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EX-32.1 - EX-32.1 - ATLANTIC POWER CORP | a2200752zex-32_1.htm |
EX-31.2 - EX-31.2 - ATLANTIC POWER CORP | a2200752zex-31_2.htm |
EX-31.1 - EX-31.1 - ATLANTIC POWER CORP | a2200752zex-31_1.htm |
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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 |
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For the quarterly period ended September 30, 2010 |
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OR |
||
o |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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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 o 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 November 10, 2010 was 66,634,461.
ATLANTIC POWER CORPORATION
FORM 10-Q
THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2010
Index
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)
|
September 30, 2010 |
December 31, 2009 |
||||||
---|---|---|---|---|---|---|---|---|
|
(unaudited) |
|
||||||
Assets |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 8,998 | $ | 49,850 | ||||
Restricted cash |
22,257 | 14,859 | ||||||
Accounts receivable |
20,553 | 17,480 | ||||||
Note receivablerelated party (Note 14) |
12,801 | | ||||||
Current portion of derivative instruments asset (Notes 8 and 9) |
5,988 | 5,619 | ||||||
Prepayments, supplies, and other |
5,717 | 3,019 | ||||||
Deferred income taxes |
11,531 | 17,887 | ||||||
Refundable income taxes |
7,463 | 10,552 | ||||||
Total current assets |
95,308 | 119,266 | ||||||
Property, plant, and equipment, net (Note 6) |
187,648 |
193,822 |
||||||
Transmission system rights (Note 6) |
190,097 | 195,984 | ||||||
Equity investments in unconsolidated affiliates (Note 5) |
301,388 | 259,230 | ||||||
Other intangible assets, net (Note 6) |
60,395 | 71,770 | ||||||
Goodwill (Note 4) |
12,453 | 8,918 | ||||||
Derivative instruments asset (Notes 8 and 9) |
11,931 | 14,289 | ||||||
Other assets |
5,273 | 6,297 | ||||||
Total assets |
$ | 864,493 | $ | 869,576 | ||||
Liabilities and Shareholders' Equity |
||||||||
Current liabilities: |
||||||||
Accounts payable and accrued liabilities |
$ | 26,195 | $ | 21,661 | ||||
Revolving credit facility (Note 17) |
20,000 | | ||||||
Current portion of long-term debt (Note 7) |
18,456 | 18,280 | ||||||
Current portion of derivative instruments liability (Notes 8 and 9) |
4,916 | 6,512 | ||||||
Interest payable on convertible debentures |
1,797 | 800 | ||||||
Dividends payable |
5,363 | 5,242 | ||||||
Other current liabilities |
8 | 752 | ||||||
Total current liabilities |
76,735 | 53,247 | ||||||
Long-term debt (Note 7) |
211,521 |
224,081 |
||||||
Convertible debentures |
142,100 | 139,153 | ||||||
Derivative instruments liability (Notes 8 and 9) |
26,459 | 5,513 | ||||||
Deferred income taxes |
33,459 | 28,619 | ||||||
Other non-current liabilities |
4,916 | 4,846 | ||||||
Commitments and contingencies (Note 16) |
||||||||
Shareholders' equity |
||||||||
Common shares |
545,447 | 541,917 | ||||||
Accumulated other comprehensive income (loss) (Note 9) |
98 | (859 | ) | |||||
Retained deficit |
(179,623 | ) | (126,941 | ) | ||||
Noncontrolling interest (Note 4) |
3,381 | | ||||||
Total shareholders' equity |
369,303 | 414,117 | ||||||
Total liabilities and shareholders' equity |
$ | 864,493 | $ | 869,576 | ||||
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 September 30, |
Nine months ended September 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | 2010 | 2009 | ||||||||||
Project revenue: |
||||||||||||||
Energy sales |
$ | 22,713 | $ | 14,795 | $ | 55,285 | $ | 44,810 | ||||||
Energy capacity revenue |
23,196 | 22,113 | 69,585 | 66,337 | ||||||||||
Transmission services |
7,813 | 7,792 | 23,186 | 23,208 | ||||||||||
Other |
317 | 157 | 1,108 | 806 | ||||||||||
|
54,039 | 44,857 | 149,164 | 135,161 | ||||||||||
Project expenses: |
||||||||||||||
Fuel |
19,678 | 15,667 | 51,606 | 43,255 | ||||||||||
Operations and maintenance |
5,674 | 6,105 | 16,174 | 15,755 | ||||||||||
Project operator fees and expenses |
1,172 | 768 | 3,074 | 2,799 | ||||||||||
Depreciation and amortization |
10,082 | 10,053 | 30,224 | 31,307 | ||||||||||
|
36,606 | 32,593 | 101,078 | 93,116 | ||||||||||
Project other income (expense): |
||||||||||||||
Change in fair value of derivative instruments (Notes 8 and 9) |
(9,744 | ) | 351 | (20,946 | ) | 711 | ||||||||
Equity in earnings of unconsolidated affiliates |
4,088 | (3,646 | ) | 12,550 | 323 | |||||||||
Interest expense, net |
(4,165 | ) | (4,525 | ) | (12,884 | ) | (13,845 | ) | ||||||
Other income, net |
22 | | 233 | 1,205 | ||||||||||
|
(9,799 | ) | (7,820 | ) | (21,047 | ) | (11,606 | ) | ||||||
Project income |
7,634 | 4,444 | 27,039 | 30,439 | ||||||||||
Administrative and other expenses (income): |
||||||||||||||
Management fees and administration |
4,103 | 2,907 | 12,046 | 8,391 | ||||||||||
Interest, net |
2,707 | 11,285 | 8,019 | 31,455 | ||||||||||
Foreign exchange (gain) loss (Note 9) |
(2,253 | ) | 12,528 | 179 | 22,034 | |||||||||
Other income, net |
| (18 | ) | (26 | ) | (48 | ) | |||||||
|
4,557 | 26,702 | 20,218 | 61,832 | ||||||||||
Income (loss) from operations before income taxes |
3,077 | (22,258 | ) | 6,821 | (31,393 | ) | ||||||||
Income tax expense (benefit) (Note 10) |
3,614 | (6,455 | ) | 12,105 | (9,104 | ) | ||||||||
Net loss |
(537 | ) | (15,803 | ) | (5,284 | ) | (22,289 | ) | ||||||
Net loss attributable to noncontrolling interest |
(99 | ) | | (228 | ) | | ||||||||
Net loss attributable to Atlantic Power Corporation |
$ | (438 | ) | $ | (15,803 | ) | $ | (5,056 | ) | $ | (22,289 | ) | ||
Net loss per share attributable to Atlantic Power Corporation shareholders: (Note 12) |
||||||||||||||
Basic |
$ | (0.01 | ) | $ | (0.26 | ) | $ | (0.08 | ) | $ | (0.37 | ) | ||
Diluted |
$ | (0.01 | ) | $ | (0.26 | ) | $ | (0.08 | ) | $ | (0.37 | ) |
See accompanying notes to consolidated financial statements.
4
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands of U.S. dollars)
(Unaudited)
|
Nine months ended September 30, |
|||||||
---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | ||||||
Cash flows from operating activities: |
||||||||
Net loss |
$ | (5,284 | ) | $ | (22,289 | ) | ||
Adjustments to reconcile to net cash provided by operating activities: |
||||||||
Depreciation and amortization |
30,224 | 31,307 | ||||||
Long-term incentive plan expense |
3,287 | 1,392 | ||||||
Loss on sale of property, plant and equipment |
| 933 | ||||||
Gain on step-up valuation of Rollcast acquisition |
(211 | ) | | |||||
Earnings from unconsolidated affiliates |
(12,550 | ) | (323 | ) | ||||
Distributions from unconsolidated affiliates |
9,897 | 19,023 | ||||||
Unrealized foreign exchange loss |
4,369 | 23,866 | ||||||
Change in fair value of derivative instruments |
20,946 | (711 | ) | |||||
Change in deferred income taxes |
10,555 | (5,833 | ) | |||||
Change in other operating balances |
||||||||
Accounts receivable |
(3,072 | ) | 7,994 | |||||
Prepayments, refundable income taxes and other assets |
1,189 | (6,633 | ) | |||||
Accounts payable and accrued liabilities |
3,747 | (5,504 | ) | |||||
Other liabilities |
576 | 1,673 | ||||||
Net cash provided by operating activities |
63,673 | 44,895 | ||||||
Cash flows used in investing activities: |
||||||||
Acquisitions and investments, net of cash acquired |
(41,182 | ) | (3,000 | ) | ||||
Loan to Idaho Wind |
(12,801 | ) | | |||||
Change in restricted cash (Note 1) |
(7,398 | ) | (7,816 | ) | ||||
Biomass development costs |
(1,827 | ) | | |||||
Proceeds from sale of property, plant and equipment |
| 167 | ||||||
Purchase of property, plant and equipment |
(2,077 | ) | (1,641 | ) | ||||
Net cash used in investing activities |
(65,285 | ) | (12,290 | ) | ||||
Cash flows used in financing activities: |
||||||||
Shares acquired in normal course issuer bid (Note 15) |
| (3,369 | ) | |||||
Proceeds from revolving credit facility borrowings |
20,000 | |||||||
Repayments of revolving credit facility borrowings |
| (20,000 | ) | |||||
Repayment of project-level debt |
(11,841 | ) | (7,684 | ) | ||||
Equity contribution from noncontrolling interest |
200 | | ||||||
Dividends paid |
(47,599 | ) | (18,110 | ) | ||||
Net cash used in financing activities |
(39,240 | ) | (49,163 | ) | ||||
Net decrease in cash and cash equivalents |
(40,852 | ) | (16,558 | ) | ||||
Cash and cash equivalents at beginning of period |
49,850 | 37,327 | ||||||
Cash and cash equivalents at end of period |
$ | 8,998 | $ | 20,769 | ||||
Supplemental cash flow information |
||||||||
Interest paid |
$ | 16,587 | $ | 40,098 | ||||
Income taxes paid (refunded), net |
$ | (1,607 | ) | $ | 651 |
See accompanying notes to consolidated financial statements.
5
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of presentation
Overview
Atlantic Power Corporation ("Atlantic Power") is a corporation established under the laws of the Province of Ontario, Canada on June 18, 2004 and continued to the Province of British Columbia, Canada on July 8, 2005. We issued income participating securities ("IPSs") for cash pursuant to an initial public offering on the Toronto Stock Exchange, or the TSX, on November 18, 2004. Each IPS was comprised of one common share and Cdn$5.767 principal value of 11% subordinated notes due 2016. On November 27, 2009 our shareholders approved a conversion from the IPS structure to a traditional common share structure. Each IPS has been exchanged for one new common share and each old common share that did not form a part of an IPS was exchanged for approximately 0.44 of a new common share. Our shares trade on the TSX under the symbol "ATP" and began trading on the New York Stock Exchange, or the NYSE, under the symbol "AT" on July 23, 2010.
We are an independent power producer with interests in 11 operational power generation projects across eight states, one wind project under construction in Idaho, one biomass project under construction in Georgia, a 500 kilovolt 84-mile electric transmission line located in California and a number of development projects. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,738 megawatts (or "MW"), in which our ownership interest is approximately 788 MW. Four of our projects are wholly-owned subsidiaries: Lake Cogen, Ltd., Pasco Cogen, Ltd., Auburndale Power Partners, L.P. and Atlantic Path 15, LLC. The interim consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles ("GAAP") with a reconciliation to Canadian GAAP in Note 18. The Canadian securities legislation allow issuers that are required to file reports with the Securities and Exchange Commission ("SEC") in the United States to file financial statements under United States GAAP to meet their continuous disclosure obligations in Canada. Prior to 2010, we prepared our consolidated financial statements in accordance with Canadian GAAP.
The interim consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. The accounting policies we follow are set forth below in Note 2, Summary of significant accounting policies. The interim consolidated financial statements follow the same accounting principles and methods of application as the most recent annual consolidated financial statements as there are no material differences in our accounting policies between United States and Canadian GAAP at September 30, 2010 other than as denoted in Note 18. Interim results are not necessarily indicative of results for a 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 September 30, 2010, the results of operations for the three and nine month periods ended September 30, 2010 and 2009, and our cash flows for the nine month periods ended September 30, 2010 and 2009.
Beginning in the first quarter of 2010, changes in restricted cash in the consolidated statement of cash flows have been reported as an investing activity. In previous periods, changes in restricted cash were reported as cash flows from operating activities. The prior period amounts have been reclassified to conform with the current year presentation. This reclassification does not impact the consolidated balance sheet or the consolidated statements of operations. We have changed the classification of restricted cash because the revised presentation is more widely used by companies in our industry.
6
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Summary of significant accounting policies
(a) Basis of consolidation and accounting:
The accompanying interim consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America and include the consolidated accounts and operations of our subsidiaries in which we have a controlling financial interest. The usual condition for a controlling financial interest is ownership of the majority of the voting interest of an entity. However, a controlling financial interest may also exist in entities, such as a variable interest entity, through arrangements that do not involve controlling voting interests.
We apply the standard that requires consolidation of variable interest entities ("VIEs"), for which we are the primary beneficiary. The guidance requires a variable interest holder to consolidate a VIE if that party has both the power to direct the activities that most significantly impact the entities' economic performance, as well as either the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. We have determined that our investments are not VIEs by evaluating their design and capital structure. Accordingly, we use the equity method of accounting for all of our investments in which we do not have an economic controlling interest. We eliminate all intercompany accounts and transactions in consolidation.
(b) 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 year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment and power purchase agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions 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. These estimates and valuation 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 valuation assumptions and estimates change, the recorded amounts could change by a material amount.
(c) Revenue:
We recognize energy sales revenue on a gross basis when electricity and steam are delivered under the terms of the related contracts. Revenue associated with capacity payments under the power purchase agreements ("PPAs") are recognized as the lesser of (1) the amount billable under the PPA or (2) an amount determined by the kilowatt hours made available during the period multiplied by the estimated average revenue per kilowatt hour over the term of the PPA.
Transmission services revenue is recognized as transmission services are provided. The annual revenue requirement for transmission services is regulated by the Federal Energy Regulatory Commission ("FERC") and is established through a rate-making process that occurs every three years. When actual cash receipts from transmission services revenue are different than the regulated revenue requirement because of timing differences, the over or under collections are deferred until the timing differences reverse in future periods.
7
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Summary of significant accounting policies (Continued)
(d) Use of fair value:
We utilize a fair value hierarchy that gives the highest priority to quoted prices in active markets and is applicable to fair value measurements of derivative contracts and other instruments that are subject to mark-to-market accounting. Refer to Note 8 for more information.
(e) Derivative financial instruments:
We use derivative financial instruments in the form of interest rate swaps and foreign exchange forward contracts to manage our current and anticipated exposure to fluctuations in interest rates and foreign currency exchange rates. We have also entered into natural gas supply contracts and natural gas forwards or swaps to minimize the effects of the price volatility of natural gas, which is a major production cost. We do not enter into derivative financial instruments for trading or speculative purposes; however, not all derivatives qualify for hedge accounting.
Derivative financial instruments not designated as a hedge are measured at fair value with changes in fair value recorded in the consolidated statements of operations.
The following table summarizes derivative financial instruments that are not designated as hedges for accounting purposes and the accounting treatment in the consolidated statements of operations of the changes in fair value and cash settlements of such derivative financial instrument:
Derivative financial instrument
|
Classification of changes in fair value | Classification of cash settlements | ||
---|---|---|---|---|
Foreign currency forward contracts | Foreign exchange loss (gain) | Foreign exchange loss (gain) | ||
Lake natural gas swaps | Change in fair value of derivative instruments |
Fuel expense | ||
Auburndale natural gas swaps | Change in fair value of derivative instruments |
Fuel expense | ||
Interest rate swap | Change in fair value of derivative instruments |
Interest expense |
Certain derivative instruments qualify for a scope exception to fair value accounting because they are considered normal purchases or normal sales. This exception applies when we have the ability to and it is probable that we will deliver or take delivery of the underlying physical commodity. Derivatives that are considered to be normal purchases and normal sales are exempt from derivative accounting treatment and are recorded as executory contracts.
We have designated one of our interest rate swaps as a hedge of cash flows for accounting purposes. Tests are performed to evaluate hedge effectiveness and ineffectiveness at inception and on an ongoing basis, both retroactively and prospectively. Unrealized gains or losses on the interest rate swap designated as a hedge are deferred and recorded as a component of accumulated other comprehensive income (loss) until the hedged transactions occur and are recognized in earnings. The ineffective portion of the cash flow hedge, if any, is immediately recognized in earnings.
(f) Property, plant and equipment:
Property, plant and equipment are stated at cost, net of accumulated depreciation. Depreciation is provided on a straight-line basis over the estimated useful life of the related asset. As major
8
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Summary of significant accounting policies (Continued)
maintenance occurs and parts are replaced on the plant's combustion and steam turbines, maintenance costs are either expensed or transferred to property, plant and equipment if the maintenance extends the useful lives of the major parts. These costs are depreciated over the parts' estimated useful lives, which is generally three to six years, depending on the nature of maintenance activity performed.
(g) Transmission system rights:
Transmission system rights are an intangible asset that represents the long-term right to approximately 72% of the capacity of the Path 15 transmission line in California. Transmission system rights are amortized on a straight-line basis over 30 years, the regulatory life of Path 15.
(h) Impairment of long-lived assets, non-amortizing intangible assets and equity method investments:
Long-lived assets, such as property, plant and equipment, transmission system rights and other intangible assets subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds its fair value.
Investments in and the operating results of 50%-or-less owned entities not required to be consolidated are included in the consolidated financial statements on the basis of the equity method of accounting. We review our investments in such unconsolidated entities for impairment whenever events or changes in business circumstances indicate that the carrying amount of the investments may not be fully recoverable. Evidence of a loss in value that is other than temporary might include the absence of an ability to recover the carrying amount of the investment, the inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment, failure of cash flow coverage ratio tests included in project-level non-recourse debt or, where applicable, estimated sales proceeds which are insufficient to recover the carrying amount of the investment. Our assessment as to whether any decline in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of the investment is recoverable within a reasonable period of time outweighs evidence to the contrary. We generally consider our investments in our equity method investees to be strategic long-term investments. Therefore, we complete our assessments with a long-term view. If the fair value of the investment is determined to be less than the carrying value and the decline in value is considered to be other than temporary, the asset is written down to its fair value.
(i) Other intangible assets:
Other intangible assets include PPAs and fuel supply agreements at our projects.
Power purchase agreements are valued at the time of acquisition based on the contract prices under the PPAs compared to projected market prices. Fuel supply agreements are valued at the time of acquisition based on the contract prices under the fuel supply agreement compared to projected market prices. The balances are presented net of accumulated amortization in the consolidated balance sheets. Amortization is recorded on a straight-line basis over the remaining term of the agreement.
9
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Summary of significant accounting policies (Continued)
(j) Income taxes:
Income tax expense includes the current tax obligation or benefit and change in deferred income tax asset or liability for the period. We use the asset and liability method of accounting for deferred income taxes and record deferred income taxes for all significant temporary differences. Income tax benefits associated with uncertain tax positions are recognized when we determine that it is more-likely-than-not that the tax position will be ultimately sustained. Refer to Note 10 for more information.
(k) Foreign currency translation:
Our functional currency and reporting currency is the United States dollar. The functional currency of our subsidiaries and other investments is the United States dollar. Monetary assets and liabilities denominated in Canadian dollars are translated into United States dollars using the rate of exchange in effect at the end of the period. All transactions denominated in Canadian dollars are translated into United States dollars at average exchange rates.
(l) Long-term incentive plan:
The officers and other employees of Atlantic Power are eligible to participate in the Long-Term Incentive Plan ("LTIP") that was implemented in 2007. In the second quarter of 2010, the board of directors approved an amendment to the LTIP and the amended plan was approved by our shareholders on June 29, 2010. The amended LTIP will be effective for grants beginning with the 2010 performance year. Under the amended LTIP, the notional units granted to plan participants will have the same characteristics as notional units under the old LTIP. However, the number of notional units that vest will be based, in part, on the total shareholder return of Atlantic Power compared to a group of peer companies in Canada. In addition, vesting of the notional units for officers of Atlantic Power will occur on a three-year cliff basis as opposed to ratable vesting over three years for grants made prior to the amendments.
Unvested notional units are entitled to receive dividends equal to the dividends per common share during the vesting period in the form of additional notional units. Unvested units are subject to forfeiture if the participant is not an employee at the vesting date or if we do not meet certain ongoing cash flow performance targets.
Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the estimated fair value of the award on the grant date for notional units accounted for as equity awards and the fair value of the award at each balance sheet date for notional units accounted for as liability awards. Fair value of the awards granted prior to the 2010 amendment is determined by projecting the total number of notional units that will vest in future periods, including dividends received on notional units during the vesting period, and applying the current market price per share to the projected number of notional units that will vest. The fair value of awards granted for the 2010 performance period with market vesting conditions is based upon a Monte Carlo simulation model on their grant date. The aggregate number of shares which may be issued from treasury under the amended LTIP is limited to one million. Unvested notional units are recorded as either a liability or equity award based on management's intended method of redeeming the notional units when they vest.
10
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Summary of significant accounting policies (Continued)
(m) Concentration of credit risk:
The financial instruments that potentially expose us to credit risk consist primarily of cash and cash equivalents, restricted cash, derivative instruments and accounts receivable. Cash and restricted cash are held by major financial institutions that are also counterparties to our derivative instruments. We have long-term agreements to sell electricity, gas and steam to public utilities and corporations. We have exposure to trends within the energy industry, including declines in the creditworthiness of our customers. We do not normally require collateral or other security to support energy-related accounts receivable. We do not believe there is significant credit risk associated with accounts receivable due to payment history. See Note 13, Segment and related information, for a further discussion of customer concentrations.
(n) Segments:
We have six reportable segments: Path 15, Auburndale, Lake, Pasco, Chambers and Other Project Assets. Each of our projects is an operating segment. Based on similar economic and other characteristics, we aggregate several of the projects into the Other Project Assets reportable segment.
(o) Recently issued accounting standards:
Adopted
On January 1, 2010, we adopted changes issued by the Financial Accounting Standards Board (FASB) to accounting for variable interest entities. These changes require an enterprise to perform an analysis to determine whether the enterprise's variable interest or interests give it a controlling financial interest in a variable interest entity; to require ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity; to eliminate the solely quantitative approach previously required for determining the primary beneficiary of a variable interest entity; to add an additional reconsideration event for determining whether an entity is a variable interest entity when any changes in facts and circumstances occur such that holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of the entity that most significantly impact the entity's economic performance; and to require enhanced disclosures that will provide users of financial statements with more transparent information about an enterprise's involvement in a variable interest entity. The adoption of these changes had no impact on the consolidated financial statements.
On January 1, 2010, we adopted changes issued by the FASB to accounting for transfers of financial assets. These changes remove the concept of a qualifying special-purpose entity and remove the exception from the application of variable interest accounting to variable interest entities that are qualifying special-purpose entities; limit the circumstances in which a transferor derecognizes a portion or component of a financial asset; define a participating interest; require a transferor to recognize and initially measure at fair value all assets obtained and liabilities incurred as a result of a transfer accounted for as a sale; and require enhanced disclosure. The adoption of these changes had no impact on the consolidated financial statements.
Effective January 1, 2010, we adopted changes issued by the FASB on January 6, 2010 for a scope clarification to the FASB's previously-issued guidance on accounting for noncontrolling interests in consolidated financial statements. These changes clarify the accounting and reporting guidance for
11
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Summary of significant accounting policies (Continued)
noncontrolling interests and changes in ownership interests of a consolidated subsidiary. An entity is required to deconsolidate a subsidiary when the entity ceases to have a controlling financial interest in the subsidiary. Upon deconsolidation of a subsidiary, an entity recognizes a gain or loss on the transaction and measures any retained investment in the subsidiary at fair value. The gain or loss includes any gain or loss associated with the difference between the fair value of the retained investment in the subsidiary and its carrying amount at the date the subsidiary is deconsolidated. In contrast, an entity is required to account for a decrease in its ownership interest of a subsidiary that does not result in a change of control of the subsidiary as an equity transaction. The adoption of these changes had no impact on the consolidated financial statements.
Effective January 1, 2010, we adopted changes issued by the FASB on January 21, 2010 to disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. The changes also clarify existing disclosure requirements related to how assets and liabilities should be grouped by class and valuation techniques used for recurring and nonrecurring fair value measurements. The adoption of these changes had no impact on the consolidated financial statements.
Effective January 1, 2010, we adopted changes issued by the FASB on February 24, 2010 to accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued, otherwise known as "subsequent events." Specifically, these changes clarify that an entity that is required to file or furnish its financial statements with the Securities and Exchange Commission is not required to disclose the date through which subsequent events have been evaluated. The adoption of these changes had no impact on the consolidated financial statements.
On July 1, 2010, we adopted changes to existing accounting requirements for embedded credit derivatives. Specifically, the changes clarify the scope exception regarding when embedded credit derivative features are not considered embedded derivatives subject to potential bifurcation and separate accounting. The adoption of these changes had no impact on the consolidated financial statements.
Issued
In October 2009, the FASB issued changes to revenue recognition for multiple-deliverable arrangements. These changes require separation of consideration received in such arrangements by establishing a selling price hierarchy (not the same as fair value) for determining the selling price of a deliverable, which will be based on available information in the following order: vendor-specific objective evidence, third-party evidence, or estimated selling price; eliminate the residual method of allocation and require that the consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method, which allocates any discount in the arrangement to each deliverable on the basis of each deliverable's selling price; require that a vendor determine its best estimate of selling price in a manner that is consistent with that used to determine the price to sell the deliverable on a standalone basis; and expand the disclosures related to multiple-deliverable revenue arrangements. These changes become effective on January 1, 2011. We have determined that the adoption of these changes will not have an impact on the consolidated financial statements, as our projects do not currently have any such arrangements with its customers.
12
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. Summary of significant accounting policies (Continued)
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. These changes become effective beginning January 1, 2011. Other than the additional disclosure requirements, we have determined these changes will 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 become effective on January 1, 2011. We have determined these changes will not have an impact on the consolidated financial statements.
3. Comprehensive income (loss)
The following table summarizes the components of comprehensive income (loss), net of tax of $(25) and $(1,365), respectively, for the three months ended September 30, 2010 and 2009, and net of tax of $(135) and $7, respectively, for the nine months ended September 30, 2010 and 2009:
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | 2010 | 2009 | |||||||||
Net income (loss) |
$ | (537 | ) | $ | (15,803 | ) | $ | (5,284 | ) | $ | (22,289 | ) | |
Unrealized gain (loss) on hedging activity |
38 | 2,048 | 202 | (10 | ) | ||||||||
Comprehensive income (loss) |
$ | (499 | ) | $ | (13,755 | ) | $ | (5,082 | ) | $ | (22,299 | ) | |
4. Acquisitions
Idaho Wind
On July 2, 2010, we acquired a 27.6% equity interest in Idaho Wind Partners 1, LLC ("Idaho Wind") for $38.9 million and approximately $3.0 million in transaction costs. Idaho Wind recently commenced construction of a 183 MW wind power project located near Twin Falls, Idaho, which is expected to be completed in phases in late 2010 and early 2011. Idaho Wind has 20-year PPAs with Idaho Power Company. Our investment in Idaho Wind was funded with cash on hand and a $20.0 million borrowing under our senior credit facility, which was repaid in October 2010 with a portion of the proceeds from our public offering (see Note 17). Idaho Wind is accounted for under the equity method of accounting.
13
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. Acquisitions (Continued)
Rollcast
On March 31, 2009, we acquired a 40% equity interest in Rollcast Energy, Inc., a North Carolina Corporation for $3.0 million in cash. On March 1, 2010, we paid $1.2 million in cash for an additional 15% of the shares of Rollcast, increasing our interest from 40% to 55% and providing us control of Rollcast. We consolidated Rollcast as of this date. We previously accounted for our 40% interest in Rollcast as an equity method investment. On April 28, 2010, we paid an additional $0.8 million to increase our ownership interest in Rollcast to 60%.
Rollcast is a developer of biomass power plants in the southeastern U.S. with several projects in various stages of development. The investment in Rollcast gives us the option but not the obligation to invest equity in Rollcast's biomass power plants. In October 2010, we completed the project-level non-recourse financing and began construction on Rollcast's Piedmont Green Power project near Barnesville, Georgia. See Note 17 for additional information.
The following table summarizes the consideration transferred to acquire Rollcast and the preliminary estimated amounts of identifiable assets acquired and liabilities assumed at the March 1, 2010 acquisition date, as well as the fair value of the noncontrolling interest in Rollcast at the acquisition date:
Fair value of consideration transferred: |
|||||
Cash |
$ | 1,200 | |||
Other items to be allocated to identifiable assets acquired and liabilities assumed: |
|||||
Fair value of our investment in Rollcast at the acquisition date |
2,758 | ||||
Fair value of noncontrolling interest in Rollcast |
3,410 | ||||
Gain recognized on the step acquisition |
211 | ||||
Total |
$ | 7,579 | |||
Recognized amounts of identifiable assets acquired and liabilities assumed: |
|||||
Cash |
$ | 1,524 | |||
Property, plant and equipment |
130 | ||||
Prepaid expenses and other assets |
133 | ||||
Capitalized development costs |
2,705 | ||||
Trade and other payables |
(448 | ) | |||
Total identifiable net assets |
4,044 | ||||
Goodwill |
3,535 | ||||
|
$ | 7,579 | |||
As a result of obtaining control over Rollcast, our previously held 40% interest was remeasured to fair value, resulting in a gain of $0.2 million. This has been recognized in other income (expense) in the consolidated statements of operations.
The fair value of the noncontrolling interest of $3.4 million in Rollcast was estimated by applying an income approach using the discounted cash flow method. This fair value measurement is based on significant inputs not observable in the market and thus represents a Level 3 fair value measurement.
14
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. Acquisitions (Continued)
The fair value estimate utilized an assumed discount rate of 9.4% which is composed of a risk-free rate and an equity risk premium determined by the capital asset pricing of companies deemed to be similar to Rollcast. The estimate assumed that no fair value adjustments are required because of the lack of control or lack of marketability that market participants would consider when estimating the fair value of the noncontrolling interest in Rollcast.
The goodwill is attributable to the value of future biomass power plant development opportunities. It is not expected to be deductible for tax purposes. All of the $3.5 million of goodwill was assigned to the Other Project Assets segment.
5. Equity method investments
The following summarizes the operating results for the nine months ended September 30, 2010 and 2009, respectively, for the proportional ownership interest in our equity method investments:
|
Nine-months ended September 30, |
|||||||
---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | ||||||
Revenue |
||||||||
Chambers |
43,146 | 38,303 | ||||||
Badger Creek |
10,435 | 9,394 | ||||||
Gregory |
24,461 | 20,529 | ||||||
Orlando |
31,617 | 30,907 | ||||||
Selkirk |
39,156 | 35,372 | ||||||
Other |
4,728 | 23,062 | ||||||
|
153,543 | 157,567 | ||||||
Project expenses |
||||||||
Chambers |
30,883 | 31,519 | ||||||
Badger Creek |
9,188 | 7,891 | ||||||
Gregory |
21,448 | 18,479 | ||||||
Orlando |
30,039 | 29,047 | ||||||
Selkirk |
36,802 | 32,461 | ||||||
Other |
3,773 | 21,073 | ||||||
|
132,133 | 140,470 | ||||||
Project other income (expense) |
||||||||
Chambers |
(2,706 | ) | (3,052 | ) | ||||
Badger Creek |
200 | (3 | ) | |||||
Gregory |
(1,346 | ) | (828 | ) | ||||
Orlando |
(99 | ) | (30 | ) | ||||
Selkirk |
(4,704 | ) | (3,679 | ) | ||||
Other |
(205 | ) | (9,182 | ) | ||||
|
(8,860 | ) | (16,774 | ) | ||||
Project income (loss) |
||||||||
Chambers |
9,557 | 3,732 | ||||||
Badger Creek |
1,447 | 1,500 | ||||||
Gregory |
1,667 | 1,222 | ||||||
Orlando |
1,479 | 1,830 | ||||||
Selkirk |
(2,350 | ) | (768 | ) | ||||
Other |
750 | (7,193 | ) | |||||
|
12,550 | 323 |
15
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
6. 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 September 30, 2010 and December 31, 2009:
|
September 30, 2010 |
December 31, 2009 |
|||||
---|---|---|---|---|---|---|---|
Property, plant and equipment |
$ | 82,948 | $ | 74,567 | |||
Transmission system rights |
41,574 | 35,685 | |||||
Other intangible assets |
61,016 | 45,368 |
7. Long-term debt
Long-term debt represents project 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 debt is non-recourse to Atlantic Power and generally amortizes during the term of the respective revenue generating contracts of the projects.
|
September 30, 2010 |
December 31, 2009 |
|||||
---|---|---|---|---|---|---|---|
Project debt, interest rates ranging from 5.1% to 9.0% maturing through 2028 |
$ | 218,490 | $ | 230,331 | |||
Purchase accounting fair value adjustments |
11,487 | 12,030 | |||||
Less: current portion of long-term debt |
(18,456 | ) | (18,280 | ) | |||
Long-term debt |
$ | 211,521 | $ | 224,081 | |||
Project-level debt is secured by the respective projects and their contracts with no other recourse to us. At September 30, 2010, all of our projects were in compliance with the covenants contained in project-level debt.
16
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. Fair value of financial instruments
The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of September 30, 2010 and December 31, 2009. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
|
September 30, 2010 | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Level 1 | Level 2 | Level 3 | Total | ||||||||||
Assets: |
||||||||||||||
Cash and cash equivalents |
$ | 8,998 | $ | | $ | | $ | 8,998 | ||||||
Restricted cash |
22,257 | | | 22,257 | ||||||||||
Derivative instruments asset |
| 17,919 | | 17,919 | ||||||||||
Total |
$ | 31,255 | $ | 17,919 | $ | | $ | 49,174 | ||||||
Liabilities: |
||||||||||||||
Derivative instruments liability |
$ | | $ | 31,375 | $ | | $ | 31,375 | ||||||
Total |
$ | | $ | 31,375 | $ | | $ | 31,375 | ||||||
|
December 31, 2009 | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
Level 1 | Level 2 | Level 3 | Total | ||||||||||
Assets: |
||||||||||||||
Cash and cash equivalents |
$ | 49,850 | $ | | $ | | $ | 49,850 | ||||||
Restricted cash |
14,859 | | | 14,859 | ||||||||||
Derivative instruments asset |
| 19,908 | | 19,908 | ||||||||||
Total |
$ | 64,709 | $ | 19,908 | $ | | $ | 84,617 | ||||||
Liabilities: |
||||||||||||||
Derivative instruments liability |
$ | | $ | 12,025 | $ | | $ | 12,025 | ||||||
Total |
$ | | $ | 12,025 | $ | | $ | 12,025 | ||||||
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 September 30, 2010, the credit reserve resulted in a $1.7 million net increase in fair value, which is comprised of a $0.4 million gain in other comprehensive income and a $1.4 million gain in change in fair value of derivative instruments offset by a $0.1 million loss in foreign exchange.
17
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Accounting for derivative instruments and hedging activities
Fair value of derivative instruments
We have elected to disclose derivative instruments 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:
|
September 30, 2010 | |||||||
---|---|---|---|---|---|---|---|---|
|
Derivative Assets |
Derivative Liabilities |
||||||
Derivative instruments designated as cash flow hedges: |
||||||||
Interest rate swap current |
$ | | $ | 398 | ||||
Interest rate swap long-term |
| 159 | ||||||
Total derivative instruments designated as cash flow hedges |
| 557 | ||||||
Derivative instruments not designated as cash flow hedges: |
||||||||
Interest rate swap current |
| 1,248 | ||||||
Interest rate swap long-term |
| 3,132 | ||||||
Foreign currency forward contracts current |
5,988 | | ||||||
Foreign currency forward contracts long-term |
11,931 | | ||||||
Natural gas swap current |
| 3,270 | ||||||
Natural gas swap long-term |
| 23,168 | ||||||
Total derivative instruments not designated as cash flow hedges |
17,919 | 30,818 | ||||||
Total derivative instruments |
$ | 17,919 | $ | 31,375 | ||||
|
December 31, 2009 | |||||||
---|---|---|---|---|---|---|---|---|
|
Derivative Assets |
Derivative Liabilities |
||||||
Derivative instruments designated as cash flow hedges: |
||||||||
Interest rate swap current |
$ | | $ | 726 | ||||
Interest rate swap long-term |
| 167 | ||||||
Total derivative instruments designated as cash flow hedges |
| 893 | ||||||
Derivative instruments not designated as cash flow hedges: |
||||||||
Interest rate swap current |
| 1,705 | ||||||
Interest rate swap long-term |
| 1,707 | ||||||
Foreign currency forward contracts current |
5,619 | | ||||||
Foreign currency forward contracts long-term |
14,289 | | ||||||
Natural gas swap current |
95 | 4,174 | ||||||
Natural gas swap long-term |
14 | 3,655 | ||||||
Total derivative instruments not designated as cash flow hedges |
20,017 | 11,241 | ||||||
Total derivative instruments |
$ | 20,017 | $ | 12,134 | ||||
18
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Accounting for derivative instruments and hedging activities (Continued)
Natural gas swaps
The Lake project's operating margin is exposed to changes in natural gas spot market prices from the expiration of its natural gas supply contract on June 30, 2009 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 expiry of the fuel supply agreement in mid-2012 until the termination of its PPA at the end of 2013.
Our strategy to mitigate the future exposure to changes in natural gas prices at Lake and Auburndale 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. Changes in the fair value of the natural gas swaps through June 30, 2009 were recorded in other comprehensive income (loss) as they were designated as a hedge of the risk associated with changes in market prices of natural gas. As of July 1, 2009, we de-designated these natural gas swap hedges and the changes in their fair value subsequent to July 1, 2009 are now recorded in change in fair value of derivative instruments in the consolidated statements of operations. Amounts in accumulated other comprehensive income (loss) remaining prior to de-designation are amortized into the consolidated statements of operations over the remaining term of the natural gas swaps.
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 was executed in November 2009 and expires on November 30, 2013.
The interest rate swap is a derivative financial instrument designated as a cash flow hedge and is recorded in the balance sheet at fair value. Changes in the fair value of the interest rate swap are recorded in accumulated other comprehensive income (loss) and reclassified to interest expense when settled in cash.
Impact of derivative instruments on the consolidated income statements
Unrealized gains on interest rate swaps designated as cash flow hedges have been recorded in the consolidated statements of operations as a gain in other comprehensive income of $0.1 million and $0.4 million for the three and nine month periods ended September 30, 2010. Realized losses on these interest rate swaps of $0.2 million and $0.6 million were recorded in interest expense, net for the three and nine month periods ended September 30, 2010.
19
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Accounting for derivative instruments and hedging activities (Continued)
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. Other comprehensive loss recorded for natural gas swap contracts accounted for as cash flow hedges totaled $5.1 million, net of tax, prior to July 1, 2009 when hedge accounting for these natural gas swaps was discontinued prospectively. Amortization of the loss of $0.4 million and $1.3 million was recorded in change in fair value of derivative instruments for the three and nine month periods ended September 30, 2010.
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:
|
Classification of (gain) loss recognized in income |
Three months ended September 30, 2010 |
Nine months ended September 30, 2010 |
||||||
---|---|---|---|---|---|---|---|---|---|
Natural gas swaps |
Fuel | $ | 2,076 | $ | 6,515 | ||||
Foreign currency forwards |
Foreign exchange gain | (1,423 | ) | (4,190 | ) | ||||
Interest rate swaps |
Interest, net | 365 | 1,314 |
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 changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:
|
Three months ended September 30, |
Nine months ended September 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | 2010 | 2009 | ||||||||||
Change in fair value of derivative instruments: |
||||||||||||||
Interest rate swaps |
$ | (804 | ) | $ | 262 | $ | (970 | ) | $ | (98 | ) | |||
Natural gas swaps |
(8,940 | ) | (613 | ) | (19,976 | ) | (613 | ) | ||||||
|
$ | (9,744 | ) | $ | (351 | ) | $ | (20,946 | ) | $ | (711 | ) | ||
Notional volumes of derivative instruments transactions
The following table summarizes the net notional volume of our derivative instruments transactions by type, excluding those derivatives that qualified for the normal purchases and normal sales exception as of September 30, 2010:
|
Units | Notional amount as of September 30, 2010 |
||||
---|---|---|---|---|---|---|
Interest rate swaps |
US$ | $ | 9,679 | |||
Currency forwards |
Cdn$ | $ | 239,700 | |||
Natural gas swaps |
Mmbtu | 15,150 |
20
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 reinforcing 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 of Cdn$1.134 per U.S. dollar in amounts sufficient to make monthly dividend payments at the current annual dividend level of Cdn$1.094 per common share, as well as interest payments on our 6.25% convertible debentures due March 15, 2017 (the "2009 Debentures"), through December 2013.
In addition, we have executed forward contracts to purchase Canadian dollars at fixed rates of exchange sufficient to make semi-annual payments on our 6.50% convertible secured debentures due October 31, 2014 (the "2006 Debentures"). The contracts provide for the purchase of Cdn$1.9 million in April and in October of each year through 2011 at a rate of Cdn$1.1075 per U.S. dollar.
It is our intention to periodically consider extending the length of these forward contracts. In addition, we will consider executing additional foreign currency forward contracts to hedge expected additional dividend and interest payments associated with the common shares and convertible debentures issued in our October 2010 public offering (see Note 17).
The foreign exchange forward contracts are recorded at estimated 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 at September 30, 2010 is an asset of $17.9 million. 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 nine month periods ended September 30, 2010 and 2009:
|
Three months ended September 30, |
Nine months ended September 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | 2010 | 2009 | ||||||||||
Unrealized foreign exchange (gain) loss: |
||||||||||||||
Subordinated notes and convertible debentures |
$ | 4,886 | $ | 33,625 | $ | 2,380 | $ | 51,282 | ||||||
Forward contracts and other |
(5,716 | ) | (19,389 | ) | 1,989 | (27,416 | ) | |||||||
|
(830 | ) | 14,236 | 4,369 | 23,866 | |||||||||
Realized foreign exchange gains on forward contract settlements |
(1,423 | ) | (1,708 | ) | (4,190 | ) | (1,832 | ) | ||||||
|
$ | (2,253 | ) | $ | 12,528 | $ | 179 | $ | 22,034 | |||||
21
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Accounting for derivative instruments and hedging activities (Continued)
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 September 30, 2010:
Convertible debentures |
$ | 14,210 | ||
Foreign currency forward contracts |
$ | 25,245 |
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 a 40% effective tax rate:
For the three month period ended September 30, 2010
|
Interest Rate Swaps |
Natural Gas Swaps |
Total | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Accumulated OCI balance at June 30, 2010 |
$ | (374 | ) | $ | 180 | $ | (194 | ) | ||
Change in fair value of cash flow hedges |
(71 | ) | | (71 | ) | |||||
Realized from OCI during the period |
109 | 254 | 363 | |||||||
Accumulated OCI balance at September 30, 2010 |
$ | (336 | ) | $ | 434 | $ | 98 | |||
For the nine month period ended September 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 |
(165 | ) | | (165 | ) | |||||
Realized from OCI during the period |
367 | 755 | 1,122 | |||||||
Accumulated OCI balance at September 30, 2010 |
$ | (336 | ) | $ | 434 | $ | 98 | |||
10. Income taxes
The difference between the actual tax expense of $3.6 million and $12.1 million for the three and nine months ended September 30, 2010, respectively, and the expected income tax expense, based on the Canadian enacted statutory rate of 30%, of $0.9 million and $2.0 million, respectively, is primarily due to an increase in the valuation allowance and various other permanent differences. The difference between the actual tax expense and the expected income tax for the nine months ended September 30, 2010 primarily relates to a $7.5 million increase in the valuation allowance and a $3.3 permanent difference related to the estimated percentage ownership at Selkirk based on the priority distribution computation.
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | 2010 | 2009 | |||||||||
Current income tax expense (benefit) |
$ | 474 | $ | (58 | ) | $ | 1,550 | $ | (3,271 | ) | |||
Deferred tax expense (benefit) |
3,140 | (6,397 | ) | 10,555 | (5,833 | ) | |||||||
Total income tax expense (benefit) |
$ | 3,614 | $ | (6,455 | ) | $ | 12,105 | $ | (9,104 | ) | |||
22
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
10. Income taxes (Continued)
Valuation Allowance
As of September 30, 2010, we have recorded a valuation allowance of $74.6 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 nine months ended September 30, 2010:
|
Units | Grant Date Weighted-Average Fair Value per Unit |
|||||
---|---|---|---|---|---|---|---|
Outstanding at December 31, 2009 |
471,281 | $ | 7.30 | ||||
Granted |
305,112 | $ | 13.29 | ||||
Additional shares from dividends |
35,390 | $ | 9.30 | ||||
Vested |
(222,265 | ) | $ | 7.94 | |||
Outstanding at September 30, 2010 |
589,518 | $ | 10.28 | ||||
In the second quarter of 2010, the board of directors approved an amendment to the LTIP. The amended LTIP will be effective for grants beginning with the 2010 performance year. Under the amended LTIP, the notional units granted to plan participants will have the same characteristics as notional units under the old LTIP. However, the number of notional units that vest will be based, in part, on the total shareholder return of Atlantic Power compared to a group of peer companies in Canada. In addition, vesting of the notional units for officers of Atlantic Power will occur on a three year cliff basis as opposed to ratable vesting over three years for grants made prior to the amendments.
Vested notional units are expected to be redeemed one-third in cash and two-thirds in shares of our common stock. Notional units granted that are expected to be redeemed in cash upon vesting are accounted for as liability awards. Notional units granted that are expected to be redeemed in common shares upon vesting are accounted for as equity awards. Notional units granted prior to the 2010 performance period are subject to the vesting conditions of the LTIP before the amendments made in 2010. We reclassified the portion of outstanding awards expected to vest in common shares totaling $1.4 million from accounts payable and accrued liabilities and other non-current liabilities to common shares as of June 29, 2010, the date the amended LTIP was approved by our shareholders.
On March 29, 2010, our board of directors approved the grant of 138,892 notional LTIP units for the 2009 performance period under the terms of the LTIP before the 2010 amendments. In May 2010, our board of directors approved the initial grant of 83,110 notional LTIP units for executive officers under the amended LTIP for the 2010-2012 performance period, subject to final shareholder approval of the amended LTIP, which occurred on June 29, 2010. Also in May 2010 and subject to the final shareholder approval of the amended LTIP, our board of directors granted transition awards to our executive officers consisting of an additional 83,110 notional LTIP units. The transition awards are
23
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. Long-Term Incentive Plan (Continued)
designed to mitigate the impact of the changes in vesting provisions of the LTIP from a ratable vesting over three years to cliff vesting at the end of three years. The transition awards are subject to the performance measurement and other provisions of the amended LTIP, except that 1/3 of the transition awards vest in the first quarter of 2011 and the other 2/3 vest in the first quarter of 2012.
The notional units, other than the transition awards, granted under the amended LTIP cliff-vest three years after the grant date. The final number of notional units, if any, that will vest at the end of the three year vesting period will be based on the Company's achievement of target levels of relative total shareholder return, which is the change in the value of an investment in the Company's common stock, including reinvestment of dividends, compared to that of a peer group of companies during the performance period. The total number of notional units vesting will range from zero up to a maximum 150% of the number of notional units in the executives' accounts on the vesting date for that award, depending on the level of achievement of relative total shareholder return during the measurement period.
Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the estimated fair value of the award on the grant date for notional units accounted for as equity awards and the fair value of the award at each balance sheet date for notional units accounted for as liability awards. Fair value of the awards granted prior to the 2010 LTIP amendment is determined by projecting the total number of notional units that will vest in future periods, including dividends received on notional units during the vesting period, and applying the current market price per share to the projected number of notional units that will vest. The fair value of awards granted in 2010 under the amended LTIP with market vesting conditions is based upon a Monte Carlo simulation model on their grant date. Compensation expense is recognized regardless of the relative total shareholder return performance, provided that the LTIP participant remains employed by the Company. The fair value of all outstanding notional units under the amended LTIP and the amended LTIP at September 30, 2010, is approximately $7.7 million. The aggregate number of shares which may be issued from treasury under the amended LTIP is limited to one million. Unvested notional units are recorded as either a liability or equity award based on management's intended method of redeeming the notional units when they vest.
Both the total shareholder return performance and the fair value of the notional units under the Monte Carlo simulation are determined for the Company by a third party.
In calculating the fair value of the awards granted in 2010 under the amended LTIP, the Monte Carlo simulation model utilizes multiple input variables over the performance period in order to determine the likely relative total shareholder return. The Monte Carlo simulation model computed simulated total shareholder return for the Company and for its peer companies during the remaining time in the performance period with the following inputs: (i) stock price on the measurement date (ii) expected volatility; (iii) risk-free interest rate; (iv) dividend yield and (v) correlations of historical common stock returns between the Company and the peer companies and among the peer companies. Expected volatilities utilized in the Monte Carlo model are based on historical volatility of the Company's and the peer companies' stock prices over a period equal in length to that of the remaining vesting period. The risk-free interest rate is derived from the U.S. Treasury yield curve in effect at the time of grant with a term equal to the performance period assumption at the time of grant.
24
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 included the following assumptions:
|
Nine months ended September 30, 2010 |
|||
---|---|---|---|---|
Weighted-average risk free rate of return |
0.53 | % | ||
Dividend yield |
9.4 | % | ||
Expected volatilityCompany |
45 | % | ||
Expected volatilitypeer companies |
28 - 64 | % | ||
Weighted-average remaining measurement period |
1.6 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, 2010. 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 three and nine month period ended September 30, 2010 and the three and nine month periods ended September 30, 2009, diluted earnings per share is equal to basic earnings per share as the inclusion of potentially dilutive shares in the computation is anti-dilutive.
25
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. Basic and diluted earnings (loss) per share (Continued)
The following table sets forth the diluted net income and potentially dilutive shares utilized in the per share calculation for the three and nine month periods ended September 30, 2010 and 2009:
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | 2010 | 2009 | |||||||||
Numerator: |
|||||||||||||
Net loss attributable to Atlantic Power Corporation |
$ | (438 | ) | $ | (15,803 | ) | $ | (5,056 | ) | $ | (22,289 | ) | |
Add: interest expense for potentially dilutive convertible debentures, net(1) |
| | | | |||||||||
Diluted net loss attributable to Atlantic Power Corporation |
$ | (438 | ) | $ | (15,803 | ) | $ | (5,056 | ) | $ | (22,289 | ) | |
- (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 all periods presented.
|
Three months ended September 30, |
Nine months ended September 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | 2010 | 2009 | ||||||||||
Denominator: |
||||||||||||||
Basic shares outstanding |
60,511 | 60,518 | 60,466 | 60,685 | ||||||||||
Dilutive potential shares: |
||||||||||||||
Convertible debentures |
11,473 | 4,839 | 11,473 | 4,839 | ||||||||||
LTIP notional units |
614 | 455 | 499 | 395 | ||||||||||
Potentially dilutive shares |
72,598 | 65,812 | 72,438 | 65,919 | ||||||||||
Diluted EPS |
$ | (0.01 | ) | $ | (0.26 | ) | $ | (0.08 | ) | $ | (0.37 | ) | ||
Potentially dilutive shares from convertible debentures and potentially dilutive shares from LTIP notional units have been excluded from fully diluted shares because their impact would be anti-dilutive.
26
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 less 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 included in the table below.
|
Path 15 | Auburndale | Lake | Pasco | Chambers | Other Project Assets |
Un-allocated Corporate |
Consolidated | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Three month period ended September 30, 2010: |
|||||||||||||||||||||||||
Operating revenues |
$ | 7,813 | $ | 19,373 | $ | 23,721 | $ | 3,132 | $ | | $ | | $ | | $ | 54,039 | |||||||||
Segment assets |
218,947 | 116,033 | 118,591 | 40,083 | | 8,116 | 362,723 | 864,493 | |||||||||||||||||
Goodwill |
8,918 | | | | | 3,535 | | 12,453 | |||||||||||||||||
Project Adjusted EBITDA |
$ | 7,318 | $ | 10,018 | $ | 9,325 | $ | 1,335 | $ | 4,637 | $ | 8,910 | $ | | $ | 41,543 | |||||||||
Change in fair value of derivative instruments |
| 4,319 | 4,623 | | 621 | 1,143 | | 10,706 | |||||||||||||||||
Depreciation and amortization |
2,096 | 4,949 | 2,275 | 751 | 848 | 5,430 | | 16,349 | |||||||||||||||||
Interest, net |
3,071 | 395 | (2 | ) | | 1,638 | 804 | | 5,906 | ||||||||||||||||
Other project (income) expense |
1 | | | (22 | ) | 199 | 770 | | 948 | ||||||||||||||||
Project income |
2,150 | 355 | 2,429 | 606 | 1,331 | 763 | | 7,634 | |||||||||||||||||
Interest, net |
| | | | | | 2,707 | 2,707 | |||||||||||||||||
Administration |
| | | | | | 4,103 | 4,103 | |||||||||||||||||
Foreign exchange gain |
| | | | | | (2,253 | ) | (2,253 | ) | |||||||||||||||
Other income, net |
| | | | | | | | |||||||||||||||||
Loss from operations before income taxes |
2,150 | 355 | 2,429 | 606 | 1,331 | 763 | (4,557 | ) | 3,077 | ||||||||||||||||
Income tax expense (benefit) |
| | | | | | 3,614 | 3,614 | |||||||||||||||||
Net loss |
$ | 2,150 | $ | 355 | $ | 2,429 | $ | 606 | $ | 1,331 | $ | 763 | $ | (8,171 | ) | $ | (537 | ) | |||||||
27
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 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Three month period ended September 30, 2009: |
|||||||||||||||||||||||||
Operating revenues |
$ | 7,792 | $ | 18,124 | $ | 15,957 | $ | 2,984 | $ | | $ | | $ | | $ | 44,857 | |||||||||
Segment assets |
229,983 | 140,340 | 122,258 | 42,877 | | | 320,861 | 856,319 | |||||||||||||||||
Goodwill |
8,918 | | | | | | | 8,918 | |||||||||||||||||
Project Adjusted EBITDA |
$ | 7,061 | $ | 9,707 | $ | 5,128 | $ | 247 | $ | 4,301 | $ | 9,631 | $ | | $ | 36,075 | |||||||||
Change in fair value of derivative instruments |
| 175 | (787 | ) | | 161 | (487 | ) | | (938 | ) | ||||||||||||||
Depreciation and amortization |
2,095 | 4,949 | 2,263 | 746 | 855 | 5,853 | | 16,761 | |||||||||||||||||
Interest, net |
3,220 | 655 | (4 | ) | 1 | 1,876 | 2,016 | | 7,764 | ||||||||||||||||
Other project (income) expense |
| | (1 | ) | | 627 | 7,418 | | 8,044 | ||||||||||||||||
Project income |
1,746 | 3,928 | 3,657 | (500 | ) | 782 | (5,169 | ) | | 4,444 | |||||||||||||||
Interest, net |
| | | | | | 11,285 | 11,285 | |||||||||||||||||
Administration |
| | | | | | 2,907 | 2,907 | |||||||||||||||||
Foreign exchange gain |
| | | | | | 12,528 | 12,528 | |||||||||||||||||
Other income, net |
| | | | | | (18 | ) | (18 | ) | |||||||||||||||
Loss from operations before income taxes |
1,746 | 3,928 | 3,657 | (500 | ) | 782 | (5,169 | ) | (26,702 | ) | (22,258 | ) | |||||||||||||
Income tax expense (benefit) |
| | | | | | (6,455 | ) | (6,455 | ) | |||||||||||||||
Net loss |
$ | 1,746 | $ | 3,928 | $ | 3,657 | $ | (500 | ) | $ | 782 | $ | (5,169 | ) | $ | (20,247 | ) | $ | (15,803 | ) | |||||
|
Path 15 | Auburndale | Lake | Pasco | Chambers | Other Project Assets |
Un-allocated Corporate |
Consolidated | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Nine month period ended September 30, 2010: |
|||||||||||||||||||||||||
Operating revenues |
$ | 23,186 | $ | 59,410 | $ | 57,804 | $ | 8,764 | $ | | $ | | $ | | $ | 149,164 | |||||||||
Segment assets |
218,947 | 116,033 | 118,591 | 40,083 | | 8,116 | 362,723 | 864,493 | |||||||||||||||||
Goodwill |
8,918 | | | | | 3,535 | | 12,453 | |||||||||||||||||
Project Adjusted EBITDA |
$ | 21,348 | $ | 29,820 | $ | 23,937 | $ | 3,752 | $ | 14,780 | $ | 25,181 | $ | | $ | 118,818 | |||||||||
Change in fair value of derivative instruments |
| 9,128 | 10,849 | | 408 | 3,050 | | 23,435 | |||||||||||||||||
Depreciation and amortization |
6,290 | 14,847 | 6,811 | 2,243 | 2,536 | 16,604 | | 49,331 | |||||||||||||||||
Interest, net |
9,313 | 1,281 | (8 | ) | | 4,965 | 2,233 | | 17,784 | ||||||||||||||||
Other project (income) expense |
1 | | | (22 | ) | 603 | 647 | | 1,229 | ||||||||||||||||
Project income |
5,744 | 4,564 | 6,285 | 1,531 | 6,268 | 2,647 | | 27,039 | |||||||||||||||||
Interest, net |
| | | | | | 8,019 | 8,019 | |||||||||||||||||
Administration |
| | | | | | 12,046 | 12,046 | |||||||||||||||||
Foreign exchange gain |
| | | | | | 179 | 179 | |||||||||||||||||
Other income, net |
| | | | | | (26 | ) | (26 | ) | |||||||||||||||
Loss from operations before income taxes |
5,744 | 4,564 | 6,285 | 1,531 | 6,268 | 2,647 | (20,218 | ) | 6,821 | ||||||||||||||||
Income tax expense (benefit) |
162 | | | | | | 11,943 | 12,105 | |||||||||||||||||
Net loss |
$ | 5,582 | $ | 4,564 | $ | 6,285 | $ | 1,531 | $ | 6,268 | $ | 2,647 | $ | (32,161 | ) | $ | (5,284 | ) | |||||||
28
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 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Nine month period ended September 30, 2009: |
|||||||||||||||||||||||||
Operating revenues |
$ | 23,208 | $ | 56,113 | $ | 47,061 | $ | 8,779 | $ | | $ | | $ | | $ | 135,161 | |||||||||
Segment assets |
229,983 | 140,340 | 122,258 | 42,877 | | | 320,861 | 856,319 | |||||||||||||||||
Goodwill |
8,918 | | | | | | 8,918 | ||||||||||||||||||
Project Adjusted EBITDA |
$ | 20,894 | $ | 28,254 | $ | 20,749 | $ | 3,116 | $ | 9,325 | $ | 28,788 | $ | | $ | 111,126 | |||||||||
Change in fair value of derivative instruments |
| 175 | (787 | ) | | (1,722 | ) | 803 | | (1,531 | ) | ||||||||||||||
Depreciation and amortization |
6,406 | 14,831 | 7,829 | 2,240 | 2,540 | 17,919 | | 51,765 | |||||||||||||||||
Interest, net |
9,664 | 1,969 | (10 | ) | (42 | ) | 5,906 | 5,913 | | 23,400 | |||||||||||||||
Other project (income) expense |
(1,229 | ) | | 61 | (25 | ) | 1,037 | 7,209 | | 7,053 | |||||||||||||||
Project income |
6,053 | 11,279 | 13,656 | 943 | 1,564 | (3,056 | ) | | 30,439 | ||||||||||||||||
Interest, net |
| | | | | | 31,455 | 31,455 | |||||||||||||||||
Administration |
| | | | | | 8,391 | 8,391 | |||||||||||||||||
Foreign exchange gain |
| | | | | | 22,034 | 22,034 | |||||||||||||||||
Other income, net |
| | | | | | (48 | ) | (48 | ) | |||||||||||||||
Loss from operations before income taxes |
6,053 | 11,279 | 13,656 | 943 | 1,564 | (3,056 | ) | (61,832 | ) | (31,393 | ) | ||||||||||||||
Income tax expense (benefit) |
| | | | | | (9,104 | ) | (9,104 | ) | |||||||||||||||
Net loss |
$ | 6,053 | $ | 11,279 | $ | 13,656 | $ | 943 | $ | 1,564 | $ | (3,056 | ) | $ | (52,728 | ) | $ | (22,289 | ) | ||||||
Progress Energy Florida and the California Independent System Operator ("CAISO") provide for 74% and 15%, respectively, of total consolidated revenues for the three months ended September 30, 2010 and 75% and 17% for the three months ended September 30, 2009 and 76% and 16%, respectively, of total consolidated revenues for the nine months ended September 30, 2010 and 76% and 17% for the nine months ended September 30, 2009. Progress Energy Florida purchases electricity from Auburndale and Lake, and the CAISO makes payments to Path 15.
14. Related party transactions
During the third quarter of 2010, we made a short-term $12.8 million loan to Idaho Wind to provide temporary funding for construction of the project until a portion of the project-level construction financing was completed in early October 2010, resulting in $4.1 million of the loan being repaid to us. The outstanding loans bear interest at a prime rate plus 10% (13.25% as September 30, 2010).
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 Capital Partners, LLC ("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 million, to be satisfied by a payment of $6 million that was made at the termination date, and additional payments of $5 million, $3 million and $1 million on the respective first, second and third anniversaries of the termination date. We recorded the remaining liability associated with the termination fee at its estimated fair value of $8.1 million at December 31, 2009. The contract termination liability is being accreted to the final amounts due over the term of these payments.
29
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. Normal course issuer bid
In 2008, we initiated a normal course issuer bid to purchase up to four million IPSs, representing approximately 8% of Atlantic Power's public float at that time. For the nine months ended September 30, 2009, we acquired 481,600 IPSs at an average price of Cdn$8.42 under the terms of our existing normal course issuer bid. As of September 30, 2009, we had acquired a cumulative total of 1,040,220 IPSs at an average price of Cdn$8.61 since the inception of the issuer bid in July 2008. We paid the market price at the time of acquisition for any IPSs purchased through the facilities of the Toronto Stock Exchange, and all IPSs acquired under the bid have been cancelled. The issuer bid expired on July 24, 2009.
16. Commitments and contingencies
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 September 30, 2010 which are expected to have a material adverse impact on our financial position or results of operations.
17. Subsequent events
On October 8, 2010, Idaho Wind closed a $221.7 million project-level credit facility. The facility is composed of two tranches, which includes a $138.5 million construction loan that will convert to a 17-year term loan following commercial operation and a $83.2 million cash grant facility which will be repaid with federal stimulus grant proceeds after completion of construction. We own a 27.6% equity interest in Idaho Wind.
On October 18, 2010, we entered into natural gas swaps that are effective in 2014 and 2015. The natural gas swaps are related to expected fuel purchases attributable to our 50% share of the 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. 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 represents approximately 25% of our share of the expected natural gas purchases at the project during 2014 and 2015. These natural gas swaps are derivative financial instruments and will be recorded in the consolidated balance sheets at fair value. Changes in the fair value of the natural gas swaps will be recorded in the statement of operations.
On October 20, 2010, we completed a public offering of 6,029,000 common shares, including 784,000 common shares issued pursuant to the exercise in full of the underwriters' over-allotment option, at a price of $13.35 per common share. We received net proceeds from the common share offering, after deducting the underwriting discounts and expenses, of approximately $75.6 million.
On October 20, 2010, we also completed the closing of a public offering of Cdn$80.5 million aggregate principal amount of convertible unsecured subordinated debentures at a price of Cdn$1,000 per debenture, including Cdn$10.5 million aggregate principal amount of debentures pursuant to the exercise in full of the underwriters' over-allotment option. The debentures bear interest at a rate of 5.60%, and will mature on June 30, 2017, unless earlier redeemed. The debentures are convertible into our common shares at an initial conversion rate of 55.2486 common shares per Cdn$1,000 principal amount of debentures, representing an initial conversion price of approximately Cdn$18.10 per common share (equivalent to US$18.03 per common share). We received net proceeds from the
30
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. Subsequent events (Continued)
debenture offering, after deducting the underwriting discounts and expenses, of approximately Cdn$76.4 million.
The net proceeds from the public offering of approximately $152.0 million are expected to be used as follows:
-
- $20.0 million to repay the outstanding borrowings on our revolving credit facility that was used to partially fund
the acquisition of Idaho Wind;
-
- Up to $75 million to fund our equity contribution to the Piedmont Green Power biomass project described below;
-
- Approximately $35.0 million to fund our expected acquisition of the Cadillac biomass plant described below; and
-
- Remaining net proceeds of approximately $20.0 million for general corporate purposes and continued execution of our growth strategy.
On October 21, 2010, we closed a non-recourse, project-level bank financing for Piedmont, our first biomass power project. The terms of the financing include an $82 million construction and term loan and a $51 million bridge loan related to the stimulus grant to be received from the U.S. Treasury 60 days after the start of commercial operations. The project has executed a swap that results in an average fixed interest rate of approximately 5.2% during the construction period and the first three years of the term loan. In addition, we will make an equity contribution of approximately $75 million for substantially all of the equity interests in Piedmont.
On October 22, 2010, we entered into a purchase and sale agreement to acquire 100% of the membership interests of Cadillac Renewable Energy, LLC, a 39.6 MW wood fired facility located in Cadillac, Michigan from a joint venture which is jointly owned by ArcLight Energy Partners Fund II and Olympus Power, LLC. The purchase price will be approximately $77 million, subject to customary working capital adjustments, and will be funded by $35 million cash on hand and $42 million of assumed non-recourse, project-level debt. Operations and maintenance will be managed by our majority-owned subsidiary Rollcast Energy. The acquisition is anticipated to close by the end of 2010.
18. United States and Canadian accounting policy differences
In accordance with Canadian securities legislation, issuers that file reports with the Securities and Exchange Commission in the United States are allowed to file financial statements under United States GAAP to meet their continuous disclosure obligations in Canada. We have included a reconciliation highlighting the material differences between our consolidated financial statements prepared in accordance with United States GAAP compared to its consolidated financial statements prepared in accordance with Canadian GAAP below.
31
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
18. United States and Canadian accounting policy differences (Continued)
Consolidated reconciliation of net income and shareholders' equity
Net income (loss) and shareholders' equity reconciled to Canadian GAAP are as follows:
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | 2010 | 2009 | |||||||||
Net income (loss), based on United States GAAP |
$ | (537 | ) | $ | (15,803 | ) | $ | (5,284 | ) | $ | (22,289 | ) | |
Changes in fair value of power purchase agreement, net of tax(1) |
4,026 | 39,319 | (12,867 | ) | 29,193 | ||||||||
Projects accounted for under the cost method of accounting, net of tax(2) |
787 | 379 | 2,610 | 4,391 | |||||||||
Net income (loss), based on Canadian GAAP |
$ | 4,276 | $ | 23,895 | $ | (15,541 | ) | $ | 11,295 | ||||
|
September 30, | ||||||
---|---|---|---|---|---|---|---|
|
2010 | 2009 | |||||
Shareholders' equity, based on United States GAAP |
$ | 369,303 | $ | 110,307 | |||
Adjusted for cumulative effect of US/Canadian differences |
70,848 | 67,649 | |||||
|
440,151 | 177,956 | |||||
Net earnings for the period, Canadian GAAP |
(15,541 | ) | 11,295 | ||||
Shareholders' equity, based on Canadian GAAP |
$ | 424,610 | $ | 189,251 | |||
- (1)
- The
United States GAAP accounting standard for derivative instruments provides an exemption for PPAs that contain both a capacity payment and
an energy component which, if certain criteria are met, qualifies the PPA for the normal purchases and normal sales treatment. A similar exemption does not exist under Canadian GAAP and accordingly, a
PPA with a capacity payment, a minimum or specified quantity of energy and delivery into a liquid market is subject to fair value accounting. Our PPA at the Chambers project meets the normal purchases
and normal sales exemption under United States GAAP and is not subject to fair value accounting.
- (2)
- We follow a standard under United States GAAP that establishes a presumption of significant influence with a low threshold of ownership in investments in limited partnerships and requires accounting under the equity method. Our investments in the Selkirk and Gregory projects are accounted for under the cost method for Canadian GAAP because there is not a different threshold for ownership interest in limited partnerships and we do not exercise significant influence over the operating and financial policies of these investments.
32
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
18. United States and Canadian accounting policy differences (Continued)
Earnings per share
|
Three months ended September 30, | Nine months ended September 30, | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | 2010 | 2009 | ||||||||||
Earnings per share under Canadian GAAP |
||||||||||||||
Income from continuing operation per sharebasic |
$ | 0.07 | $ | 0.42 | $ | (0.25 | ) | $ | 0.23 | |||||
Income from discontinued operation per sharebasic |
| (0.03 | ) | | (0.04 | ) | ||||||||
Net income from sharebasic |
$ | 0.07 | $ | 0.39 | $ | (0.25 | ) | $ | 0.19 | |||||
Income from continuing operation per sharediluted |
$ | 0.07 | $ | 0.39 | $ | (0.25 | ) | $ | 0.22 | |||||
Income from discontinued operation per sharediluted |
| (0.03 | ) | | (0.04 | ) | ||||||||
Net income from sharediluted |
$ | 0.07 | $ | 0.36 | $ | (0.25 | ) | $ | 0.18 | |||||
Condensed consolidated balance sheet
|
September 30, 2010 |
December 31, 2009 |
||||||
---|---|---|---|---|---|---|---|---|
|
(Canadian GAAP) |
(Canadian GAAP) |
||||||
Assets |
||||||||
Current assets |
$ | 114,036 | $ | 149,340 | ||||
Equity investments in unconsolidated affiliates(1) |
99,824 | 61,037 | ||||||
Other long-term assets |
783,046 | 827,175 | ||||||
Total assets |
$ | 996,906 | $ | 1,037,552 | ||||
Liabilities and Shareholders' Equity |
||||||||
Current liabilities |
$ | 100,392 | $ | 77,471 | ||||
Other non-current liabilities |
471,904 | 480,398 | ||||||
Shareholders' equity: |
||||||||
Common shares |
544,834 | 541,304 | ||||||
Accumulated other comprehensive loss |
98 | (859 | ) | |||||
Retained deficit |
(123,703 | ) | (60,762 | ) | ||||
Noncontrolling interest |
3,381 | | ||||||
Total shareholders' equity |
424,610 | 479,683 | ||||||
Total liabilities and shareholders' equity |
$ | 996,906 | $ | 1,037,552 | ||||
- (1)
- We follow a standard under United States GAAP that requires the equity method of accounting for our investments with 50% or less ownership interest in which we do not have a controlling interest. Under Canadian GAAP, our share of each of the assets, liabilities, revenues and expenses of our investments that are subject to joint control is proportionately consolidated.
33
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
18. United States and Canadian accounting policy differences (Continued)
Condensed consolidated statement of operations
|
Three months ended September 30, |
Nine months ended September 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | 2010 | 2009 | ||||||||||
|
(Canadian GAAP) |
(Canadian GAAP) |
(Canadian GAAP) |
(Canadian GAAP) |
||||||||||
Project income (loss) |
||||||||||||||
Project revenue |
$ | 83,430 | $ | 70,518 | $ | 236,969 | $ | 216,170 | ||||||
Project expenses |
61,721 | 54,343 | 175,198 | 165,649 | ||||||||||
Project other (expenses) income |
(13,753 | ) | 48,064 | (69,209 | ) | 29,035 | ||||||||
|
7,956 | 64,239 | (7,438 | ) | 79,556 | |||||||||
Administration and other expenses, net |
4,549 | 21,755 | 20,211 | 56,426 | ||||||||||
Income (loss) from operations before income taxes |
3,407 | 42,484 | (27,649 | ) | 23,130 | |||||||||
Income tax expense (benefit) |
(868 | ) | 17,072 | (12,107 | ) | 8,935 | ||||||||
Income (loss) from continuing operations |
4,275 | 25,412 | (15,542 | ) | 14,195 | |||||||||
Less: Net loss attributable to noncontrolling interest |
(99 | ) | | (228 | ) | | ||||||||
Loss from discontinued operations, net of tax |
| (1,517 | ) | | (2,900 | ) | ||||||||
Net income (loss) attributable to Atlantic Power Corporation |
$ | 4,374 | $ | 23,895 | $ | (15,314 | ) | $ | 11,295 | |||||
Condensed consolidated statement of cash flows
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
2010 | 2009 | 2010 | 2009 | |||||||||
|
(Canadian GAAP) |
(Canadian GAAP) |
(Canadian GAAP) |
(Canadian GAAP) |
|||||||||
Cash provided by operating activities of continuing operations |
$ | 34,078 | $ | 19,770 | $ | 75,054 | $ | 51,160 | |||||
Cash provided by operating activities of discontinued operations |
| 138 | | 470 | |||||||||
|
34,078 | 19,908 | 75,054 | 51,630 | |||||||||
Cash used in investing activities of continuing operations |
(66,438 | ) | (12,723 | ) | (68,818 | ) | (12,067 | ) | |||||
Cash used in investing activities of discontinued operations |
| | | | |||||||||
|
(66,438 | ) | (12,723 | ) | (68,818 | ) | (12,067 | ) | |||||
Cash used in financing activities of continuing operations |
(21,639 | ) | (29,910 | ) | (48,013 | ) | (55,851 | ) | |||||
Cash used in financing activities of discontinued operations |
| (1,038 | ) | | (1,853 | ) | |||||||
|
(21,639 | ) | (30,948 | ) | (48,013 | ) | (57,704 | ) | |||||
Decrease in cash and cash equivalents |
(53,999 | ) | (23,763 | ) | (41,777 | ) | (18,141 | ) | |||||
Cash and cash equivalents, beginning of period |
66,725 | 48,188 | 54,503 | 42,566 | |||||||||
Cash and cash equivalents, end of period |
$ | 12,726 | $ | 24,425 | $ | 12,726 | $ | 24,425 | |||||
34
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.
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:
-
- expected opportunities for accretive acquisitions;
-
- the amount of distributions expected to be received from the projects for the full year 2010 and 2011;
-
- estimated net cash tax refund in 2010;
-
- our forecast of expected cash distributions from Idaho Wind, Piedmont and Cadillac for each full year of operations;
-
- our forecast of expected annual cash distributions from the Lake and Auburndale projects through 2012; and
-
- the expected resumption of distributions from our Chambers and Delta-Person projects in 2011 and the Selkirk project in 2012.
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 Securities and Exchange Commission. 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; and
-
- our limited control over the operation of certain minority-owned projects.
35
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.
OVERVIEW
Atlantic Power Corporation is an independent power producer, with power projects located in major markets in the United States. Our current portfolio consists of interests in 11 operational power generation projects across eight states, one wind project under construction in Idaho, one biomass project under construction in Georgia, a 500 kilovolt 84-mile electric transmission line located in California and a number of development projects. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,738 megawatts (or "MW"), in which our ownership interest is approximately 788 MW.
We sell the capacity and power 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 2010 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 most of the PPAs and steam sales agreements provide for the pass-through or indexing of fuel costs to our customers.
We partner with recognized leaders in the independent power industry to operate and maintain our projects, including Caithness Energy, LLC, Power Plant Management 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.
Atlantic Power Corporation is organized under the laws of the Province of British Columbia, Canada. Our registered office is located at 355 Burrard Street, Suite 1900, Vancouver, British Columbia V6C 2G8 and our headquarters are located at 200 Clarendon Street, Floor 25, Boston, Massachusetts, USA 02116. Our website is atlanticpower.com. Information contained on, or otherwise accessible through, our website is not incorporated into this Quarterly Report on Form 10-Q.
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.
36
As of November 10, 2010, we had 66,634,461 common shares, Cdn$59 million principal amount of 6.50% convertible secured debentures due October 31, 2014 (the "2006 Debentures"), Cdn$86.2 million principal amount of 6.25% convertible debentures due March 15, 2017 (the "2009 Debentures"), and Cdn$80.5 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 receive a monthly dividend at a current annual rate of Cdn$1.094 per common share.
On November 24, 2009, our shareholders approved our conversion from the previous Income Participating Security ("IPS") structure to a traditional common share structure. Each IPS was exchanged for one new common share and each old common share that did not form part of an IPS was exchanged for approximately 0.44 of a new common share. This transaction resulted in the extinguishment of Cdn$347,832 principal value of 11% Subordinated Notes due 2016 that previously formed a part of each IPS.
37
OUR POWER PROJECTS
The following table outlines our portfolio of power generating and transmission assets in operation and under construction as of November 10, 2010, including our interest in each facility. Management believes the portfolio is well diversified based on 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) |
Accounting Treatment(2) |
Net MW(3) |
Electricity Purchaser |
Power Contract Expiry |
Customer S&P Credit Rating |
|||||||||||||
|
||||||||||||||||||||||
Auburndale |
Florida | Natural Gas | 155 | 100.00 | % | C | 155 | Progress Energy Florida | 2013 | BBB+ | ||||||||||||
|
||||||||||||||||||||||
Lake |
Florida | Natural Gas | 121 | 100.00 | % | C | 121 | Progress Energy Florida | 2013 | BBB+ | ||||||||||||
|
||||||||||||||||||||||
Pasco |
Florida | Natural Gas | 121 | 100.00 | % | C | 121 | Tampa Electric Co. | 2018 | BBB | ||||||||||||
|
||||||||||||||||||||||
Chambers |
New Jersey | Coal | 262 | 40.00 | % | E | 89 | ACE(4) | 2024 | BBB+ | ||||||||||||
|
||||||||||||||||||||||
|
16 | DuPont | 2024 | A | ||||||||||||||||||
|
||||||||||||||||||||||
Path 15 |
California | Transmission | N/A | 100.00 | % | C | N/A | California Utilities via CAISO(5) | N/A | (6) | BBB+ to A(7) | |||||||||||
|
||||||||||||||||||||||
Orlando |
Florida | Natural Gas | 129 | 50.00 | % | E | 46 | Progress Energy Florida | 2023 | BBB+ | ||||||||||||
|
||||||||||||||||||||||
|
19 | Reedy Creek Improvement District | 2013 | (8) | A(9) | |||||||||||||||||
|
||||||||||||||||||||||
Selkirk |
New York | Natural Gas | 345 | 17.70 | %(10) | E | 15 | Merchant | N/A | N/R | ||||||||||||
|
||||||||||||||||||||||
|
49 | Consolidated Edison | 2014 | A- | ||||||||||||||||||
|
||||||||||||||||||||||
Gregory |
Texas | Natural Gas | 400 | 17.10 | % | E | 59 | Fortis Energy Marketing and Trading | 2013 | AA | ||||||||||||
|
||||||||||||||||||||||
|
9 | Sherwin Alumina | 2020 | NR | ||||||||||||||||||
|
||||||||||||||||||||||
Topsham(11) |
Maine | Hydro | 14 | 50.00 | % | E | 7 | Central Maine Power | 2011 | BBB+ | ||||||||||||
|
||||||||||||||||||||||
Badger Creek |
California | Natural Gas | 46 | 50.00 | % | E | 23 | Pacific Gas & Electric | 2011 | BBB+ | ||||||||||||
|
||||||||||||||||||||||
Koma Kulshan |
Washington | Hydro | 13 | 49.80 | % | E | 6 | Puget Sound Energy | 2037 | BBB | ||||||||||||
|
||||||||||||||||||||||
Delta-Person |
New Mexico | Natural Gas | 132 | 40.00 | % | E | 53 | PNM | 2020 | BB- | ||||||||||||
|
||||||||||||||||||||||
Idaho Wind(12) |
Idaho | Wind | 183 | 27.56 | % | E | 51 | Idaho Power Co. | 2030 | BBB | ||||||||||||
|
||||||||||||||||||||||
Piedmont(13) |
Georgia | Biomass | 54 | 100.00 | % | C | 51 | 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)
- Accounting Treatment: CConsolidated; and EEquity Method of Accounting
- (3)
- Represents our interest in each project's electric generation capacity based on our economic interest.
- (4)
- Includes separate power sales agreement in which the project and ACE share profits on spot sales of energy and capacity not purchased by ACE under the base PPA.
- (5)
- California utilities pay transmission access charges to CAISO, who then pays owners of TSRs, such as Path 15, in accordance with its FERC approved annual revenue requirement.
- (6)
- Path 15 is a FERC regulated asset with a FERC-approved regulatory life of 30 years: through 2034.
- (7)
- Largest payers of TACs supporting Path 15's annual revenue requirement are PG&E (BBB+), SoCal Ed (BBB+) and SDG&E (A). CAISO imposes minimum credit quality requirements for any participants of A or better unless collateral is posted per CAISO imposed schedule.
- (8)
- Upon the expiry of the Reedy Creek PPA, the associated capacity and energy will be sold to PEF.
- (9)
- Fitch rating on Reedy Creek Improvement District bonds.
- (10)
- 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.
- (11)
- We own our interest in this project as a lessor.
- (12)
- Project currently under construction and is expected to be completed in phases in late 2010 and 2011.
- (13)
- Project currently under construction and is expected to be completed in late 2012.
38
Recent Developments
On July 2, 2010, we acquired a 27.6% equity interest in Idaho Wind for approximately $38.9 million and approximately $3.0 million in transaction costs. Idaho Wind recently commenced construction of a 183 MW wind power project located near Twin Falls, Idaho, which is expected to be completed in phases in late 2010 and early 2011. Idaho Wind has 20-year PPAs with Idaho Power Company. Our investment in Idaho Wind was funded with cash on hand and a $20 million borrowing under our senior credit facility. Upon completion of construction, we expect Idaho Wind to provide after-tax cash flows to us of $4.5 million to $5.5 million for each full year of operations. During the third quarter of 2010, we made a short-term $12.8 million loan to Idaho Wind to provide temporary funding for construction of the project. A portion of the project-level construction financing was completed in early October 2010, resulting in $4.1 million of the loan repaid to us. The remaining $8.7 million is expected to be repaid in late 2010 and early 2011.
On October 8, 2010, Idaho Wind closed a $221.7 million project-level credit facility. The facility is composed of two tranches, which includes a $138.5 million construction loan that will convert to a 17-year term loan following commercial operation and a $83.2 million cash grant facility which will be repaid with federal stimulus grant proceeds after completion of construction. We own a 27.6% equity interest in Idaho Wind.
On October 18, 2010, we entered into natural gas swaps that are effective in 2014 and 2015. The natural gas swaps are related to expected fuel purchases attributable to our 50% share of the 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. 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. These natural gas swaps are derivative financial instruments and will be recorded in the consolidated balance sheets at fair value. Changes in the fair value of the natural gas swaps will be recorded in the statement of operations.
We expect cash distributions from Orlando to increase significantly following the expiration of the project's gas contract at the end of 2013 because projected natural gas prices at that time and the prices in the natural gas swaps we have executed are lower than the price of natural gas being purchased under the project's current gas contract.
On October 20, 2010, we completed a public offering of 6,029,000 common shares, including 784,000 common shares issued pursuant to the exercise in full of the underwriters' over-allotment option, at a price of $13.35 per common share. We received net proceeds from the common share offering, after deducting the underwriting discounts and expenses, of approximately $75.6 million.
On October 20, 2010, we also completed the closing of a public offering of Cdn$80.5 million aggregate principal amount of convertible unsecured subordinated debentures at a price of Cdn$1,000 per debenture, including Cdn$10.5 million aggregate principal amount of debentures pursuant to the exercise in full of the underwriters' over-allotment option. The debentures bear interest at a rate of 5.60%, and will mature on June 30, 2017, unless earlier redeemed. The debentures are convertible into our common shares at an initial conversion rate of 55.2486 common shares per Cdn$1,000 principal amount of debentures, representing an initial conversion price of approximately Cdn$18.10 per common share (equivalent to US$18.03 per common share). We received net proceeds from the debenture offering, after deducting the underwriting discounts and expenses, of approximately Cdn$76.4 million.
39
The net proceeds from the public offering of approximately $152 million are expected to be used as follows:
-
- $20 million to repay the outstanding borrowings on our revolving credit facility that was used to partially fund
the acquisition of Idaho Wind;
-
- Up to $75 million to fund our equity contribution to the Piedmont Green Power biomass project described below;
-
- Approximately $35 million to fund our expected acquisition of the Cadillac biomass plant described below; and
-
- Remaining net proceeds of approximately $22 million for general corporate purposes and continued execution of our growth strategy
On October 21, 2010, we closed a non-recourse, project-level bank financing for Piedmont, our first biomass power project. The terms of the financing include an $82 million construction and term loan and a $51 million bridge loan related to the stimulus grant to be received from the U.S. Treasury 60 days after the start of commercial operations, which is expected in late 2012. In addition, we will make an equity contribution of approximately $75 million for substantially all of the equity interests in Piedmont. The project has executed a swap that results in an average fixed interest rate of approximately 5.2% during the construction period and the first three years of the term loan. Cash distributions to us from the project are expected to average $8 million to $10 million for each full year of project operation. The project has a 20-year power purchase agreement under which capacity payments represent the majority of the revenues. In addition, the revenue and fuel supply contracts contain adjustment mechanisms that will mitigate potential biomass fuel price volatility.
On October 22, 2010, we entered into a purchase and sale agreement to acquire 100% of the membership interests of Cadillac Renewable Energy, LLC, a 39.6 MW wood fired facility located in Cadillac, Michigan from a joint venture which is jointly owned by ArcLight Energy Partners Fund II and Olympus Power, LLC. The purchase price will be approximately $77 million, subject to customary working capital adjustments, and will be funded by $35 million cash on hand and $42 million of assumed non-recourse, project-level debt. Operations and maintenance will be managed by our majority-owned subsidiary Rollcast Energy. The acquisition is anticipated to close by the end of 2010. We expect to receive distributions from the project in the range of $3.5 million to $4.5 million per year beginning in 2011.
Critical Accounting Policies and Estimates
Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of generally accepted accounting principles involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining fair
40
values of acquired assets, the useful lives and recoverability of property, plant and equipment and PPAs, the recoverability of equity investments, the recoverability of deferred tax assets, the fair value of notional units granted under the terms of the Long-Term incentive plan, and the fair value of derivatives.
For a summary of our significant accounting policies, see Note 2 to our interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed as follows.
Impairment of long-lived assets and equity investments
Long-lived assets, which include property, plant and equipment, transmission system rights and other intangible assets subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the probability weighting of different courses of action available. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes. We also consider quoted market prices in active markets to the extent they are available. In the absence of such information, we may consider prices of similar assets, consult with brokers or employ other valuation techniques. We use our best estimates in making these evaluations. However, actual results could vary from the assumptions used in our estimates and the impact of such variations could be material.
Investments in and the operating results of 50%-or-less owned entities not required to be consolidated are included in the consolidated financial statements on the basis of the equity method of accounting. We review our investments in unconsolidated entities for impairment whenever events or changes in business circumstances indicate that the carrying amount of the investments may not be fully recoverable. Evidence of a loss in value that is other than temporary might include the absence of an ability to recover the carrying amount of the investment, the inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment, failure of cash flow coverage ratio tests included in project-level, non-recourse debt or, where applicable, estimated sales proceeds which are insufficient to recover the carrying amount of the investment. Our assessment as to whether any decline in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of the investment is recoverable within a reasonable period of time outweighs evidence to the contrary.
When we determine that an impairment test is required, the future projected cash flows from the equity investment are the most significant factor in determining whether impairment exists and, if so, the amount of the impairment charges. We use our best estimates of market prices of power and fuel and our knowledge of the operations of the project and our related contracts when developing these cash flow estimates. In addition, when determining fair value using discounted cash flows, the discount rate used can have a material impact on the fair value determination. Discount rates are based on our risk of the cash flows in the estimate, including when applicable, the credit risk of the counterparty that is contractually obligated to purchase electricity or steam from the project.
We generally consider our investments in our equity method investees to be strategic long-term investments that comprise a significant portion of our core operating business. Therefore, we complete our assessments with a long-term view. If the fair value of the investment is determined to be less than the carrying value and the decline in value is considered to be other than temporary, an appropriate
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write-down is recorded based on the excess of the carrying value over the best estimate of fair value of the investment. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in our estimates and the impact of such variations could be material.
Fair Value of Derivatives
We utilize derivative contracts to mitigate our exposure to fluctuations in fuel commodity prices, foreign currency and to balance our exposure to variable interest rates. We believe that these derivatives are generally effective in realizing these objectives.
In determining fair value for our derivative assets and liabilities, we generally use the market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk and/or the risks inherent in the inputs to the valuation techniques.
A fair value hierarchy exists for inputs used in measuring fair value that maximizes the use of observable inputs (Level 1 or Level 2) and minimizes the use of unobservable inputs (Level 3) by requiring that the observable inputs be used when available. Our derivative instruments are classified as Level 2. The fair value measurements of these derivative assets and liabilities are based largely on quoted prices from independent brokers in active markets who regularly facilitate our transactions. An active market is considered to have transactions with sufficient frequency and volume to provide pricing information on an ongoing basis.
Derivative assets are discounted for credit risk using credit spreads representative of the counterparty's probability of default. For derivative liabilities, fair value measurement reflects the nonperformance risk related to that liability, which is our own credit risk. We derive our nonperformance risk by applying credit spreads approximating our estimate of corporate credit rating against the respective derivative liability.
Certain derivative instruments qualify for a scope exception to fair value accounting, as they are considered normal purchases or normal sales. The availability of this exception is based upon the assumption that we have the ability and it is probable to deliver or take delivery of the underlying physical commodity. Derivatives that are considered to be normal purchases and normal sales are exempt from derivative accounting treatment and are recorded as executory contracts.
Income Taxes and Valuation Allowance for Deferred Tax Assets
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. The valuation allowance is comprised primarily of provisions against available Canadian and U.S. net operating loss carryforwards.
Long-term incentive plan
The officers and other employees of Atlantic Power are eligible to participate in the LTIP that was implemented in 2007. In the second quarter of 2010, the board of directors approved an amendment to the LTIP and the amended plan was approved by our shareholders on June 29, 2010. The amended LTIP will be effective for grants beginning with the 2010 performance year. Under the amended LTIP, the notional units granted to plan participants will have the same characteristics as notional units under the old LTIP. However, the number of notional units that vest will be based, in part, on the total shareholder return of Atlantic Power compared to a group of peer companies in Canada. In addition,
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vesting of the notional units for officers of Atlantic Power will occur on a three-year cliff basis as opposed to ratable vesting over three years for grants made prior to the amendments.
Unvested notional units are entitled to receive dividends equal to the dividends per common share during the vesting period in the form of additional notional units. Unvested units are subject to forfeiture if the participant is not an employee at the vesting date or if we do not meet certain ongoing cash flow performance targets.
Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the estimated fair value of the award on the grant date for notional units accounted for as equity awards and the fair value of the award at each balance sheet date for notional units accounted for as liability awards. Fair value of the awards granted prior to the 2010 amendment is determined by projecting the total number of notional units that will vest in future periods, including dividends received on notional units during the vesting period, and applying the current market price per share to the projected number of notional units that will vest. The fair value of awards granted for the 2010 performance period with market vesting conditions is based upon a Monte Carlo simulation model on their grant date. The aggregate number of shares which may be issued from treasury under the amended LTIP is limited to one million. Unvested notional units are recorded as either a liability or equity award based on management's intended method of redeeming the notional units when they vest.
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Results of Operations
The following table and discussion is a summary of our consolidated results of operations for the three and nine month periods ended September 30, 2010 and 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
|
Three months ended September 30, |
Nine months ended September 30, |
||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(Unaudited) (in thousands of U.S. dollars, except as otherwise stated) |
2010 | 2009 | 2010 | 2009 | ||||||||||
Project revenue |
||||||||||||||
Auburndale |
$ | 19,373 | $ | 18,124 | $ | 59,410 | $ | 56,113 | ||||||
Lake |
23,721 | 15,957 | 57,804 | 47,061 | ||||||||||
Pasco |
3,132 | 2,984 | 8,764 | 8,779 | ||||||||||
Path 15 |
7,813 | 7,792 | 23,186 | 23,208 | ||||||||||
|
54,039 | 44,857 | 149,164 | 135,161 | ||||||||||
Project expenses |
||||||||||||||
Auburndale |
14,304 | 13,366 | 44,437 | 42,690 | ||||||||||
Lake |
16,671 | 13,093 | 40,678 | 34,142 | ||||||||||
Pasco |
2,548 | 3,484 | 7,255 | 7,903 | ||||||||||
Path 15 |
2,901 | 2,826 | 8,438 | 8,720 | ||||||||||
Other Project Assets |
182 | (176 | ) | 270 | (339 | ) | ||||||||
|
36,606 | 32,593 | 101,078 | 93,116 | ||||||||||
Project other income (expense) |
||||||||||||||
Auburndale |
(4,714 | ) | (830 | ) | (10,409 | ) | (2,144 | ) | ||||||
Lake |
(4,621 | ) | 793 | (10,841 | ) | 737 | ||||||||
Pasco |
22 | | 22 | 67 | ||||||||||
Path 15 |
(2,762 | ) | (3,220 | ) | (9,004 | ) | (8,435 | ) | ||||||
Chambers |
1,331 | 782 | 6,268 | 1,564 | ||||||||||
Other Project Assets |
945 | (5,345 | ) | 2,917 | (3,395 | ) | ||||||||
|
(9,799 | ) | (7,820 | ) | (21,047 | ) | (11,606 | ) | ||||||
Total project income |
||||||||||||||
Auburndale |
355 | 3,928 | 4,564 | 11,279 | ||||||||||
Lake |
2,429 | 3,657 | 6,285 | 13,656 | ||||||||||
Pasco |
606 | (500 | ) | 1,531 | 943 | |||||||||
Path 15 |
2,150 | 1,746 | 5,744 | 6,053 | ||||||||||
Chambers |
1,331 | 782 | 6,268 | 1,564 | ||||||||||
Other Project Assets |
763 | (5,169 | ) | 2,647 | (3,056 | ) | ||||||||
|
7,634 | 4,444 | 27,039 | 30,439 | ||||||||||
Administrative and other expenses |
||||||||||||||
Management fees and administration |
4,103 | 2,907 | 12,046 | 8,391 | ||||||||||
Interest, net |
2,707 | 11,285 | 8,019 | 31,455 | ||||||||||
Foreign exchange loss (gain) |
(2,253 | ) | 12,528 | 179 | 22,034 | |||||||||
Other income, net |
| (18 | ) | (26 | ) | (48 | ) | |||||||
Total administrative and other expenses |
4,557 | 26,702 | 20,218 | 61,832 | ||||||||||
Income (loss) from operations before income taxes |
3,077 | (22,258 | ) | 6,821 | (31,393 | ) | ||||||||
Income tax expense (benefit) |
3,614 | (6,455 | ) | 12,105 | (9,104 | ) | ||||||||
Net (loss) income |
(537 | ) | (15,803 | ) | (5,284 | ) | (22,289 | ) | ||||||
Net loss attributable to noncontrolling interest |
(99 | ) | | (228 | ) | | ||||||||
Net loss attributable to Atlantic Power Corporation shareholders |
$ | (438 | ) | $ | (15,803 | ) | $ | (5,056 | ) | $ | (22,289 | ) | ||
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