buyers, fuel type, regulatory jurisdictions and regional power pools, thereby partially mitigating exposure to market, regulatory or environmental conditions specific to any single region.
|
||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Project Name |
Location (State) |
Type |
Total MW |
Economic Interest(1) |
Net MW(2) |
Electricity Purchaser |
Power Contract Expiry |
Customer S&P Credit Rating |
||||||||||||
|
||||||||||||||||||||
Auburndale | Florida | Natural Gas | 155 | 100.00 | % | 155 | Progress Energy Florida | 2013 | BBB+ | |||||||||||
|
||||||||||||||||||||
Lake | Florida | Natural Gas | 121 | 100.00 | % | 121 | Progress Energy Florida | 2013 | BBB+ | |||||||||||
|
||||||||||||||||||||
Pasco | Florida | Natural Gas | 121 | 100.00 | % | 121 | Tampa Electric Co. | 2018 | BBB+ | |||||||||||
|
||||||||||||||||||||
Chambers | New Jersey | Coal | 262 | 40.00 | % | 89 | ACE(3) | 2024 | BBB+ | |||||||||||
|
||||||||||||||||||||
16 | DuPont | 2024 | A | |||||||||||||||||
|
||||||||||||||||||||
Path 15 | California | Transmission | N/A | 100.00 | % | N/A | California Utilities via CAISO(4) | N/A | (5) | BBB+ to A(6) | ||||||||||
|
||||||||||||||||||||
Orlando | Florida | Natural Gas | 129 | 50.00 | % | 46 | Progress Energy Florida | 2023 | BBB+ | |||||||||||
|
||||||||||||||||||||
19 | Reedy Creek Improvement District | 2013 | (7) | A1(8) | ||||||||||||||||
|
||||||||||||||||||||
Selkirk | New York | Natural Gas | 345 | 17.70% | (9) | 15 | Merchant | N/A | N/R | |||||||||||
|
||||||||||||||||||||
49 | Consolidated Edison | 2014 | A- | |||||||||||||||||
|
||||||||||||||||||||
Gregory | Texas | Natural Gas | 400 | 17.10 | % | 59 | Fortis Energy Marketing and Trading | 2013 | AA | |||||||||||
|
||||||||||||||||||||
9 | Sherwin Alumina | 2020 | NR | |||||||||||||||||
|
||||||||||||||||||||
Badger Creek | California | Natural Gas | 46 | 50.00 | % | 23 | Pacific Gas & Electric | 2012 | (10) | BBB+ | ||||||||||
|
||||||||||||||||||||
Koma Kulshan | Washington | Hydro | 13 | 49.80 | % | 6 | Puget Sound Energy | 2037 | BBB | |||||||||||
|
||||||||||||||||||||
Delta-Person | New Mexico | Natural Gas | 132 | 40.00 | % | 53 | PNM | 2020 | BB- | |||||||||||
|
||||||||||||||||||||
Cadillac | Michigan | Biomass | 40 | 100.00 | % | 40 | Consumers Energy | 2028 | BBB- | |||||||||||
|
||||||||||||||||||||
Idaho Wind | Idaho | Wind | 183 | 27.56 | % | 50 | Idaho Power Co. | 2030 | BBB | |||||||||||
|
||||||||||||||||||||
Piedmont(11) | Georgia | Biomass | 54 | 98.00 | % | 53 | Georgia Power | 2032 | A | |||||||||||
|
- (1)
- Except as otherwise noted, economic interest represents the percentage ownership interest in the project held indirectly by Atlantic Power.
- (2)
- Represents our interest in each project's electric generation capacity based on our economic interest.
- (3)
- Includes a separate power sales agreement in which the project and Atlantic City Electric ("ACE") share profits on spot sales of energy and capacity not purchased by ACE under the base PPA.
- (4)
- California utilities pay transmission access charges to the California Independent System Operator, who then pays owners of Transmission system rights, such as Path 15, in accordance with its annual revenue requirement approved every three years by the Federal Energy Regulatory Commission ("FERC").
- (5)
- Path 15 is a FERC regulated asset with a FERC-approved regulatory life of 30 years: through 2034.
- (6)
- Largest payers of transmission access charges supporting Path 15's annual revenue requirement are Pacific Gas & Electric (BBB+), Southern California Edison (BBB+) and San Diego Gas & Electric (A). The California Independent System Operator imposes minimum credit quality requirements for any participants rated A or better unless collateral is posted per the California Independent System Operator imposed schedule.
- (7)
- Upon the expiry of the Reedy Creek PPA, the associated capacity and energy will be sold to PEF under the terms of the current agreement.
- (8)
- Fitch rating on Reedy Creek Improvement District bonds.
- (9)
- Represents our residual interest in the project after all priority distributions are paid to us and the other partners, which is estimated to occur in 2012.
- (10)
- Entered into a one-year interim agreement in April 2011.
- (11)
- Project currently under construction and is expected to be completed in late 2012.
29
Results of Operations
The following table and discussion is a summary of our consolidated results of operations for the three and six month periods ended June 30, 2011 and 2010. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
|
Three months ended June 30, |
Six months ended June 30, |
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---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(Unaudited) (in thousands of U.S. dollars, except as otherwise stated) |
2011 | 2010 | 2011 | 2010 | ||||||||||
Project revenue |
||||||||||||||
Auburndale |
$ | 20,434 | $ | 19,570 | $ | 42,216 | $ | 40,037 | ||||||
Lake |
16,844 | 17,842 | 33,968 | 34,083 | ||||||||||
Pasco |
3,382 | 2,763 | 5,902 | 5,632 | ||||||||||
Path 15 |
7,491 | 7,729 | 15,135 | 15,373 | ||||||||||
Other Project Assets |
5,107 | | 9,702 | | ||||||||||
|
53,258 | 47,904 | 106,923 | 95,125 | ||||||||||
Project expenses |
||||||||||||||
Auburndale |
13,787 | 14,089 | 30,215 | 30,133 | ||||||||||
Lake |
10,710 | 12,810 | 21,634 | 24,007 | ||||||||||
Pasco |
2,670 | 2,507 | 7,024 | 4,707 | ||||||||||
Path 15 |
2,310 | 2,762 | 5,357 | 5,452 | ||||||||||
Chambers |
| | 1 | | ||||||||||
Other Project Assets |
3,564 | 116 | 7,829 | 173 | ||||||||||
|
33,041 | 32,284 | 72,060 | 64,472 | ||||||||||
Project other income (expense) |
||||||||||||||
Auburndale |
(1,427 | ) | (1,012 | ) | (779 | ) | (5,695 | ) | ||||||
Lake |
299 | 1,713 | 1,867 | (6,220 | ) | |||||||||
Pasco |
| | | | ||||||||||
Path 15 |
(2,943 | ) | (3,096 | ) | (5,935 | ) | (6,242 | ) | ||||||
Chambers |
1,649 | 1,654 | 4,704 | 5,103 | ||||||||||
Other Project Assets |
(4,764 | ) | 662 | (6,820 | ) | 1,806 | ||||||||
|
(7,186 | ) | (79 | ) | (6,963 | ) | (11,248 | ) | ||||||
Total project income |
||||||||||||||
Auburndale |
5,220 | 4,469 | 11,222 | 4,209 | ||||||||||
Lake |
6,433 | 6,745 | 14,201 | 3,856 | ||||||||||
Pasco |
712 | 256 | (1,122 | ) | 925 | |||||||||
Path 15 |
2,238 | 1,871 | 3,843 | 3,679 | ||||||||||
Chambers |
1,649 | 1,654 | 4,703 | 5,103 | ||||||||||
Other Project Assets |
(3,221 | ) | 546 | (4,947 | ) | 1,633 | ||||||||
|
13,031 | 15,541 | 27,900 | 19,405 | ||||||||||
Administrative and other expenses |
||||||||||||||
Administration |
4,671 | 3,843 | 8,725 | 7,943 | ||||||||||
Interest, net |
3,510 | 2,518 | 7,478 | 5,312 | ||||||||||
Foreign exchange loss (gain) |
(535 | ) | 4,224 | (1,193 | ) | 2,432 | ||||||||
Other income, net |
| (26 | ) | | (26 | ) | ||||||||
Total administrative and other expenses |
7,646 | 10,559 | 15,010 | 15,661 | ||||||||||
Income from operations before income taxes |
5,385 | 4,982 | 12,890 | 3,744 | ||||||||||
Income tax expense (benefit) |
(7,684 | ) | 3,618 | (6,161 | ) | 8,491 | ||||||||
Net income (loss) |
13,069 | 1,364 | 19,051 | (4,747 | ) | |||||||||
Net loss attributable to noncontrolling interest |
(117 | ) | (81 | ) | (271 | ) | (129 | ) | ||||||
Net income (loss) attributable to Atlantic Power Corporation shareholders |
$ | 13,186 | $ | 1,445 | $ | 19,322 | $ | (4,618 | ) | |||||
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Consolidated Overview
We have six reportable segments: Auburndale, Chambers, Lake, Pasco, Path 15 and Other Project Assets. The results of operations are discussed below by reportable segment.
Project income is the primary GAAP measure of our operating results and is discussed in "Project Operations Performance" below. In addition, an analysis of non-project expenses impacting our results is set out in "Administrative and Other Expenses (Income)" below.
Significant non-cash items, which are subject to potentially significant fluctuations, include: (1) the change in fair value of certain derivative financial instruments that are required by GAAP to be revalued at each balance sheet date (see "Quantitative and Qualitative Disclosures About Market Risk" for additional information); (2) the non-cash impact of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of our Canadian dollar denominated obligations and; (3) the related deferred income tax expense (benefit) associated with these non-cash items.
Cash available for distribution was $18.0 million and $7.5 million for the three-months ended June 30, 2011 and 2010, respectively and $34.6 million and $25.3 million for the six-months ended June 30, 2011 and 2010, respectively. See "Cash Available for Distribution" in this Form 10-Q for additional information.
Income from operations before income taxes for the three-months ended June 30, 2011 and 2010 was $5.4 million and $5.0 million, respectively and $12.9 million and $3.7 million for the six-months ended June 30, 2011 and 2010, respectively. See "Project Income" below for additional information.
Three months ended June 30, 2011 compared with three months ended June 30, 2010
Project Income
Auburndale Segment
The increase in project income for our Auburndale segment of $0.7 million to $5.2 million in the three-month period ended June 30, 2011 from income of $4.5 million in the comparable 2010 period is primarily attributable to the annual contractual escalation of capacity payments under the project's PPA, as well as favorable gas transportation cost compared to 2010.
Lake Segment
Project income for our Lake segment decreased $0.3 million to $6.4 million in the three-month period ended June 30, 2011, from income of $6.7 million in the comparable 2010 period. The decrease is primarily attributable to a $1.4 million change in the benefit associated with the non-cash change in fair value of derivative instruments associated with its natural gas swaps. These swaps were executed to financially hedge the project's exposure to changes in the market prices of natural gas. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk", for additional details about our derivative instruments and other financial instruments. This was partially offset by lower fuel expenses attributable to lower prices on natural gas swaps.
Pasco Segment
Project income for our Pasco segment increased $0.4 million to $0.7 million in the three-month period ended June 30, 2011, from project income of $0.3 million in the comparable 2010 period. The increase is due to higher dispatch compared to 2010 of the project.
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Path 15 Segment
Project income for our Path 15 segment increased $0.3 million to $2.2 million in the three-month period ended June 30, 2011 from $1.9 million in the comparable 2010 period due to decreased operation and maintenance costs.
Chambers Segment
The change in project income for our Chambers segment, which is recorded under the equity method of accounting, was not significant in the three-month period ended June 30, 2011 compared to same period in 2010.
Other Project Assets Segment
Project income for our Other Project Assets segment decreased $3.7 million to a project loss of $(3.2) million for the three-month period ended June 30, 2011 compared to project income of $0.5 million in 2010. The most significant components to the change are as follows:
-
- increased expense at Piedmont in 2011 associated with the non-cash change in fair value of interest rate swaps
recorded at fair value;
-
- increased expense at Orlando due to higher operation and maintenance costs attributable to a planned gas turbine overhaul;
-
- reduced revenue at Badger Creek due to lower capacity payments under the new one year interim power purchase agreement;
-
- the absence of income from Topsham. The project was sold in May 2011;
-
- project loss at Idaho Wind of $0.7 million which became operational in Q1 2011; offset by
-
- project income of $1.1 million at Cadillac, which was acquired in December 2010.
Administrative and Other Expenses (Income)
Administration includes the non-project related costs of operating the company. Administration increased $0.9 million to $4.7 million in the three-month period ended June 30, 2011 from $3.8 million in the comparable 2010 period primarily due to higher business development costs associated with the CPILP transaction and increases in compensation costs attributable to an increase in corporate office staff levels.
Interest expense at the corporate level primarily relates to our convertible debentures. Interest expense, net increased $1.0 million to $3.5 million in the three-month period ended June 30, 2011 from $2.5 million in the comparable 2010 period. This increase is due to the issuance of Cdn$80.5 million of convertible debentures in October of 2010.
Foreign exchange loss (gain) primarily reflects the unrealized impact of changes in foreign exchange rates on the U.S. dollar equivalent of our Canadian dollar denominated obligations to holders of the convertible debentures. In addition, unrealized and realized gains and losses on our forward contracts for the purchase of Canadian dollars to satisfy these obligations and our dividends to shareholders are included in foreign exchange loss (gain). Unrealized gains and losses on our forward contracts are reclassified to realized gains and losses upon cash settlement of the contracts. Foreign exchange loss decreased $4.7 million to a $0.5 million gain in the three-month period ended June 30, 2011 compared to a $(4.2) million loss in the comparable 2010 period. The U.S. dollar to Canadian dollar exchange rate increased by 0.5% during the three-month period ended June 30, 2011, compared to a decrease of 4.6% in the comparable period in 2010. See Item 3 "Quantitative and Qualitative Disclosures About Market Risk" for additional details about our management of foreign currency risk
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and the components of the foreign exchange gain recognized during the three-month period ended June 30, 2011 compared to the foreign exchange loss in the comparable 2010 period.
Six months ended June 30, 2011 compared with six months ended June 30, 2010
Project Income
Auburndale Segment
The increase in project income for our Auburndale segment of $7.0 million to $11.2 million in the six-month period ended June 30, 2011 from income of $4.2 million in the comparable 2010 period is primarily attributable to the $4.6 million change in the benefit associated with the non-cash change in fair value of derivative instruments associated with its natural gas swaps. These swaps were executed to financially hedge the project's exposure to changes in the market prices of natural gas. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk", for additional details about our derivative instruments and other financial instruments. Project revenue at Auburndale increased by $2.1 million in the six-month period ended June 30, 2011 due to favorable energy pricing compared to 2010, as well as the annual contractual escalation of capacity payments. Interest expense on project-level debt decreased by $0.3 million in the six-month period ended June 30, 2011 as compared to the comparable period in 2010.
Lake Segment
Project income for our Lake segment increased $10.3 million to $14.2 million in the six-month period ended June 30, 2011, from income of $3.9 million in the comparable 2010 period. The increase is primarily attributable to the $8.1 million change in the benefit associated with the non-cash change in fair value of derivative instruments associated with its natural gas swaps. These swaps were executed to financially hedge the project's exposure to changes in the market prices of natural gas. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk", for additional details about our derivative instruments and other financial instruments. In addition, fuel costs at Lake decreased due to the lower price on natural gas swaps.
Pasco Segment
Project income for our Pasco segment decreased $2.0 million to a project loss of $(1.1) million in the six-month period ended June 30, 2011, from project income of $0.9 million in the comparable 2010 period. The decrease is due to higher operations and maintenance expenses attributable to the unplanned replacement of gas turbine components during 2011.
Path 15 Segment
Project income for our Path 15 segment was consistent for the six-month period ended June 30, 2011and 2010.
Chambers Segment
Project income for our Chambers segment, which is recorded under the equity method of accounting, decreased $0.4 million to $4.7 million in the six-month period ended June 30, 2011 from $5.1 million in the comparable 2010 period. The decrease in project income at Chambers is primarily attributable to lower dispatch compared to 2010.
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Other Project Assets Segment
Project income for our Other Project Assets segment decreased $6.5 million to a project loss of $(4.9) million for the six-month period ended June 30, 2011 compared to project income of $1.6 million in 2010. The most significant components to the change are as follows:
-
- increased expense at Piedmont in 2011 associated with a non-cash change in the fair value of an interest rate
swap that is recorded at fair value;
-
- decreased income at Selkirk due to a planned outage lasting longer than expected that delayed recognition of capacity
payments until the third quarter of 2011;
-
- increased expense at Orlando due to higher operation and maintenance costs attributable to a planned gas turbine overhaul;
-
- reduced revenue at Badger Creek due to lower capacity payments under the new one year interim power purchase agreement;
-
- the absence of income from Topsham. The project was sold in May 2011;
-
- project loss at Idaho Wind of $0.6 million which became operational in Q1 2011; offset by
-
- project income at Cadillac of $1.3 million, which was acquired in December 2010.
Administrative and Other Expenses (Income)
Administration includes the non-project related costs of operating the company. Administration increased $0.8 million to $8.7 million for the six-month period ended June 30, 2011 from $7.9 million in the comparable 2010 period primarily due to higher business development costs associated with the CPILP transaction and increased compensation costs attributable to an increase in corporate office staff levels.
Interest expense at the corporate level primarily relates to our convertible debentures. Interest expense, net increased $2.2 million to $7.5 million in the six-month period ended June 30, 2011 from $5.3 million in the comparable 2010 period. This increase is due to the issuance of Cdn$80.5 million of convertible debentures in October of 2010.
Foreign exchange loss (gain) primarily reflects the unrealized impact of changes in foreign exchange rates on the U.S. dollar equivalent of our Canadian dollar-denominated obligations to holders of the convertible debentures. In addition, unrealized and realized gains and losses on our forward contracts for the purchase of Canadian dollars to satisfy these obligations and our dividends to shareholders are included in foreign exchange loss (gain). Unrealized gains and losses on our forward contracts are reclassified to realized gains and losses upon cash settlement of the contracts. Foreign exchange loss decreased $3.6 million to a $1.2 million gain in the six-month period ended 2011 compared to a $(2.4) million loss in the comparable 2010 period. The U.S. dollar to Canadian dollar exchange rate increased by 3.1% during the six-month period ended June 30, 2011, compared to a decrease of 1.3% in the comparable period in 2010. See Item 3 "Quantitative and Qualitative Disclosures About Market Risk" for additional details about our management of foreign currency risk and the components of the foreign exchange gain recognized during the six-month period ended June 30, 2011 compared to the foreign exchange loss in the comparable 2010 period.
Supplementary Non-GAAP Financial Information
The key measure we use to evaluate the results of our projects is Cash Available for Distribution. Cash Available for Distribution is not a measure recognized under GAAP, does not have a standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers. We believe Cash Available for Distribution is a relevant supplemental measure of our
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ability to pay dividends to our shareholders. A reconciliation of net cash provided by operating activities to Cash Available for Distribution is set out below under "Cash Available for Distribution." Investors are cautioned that we may calculate this measure in a manner that is different from other companies.
The primary factor influencing Cash Available for Distribution is cash distributions received from the projects. These distributions received are generally funded from Project Adjusted EBITDA generated by the projects, reduced by project-level debt service and capital expenditures, and adjusted for changes in project-level working capital and cash reserves. Project Adjusted EBITDA is defined as project income plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use unaudited Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. A reconciliation of project income to Project Adjusted EBITDA is set out below under "Project Adjusted EBITDA." Investors are cautioned that we may calculate this measure in a manner that is different from other companies.
Because Project Adjusted EBITDA and project distributions are key drivers of both the performance of our projects and Cash Available for Distribution, please see the following supplementary unaudited non-GAAP information that summarizes Project Adjusted EBITDA by project and a reconciliation of Project Adjusted EBITDA by project to project distributions actually received by us.
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Project Adjusted EBITDA (in thousands of U.S. dollars):
|
Three months ended June 30, |
Six months ended June 30, |
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---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(unaudited) |
2011 | 2010 | 2011 | 2010 | ||||||||||
Project Adjusted EBITDA by individual segment |
||||||||||||||
Auburndale |
$ | 11,606 | $ | 10,431 | $ | 21,919 | $ | 19,802 | ||||||
Lake |
8,424 | 7,299 | 16,914 | 14,612 | ||||||||||
Pasco |
1,469 | 1,002 | 392 | 2,417 | ||||||||||
Path 15 |
7,186 | 7,062 | 13,756 | 14,115 | ||||||||||
Chambers |
4,307 | 4,141 | 9,031 | 10,129 | ||||||||||
Total |
32,992 | 29,935 | 62,012 | 61,075 | ||||||||||
Other Project Assets |
||||||||||||||
Selkirk |
3,206 | 3,526 | 4,314 | 7,056 | ||||||||||
Orlando |
1,202 | 1,870 | 3,093 | 3,671 | ||||||||||
Cadillac |
2,644 | | 4,391 | | ||||||||||
Gregory |
956 | 1,428 | 1,728 | 2,283 | ||||||||||
Idaho Wind |
1,246 | | 2,051 | | ||||||||||
Badger Creek |
41 | 774 | 801 | 1,510 | ||||||||||
Delta Person |
443 | 540 | 842 | 904 | ||||||||||
Koma Kulshan |
374 | 434 | 434 | 553 | ||||||||||
Rollcast |
(306 | ) | | (773 | ) | | ||||||||
Piedmont |
(32 | ) | | (61 | ) | | ||||||||
Topsham |
| 548 | | 963 | ||||||||||
Rumford |
| 1 | | (7 | ) | |||||||||
Other |
88 | (530 | ) | 15 | (733 | ) | ||||||||
Total adjusted EBITDA from Other Project Assets segment |
9,862 | 8,591 | 16,835 | 16,200 | ||||||||||
Total adjusted EBITDA from all Projects |
42,854 | 38,526 | 78,847 | 77,275 | ||||||||||
Depreciation and amortization |
17,661 | 16,596 | 35,098 | 32,982 | ||||||||||
Interest expense, net |
7,088 | 6,097 | 13,328 | 11,878 | ||||||||||
Change in the fair value of derivative instruments |
4,826 | 210 | 2,042 | 12,729 | ||||||||||
Other (income) expense |
248 | 82 | 479 | 281 | ||||||||||
Project income as reported in the statement of operations |
$ | 13,031 | $ | 15,541 | $ | 27,900 | $ | 19,405 | ||||||
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