ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
ATLANTIC POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands of U.S. dollars)
|
|
|
|
|
|
|
|
|
|
September 30,
2012
|
|
December 31,
2011
|
|
|
|
(unaudited)
|
|
|
|
Assets
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
42,872
|
|
$
|
60,651
|
|
Restricted cash
|
|
|
112,633
|
|
|
21,412
|
|
Accounts receivable
|
|
|
80,190
|
|
|
79,008
|
|
Current portion of derivative instruments asset (Notes 6 and 7)
|
|
|
10,792
|
|
|
10,411
|
|
Inventory
|
|
|
20,105
|
|
|
18,628
|
|
Prepayments and other current assets
|
|
|
27,751
|
|
|
7,615
|
|
Assets held for sale (Note 11)
|
|
|
203,111
|
|
|
|
|
Refundable income taxes
|
|
|
3,646
|
|
|
3,042
|
|
|
|
|
|
|
|
Total current assets
|
|
|
501,100
|
|
|
200,767
|
|
Property, plant, and equipment, net of accumulated depreciation of $168.4 million and $116.3 million at September 30, 2012
and December 31, 2011, respectively
|
|
|
1,730,765
|
|
|
1,388,254
|
|
Transmission system rights, net of accumulated amortization of $51.4 million at December 31, 2011
|
|
|
|
|
|
180,282
|
|
Equity investments in unconsolidated affiliates (Note 3)
|
|
|
432,525
|
|
|
474,351
|
|
Other intangible assets, net of accumulated amortization of $155.0 million and $90.2 million at September 30, 2012 and December 31,
2011, respectively
|
|
|
557,356
|
|
|
584,274
|
|
Goodwill
|
|
|
334,668
|
|
|
343,586
|
|
Derivative instruments asset (Notes 6 and 7)
|
|
|
14,236
|
|
|
22,003
|
|
Other assets
|
|
|
73,345
|
|
|
54,910
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,643,995
|
|
$
|
3,248,427
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
13,997
|
|
$
|
18,122
|
|
Accrued interest
|
|
|
29,453
|
|
|
19,916
|
|
Other accrued liabilities
|
|
|
82,690
|
|
|
43,968
|
|
Revolving credit facility (Note 4)
|
|
|
20,000
|
|
|
58,000
|
|
Current portion of long-term debt (Note 4)
|
|
|
303,890
|
|
|
20,958
|
|
Current portion of derivative instruments liability (Notes 6 and 7)
|
|
|
42,440
|
|
|
20,592
|
|
Dividends payable
|
|
|
11,627
|
|
|
10,733
|
|
Liabilities associated with assets held for sale (Note 11)
|
|
|
157,420
|
|
|
|
|
Other current liabilities
|
|
|
4,014
|
|
|
165
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
665,531
|
|
|
192,454
|
|
Long-term debt (Note 4)
|
|
|
1,225,661
|
|
|
1,404,900
|
|
Convertible debentures (Note 5)
|
|
|
326,067
|
|
|
189,563
|
|
Derivative instruments liability (Notes 6 and 7)
|
|
|
103,411
|
|
|
33,170
|
|
Deferred income taxes
|
|
|
161,266
|
|
|
182,925
|
|
Power purchase and fuel supply agreement liabilities, net of accumulated amortization of $3.5 million and $1.4 million at September 30, 2012
and December 31, 2011, respectively
|
|
|
45,265
|
|
|
71,775
|
|
Other non-current liabilities
|
|
|
63,996
|
|
|
57,859
|
|
Commitments and contingencies (Note 14)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
2,591,197
|
|
|
2,132,646
|
|
Equity
|
|
|
|
|
|
|
|
Common shares, no par value, unlimited authorized shares; 119,294,718 and 113,526,182 issued and outstanding at September 30, 2012 and
December 31, 2011, respectively
|
|
|
1,286,399
|
|
|
1,217,265
|
|
Preferred shares issued by a subsidiary company
|
|
|
221,304
|
|
|
221,304
|
|
Accumulated other comprehensiveincome (loss)
|
|
|
17,253
|
|
|
(5,193
|
)
|
Retained deficit
|
|
|
(474,489
|
)
|
|
(320,622
|
)
|
|
|
|
|
|
|
Total Atlantic Power Corporation shareholders' equity
|
|
|
1,050,467
|
|
|
1,112,754
|
|
Noncontrolling interest
|
|
|
2,331
|
|
|
3,027
|
|
|
|
|
|
|
|
Total equity
|
|
|
1,052,798
|
|
|
1,115,781
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
3,643,995
|
|
$
|
3,248,427
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
4
Table of Contents
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,
|
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
Project revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy sales
|
|
$
|
72,033
|
|
$
|
17,104
|
|
$
|
218,883
|
|
$
|
53,471
|
|
Energy capacity revenue
|
|
|
68,354
|
|
|
27,070
|
|
|
193,911
|
|
|
81,859
|
|
Other
|
|
|
14,112
|
|
|
521
|
|
|
51,036
|
|
|
1,153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
154,499
|
|
|
44,695
|
|
|
463,830
|
|
|
136,483
|
|
Project expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
58,565
|
|
|
14,818
|
|
|
176,176
|
|
|
46,202
|
|
Operations and maintenance
|
|
|
35,848
|
|
|
8,124
|
|
|
111,027
|
|
|
25,618
|
|
Depreciation and amortization
|
|
|
38,542
|
|
|
8,880
|
|
|
111,219
|
|
|
26,705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
132,955
|
|
|
31,822
|
|
|
398,422
|
|
|
98,525
|
|
Project other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivative instruments (Notes 6 and 7)
|
|
|
17,213
|
|
|
(11,484
|
)
|
|
(40,953
|
)
|
|
(12,497
|
)
|
Equity in earnings of unconsolidated affiliates (Note 3)
|
|
|
4,000
|
|
|
2,374
|
|
|
12,420
|
|
|
5,647
|
|
Interest expense, net
|
|
|
(4,211
|
)
|
|
(1,576
|
)
|
|
(12,637
|
)
|
|
(4,832
|
)
|
Other expense, net
|
|
|
(567
|
)
|
|
(7
|
)
|
|
(538
|
)
|
|
(40
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,435
|
|
|
(10,693
|
)
|
|
(41,708
|
)
|
|
(11,722
|
)
|
|
|
|
|
|
|
|
|
|
|
Project income
|
|
|
37,979
|
|
|
2,180
|
|
|
23,700
|
|
|
26,236
|
|
Administrative and other expenses (income):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Administration
|
|
|
6,309
|
|
|
11,839
|
|
|
21,992
|
|
|
20,379
|
|
Interest, net
|
|
|
25,829
|
|
|
3,337
|
|
|
69,269
|
|
|
10,815
|
|
Foreign exchange loss (Note 7)
|
|
|
7,659
|
|
|
21,576
|
|
|
4,440
|
|
|
20,383
|
|
Other expense (income), net
|
|
|
272
|
|
|
|
|
|
(5,728
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,069
|
|
|
36,752
|
|
|
89,973
|
|
|
51,577
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations before income taxes
|
|
|
(2,090
|
)
|
|
(34,572
|
)
|
|
(66,273
|
)
|
|
(25,341
|
)
|
Income tax expense (benefit) (Note 8)
|
|
|
3,166
|
|
|
(5,323
|
)
|
|
(19,076
|
)
|
|
(12,900
|
)
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
|
|
|
(5,256
|
)
|
|
(29,249
|
)
|
|
(47,197
|
)
|
|
(12,441
|
)
|
Income from discontinued operations, net of tax (Note 11)
|
|
|
773
|
|
|
1,271
|
|
|
1,444
|
|
|
3,514
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
(4,483
|
)
|
|
(27,978
|
)
|
|
(45,753
|
)
|
|
(8,927
|
)
|
Net income (loss) attributable to noncontrolling interest
|
|
|
2,963
|
|
|
(78
|
)
|
|
9,071
|
|
|
(349
|
)
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to Atlantic Power Corporation
|
|
$
|
(7,446
|
)
|
$
|
(27,900
|
)
|
$
|
(54,824
|
)
|
$
|
(8,578
|
)
|
|
|
|
|
|
|
|
|
|
|
Net loss per share attributable to Atlantic Power Corporation shareholders: (Note 10)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.06
|
)
|
$
|
(0.40
|
)
|
$
|
(0.47
|
)
|
$
|
(0.13
|
)
|
Diluted
|
|
$
|
(0.06
|
)
|
$
|
(0.40
|
)
|
$
|
(0.47
|
)
|
$
|
(0.13
|
)
|
Weighted average number of common shares outstanding: (Note 10)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
119,011
|
|
|
68,910
|
|
|
115,437
|
|
|
68,384
|
|
Diluted
|
|
|
119,011
|
|
|
68,910
|
|
|
115,437
|
|
|
68,384
|
|
See accompanying notes to consolidated financial statements.
5
Table of Contents
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands of U.S. dollars)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
Net loss
|
|
$
|
(4,483
|
)
|
$
|
(27,978
|
)
|
$
|
(45,753
|
)
|
$
|
(8,927
|
)
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on hedging activities
|
|
|
(300
|
)
|
|
(1,495
|
)
|
|
(833
|
)
|
|
(2,257
|
)
|
Net amount reclassified to earnings
|
|
|
216
|
|
|
253
|
|
|
672
|
|
|
784
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses on derivatives
|
|
|
(84
|
)
|
|
(1,242
|
)
|
|
(161
|
)
|
|
(1,473
|
)
|
Foreign currency translation adjustments
|
|
|
19,301
|
|
|
|
|
|
22,608
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income, net of tax
|
|
|
19,217
|
|
|
(1,242
|
)
|
|
22,447
|
|
|
(1,473
|
)
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
|
14,734
|
|
|
(29,220
|
)
|
|
(23,306
|
)
|
|
(10,400
|
)
|
|
|
|
|
|
|
|
|
|
|
Less: Comprehensive (income) loss attributable to noncontrolling interest
|
|
|
2,963
|
|
|
(78
|
)
|
|
9,071
|
|
|
(349
|
)
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) attributable to Atlantic Power Corporation
|
|
$
|
11,771
|
|
$
|
(29,142
|
)
|
$
|
(32,377
|
)
|
$
|
(10,051
|
)
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
6
Table of Contents
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands of U.S. dollars)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
Nine months ended
September 30,
|
|
|
|
2012
|
|
2011
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(45,753
|
)
|
$
|
(8,927
|
)
|
Adjustments to reconcile to net cash provided by operating activities:
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
117,464
|
|
|
32,711
|
|
Long-term incentive plan expense
|
|
|
2,344
|
|
|
2,257
|
|
Loss on the disposal of property, plant and equipment and other charges
|
|
|
840
|
|
|
|
|
Impairment charge on equity investment
|
|
|
3,000
|
|
|
|
|
Gain on sale of equity investments
|
|
|
(578
|
)
|
|
|
|
Equity in earnings from unconsolidated affiliates
|
|
|
(14,842
|
)
|
|
(5,647
|
)
|
Distributions from unconsolidated affiliates
|
|
|
26,821
|
|
|
15,542
|
|
Unrealized foreign exchange loss
|
|
|
21,552
|
|
|
28,175
|
|
Change in fair value of derivative instruments
|
|
|
40,953
|
|
|
12,497
|
|
Change in deferred income taxes
|
|
|
(24,278
|
)
|
|
(10,315
|
)
|
Change in other operating balances
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(2,873
|
)
|
|
258
|
|
Prepayments, refundable income taxes and other assets
|
|
|
(18,656
|
)
|
|
(570
|
)
|
Accounts payable and accrued liabilities
|
|
|
14,855
|
|
|
1,536
|
|
Other liabilities
|
|
|
3,267
|
|
|
(1,178
|
)
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
124,116
|
|
|
66,339
|
|
Cash flows used in investing activities:
|
|
|
|
|
|
|
|
Change in restricted cash
|
|
|
(105,494
|
)
|
|
(12,379
|
)
|
Proceeds from sale of equity investments
|
|
|
27,925
|
|
|
8,500
|
|
Cash paid for equity investment
|
|
|
(264
|
)
|
|
|
|
Proceeds from related party loan
|
|
|
|
|
|
15,455
|
|
Biomass development costs
|
|
|
(372
|
)
|
|
(753
|
)
|
Construction in progress
|
|
|
(336,153
|
)
|
|
(78,256
|
)
|
Purchase of property, plant and equipment
|
|
|
(1,172
|
)
|
|
(814
|
)
|
|
|
|
|
|
|
Cash used in investing activities
|
|
|
(415,530
|
)
|
|
(68,247
|
)
|
Cash flows provided by (used in) financing activities:
|
|
|
|
|
|
|
|
Proceeds from issuance of convertible debentures
|
|
|
130,000
|
|
|
|
|
Proceeds from issuance of equity, net of offering costs
|
|
|
67,692
|
|
|
|
|
Proceeds from project-level debt
|
|
|
261,226
|
|
|
65,374
|
|
Repayment of project-level debt
|
|
|
(12,050
|
)
|
|
(13,166
|
)
|
Payments for revolving credit facility borrowings
|
|
|
(60,800
|
)
|
|
|
|
Proceeds from revolving credit facility borrowings
|
|
|
22,800
|
|
|
|
|
Deferred financing costs
|
|
|
(25,339
|
)
|
|
|
|
Dividends paid
|
|
|
(108,152
|
)
|
|
(57,543
|
)
|
|
|
|
|
|
|
Cash provided by (used in) financing activities
|
|
|
275,377
|
|
|
(5,335
|
)
|
Net decrease in cash and cash equivalents
|
|
|
(16,037
|
)
|
|
(7,243
|
)
|
Less cash at discontinued operations
|
|
|
(1,742
|
)
|
|
|
|
Cash and cash equivalents at beginning of period
|
|
|
60,651
|
|
|
45,497
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
42,872
|
|
$
|
38,254
|
|
|
|
|
|
|
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
77,738
|
|
$
|
21,567
|
|
Income taxes paid (refunded), net
|
|
$
|
3,145
|
|
$
|
(352
|
)
|
Accruals for construction in progress
|
|
$
|
40,097
|
|
$
|
19,547
|
|
See accompanying notes to consolidated financial statements.
7
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Basis of presentation and summary of significant accounting policies
Overview
Atlantic Power Corporation is a power generation and infrastructure company with a portfolio of assets in the United States and Canada.
Our power generation projects sell electricity to utilities and other large commercial customers under long-term power purchase agreements ("PPAs"), which seek to minimize exposure to
changes in commodity prices. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 3,351 megawatts ("MW") in which our ownership interest is
approximately 2,118 MW. Our current portfolio consists of interests in 30 operational power generation projects across 11 states in the United States and two provinces in Canada and an 84 mile
500-kilovolt electric transmission line located in California. In addition, we have one 53 MW biomass project under construction in Georgia and one approximately 300 MW wind project under
construction in Oklahoma.
Atlantic Power also owns a majority interest in Rollcast Energy, a biomass power plant developer in North Carolina. Twenty-three of our projects are wholly owned subsidiaries.
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 on July 8,
2005. Our shares trade on the Toronto Stock Exchange under the symbol "ATP" and on the New York Stock Exchange under the symbol "AT." Our registered office is located at 355 Burrard Street,
Suite 1900, Vancouver, British Columbia V6C 2G8 Canada and our headquarters is located at One Federal Street, Floor 30, Boston, Massachusetts, 02110, USA. Our telephone number in Boston
is (617) 977-2400 and the address of our website is www.atlanticpower.com. Information contained on Atlantic Power's website or that can be accessed through its website is not
incorporated into and does not constitute a part of this Quarterly Report on Form 10-Q. Atlantic Power has included its website address only as an inactive textual reference and
does not intend it to be an active link to its website. We make available, free of charge, on our website our Annual Report on Form 10-K, Quarterly Reports on
Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange
Act of 1934, as amended (the "Exchange Act"), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission ("SEC").
Additionally, we make available on our website our Canadian securities filings, which are not incorporated by reference into our Exchange Act filings.
The
interim consolidated financial statements have been prepared in accordance with the SEC regulations for interim financial information and with the instructions to
Form 10-Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our financial statements in our Annual
Report on Form 10-K for the year ended December 31, 2011. Interim results are not necessarily indicative of results for the full year.
In
our opinion, the accompanying unaudited interim consolidated financial statements present fairly our consolidated financial position as of September 30, 2012, the results of
operations and comprehensive income for the three and nine month periods ended September 30, 2012 and 2011, and our cash flows for the nine month periods ended September 30, 2012 and
2011. In the opinion of management, all adjustments (consisting of normal recurring accruals and other adjustments) considered necessary for a fair presentation have been included.
8
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
1. Basis of presentation and summary of significant accounting policies (Continued)
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, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax
provisions, the valuation of shares associated with our Long-Term Incentive Plan ("LTIP") 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. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of
OperationsCritical Accounting Policies and Estimates" in our Annual Report on Form 10-K for the year ended December 31, 2011. 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.
Recently issued accounting standards
Adopted
On January 1, 2012, we adopted changes issued by the Financial Accounting Standards Board ("FASB") to conform existing guidance
regarding fair value measurement and disclosure between GAAP and International Financial Reporting Standards. These changes both clarify the FASB's intent about the application of existing fair value
measurement and disclosure requirements and amend certain principles or requirements for measuring fair value or for disclosing information about fair value measurements. The clarifying changes relate
to the application of the highest and best use and valuation premise concepts, measuring the fair value of an instrument classified in a reporting entity's shareholders' equity, and disclosure of
quantitative information about unobservable inputs used for Level 3 fair value measurements. The amendments relate to measuring the fair value of financial instruments that are managed within a
portfolio; application of premiums and discounts in a fair value measurement; and additional disclosures concerning the valuation processes used and sensitivity of the fair value measurement to
changes in unobservable inputs for those items
categorized as Level 3, a reporting entity's use of a nonfinancial asset in a way that differs from the asset's highest and best use, and the categorization by level in the fair value hierarchy
for items required to be measured at fair value for disclosure purposes only. The adoption of these changes had no impact on our consolidated financial statements.
On
January 1, 2012, we adopted changes issued by the FASB to the presentation of comprehensive income. These changes give an entity the option to present the total of
comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive
statements; the option to present components of other comprehensive income as part of the statement of changes in
9
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
1. Basis of presentation and summary of significant accounting policies (Continued)
shareholders'
equity was eliminated. The items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income were not changed.
Additionally, no changes were made to the calculation and presentation of earnings per share. We elected to present the two-statement option. Other than the change in presentation, the
adoption of these changes had no impact on our consolidated financial statements.
Issued
In July 2012, the FASB issued changes to the testing of indefinite-lived intangible assets for impairment, similar to the goodwill
changes issued in September 2011. These changes provide an entity the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination
that it is more likely than not (more than 50%) that the fair value of an indefinite-lived intangible asset is less than its carrying amount. Such qualitative factors may include the following:
macroeconomic conditions; industry and market considerations; cost factors; overall financial performance; and other relevant entity-specific events. If an entity elects to perform a qualitative
assessment and determines that an impairment is more likely than not, the entity is then required to perform the existing two-step quantitative impairment test, otherwise no further
analysis is required. An entity also may elect not to perform the qualitative assessment and, instead, proceed directly to the two-step quantitative impairment test. These changes become
effective for us for any indefinite-lived intangible asset impairment test performed on January 1, 2013 or later, although early adoption is permitted. We do not expect the adoption of these
changes to have an impact on our consolidated financial statements.
2. Acquisitions and divestitures
2012 Acquisitions
On January 31, 2012, Atlantic Oklahoma Wind, LLC ("Atlantic OW"), a Delaware limited liability company and our wholly
owned subsidiary, entered into a purchase and sale agreement with Apex Wind Energy Holdings, LLC, a Delaware limited liability company ("Apex"), pursuant to which Atlantic OW acquired a 51%
interest in Canadian Hills Wind, LLC, an Oklahoma limited liability company ("Canadian Hills") for a nominal sum. Canadian Hills is the owner of a 298.45 MW wind energy project under
construction in the state of Oklahoma.
On
March 30, 2012, we completed the purchase of an additional 48% interest in Canadian Hills for a nominal amount, bringing our total interest in the project to 99%. Apex retained
a 1% interest in the project. At the time, we also closed a $310 million non-recourse, project-level construction financing facility for the project, which includes a
$290 million construction loan and a $20 million 5-year letter of credit facility. The construction loan is structured to be repaid by a tax equity investment when Canadian
Hills commences commercial operations.
On
October 31, 2012, the Canadian Hills project entered into an equity contribution agreement with four entities for their commitment of a tax equity investment in the project totalling
$225.0 million in exchange for Class B equity interests in Canadian Hills which will be funded on date of commercial operations. We are actively pursuing additional tax equity investors
to fund the remaining estimated $47.0 million needed to pay down the existing construction loan. If we are unable to subscribe
10
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
2. Acquisitions and divestitures (Continued)
additional
investors, we will fund the remaining portion with either cash on hand or proceeds from our senior credit facility and will become an additional tax equity investor in the project owning
the remaining Class B equity interest in Canadian Hills. In July 2012 we funded approximately $190.0 million of our equity contribution (net of financing costs). The acquisition of
Canadian Hills was accounted for as an asset purchase and is consolidated in our consolidated balance sheet at September 30, 2012.
2012 Divestitures
On August 2, 2012, we entered into a purchase and sale agreement for the sale of our 50% ownership interest in the Badger Creek
project. On September 4, 2012, the transaction closed and we received gross proceeds of $3.7 million. As a result of the pending sale, we recorded an impairment charge in the second
quarter of 2012 of $3.0 million in equity in earnings from unconsolidated affiliates in the consolidated statements of operations.
On
February 16, 2012, we entered into an agreement with Primary Energy Recycling Corporation ("Primary Energy" or "PERC"), whereby PERC agreed to purchase our 7,462,830.33 common
membership interests in Primary Energy Recycling Holdings, LLC ("PERH") (14.3% of PERH total interests) for approximately $24.2 million, plus a management agreement termination fee of
approximately $6.0 million, for a total sale price of $30.2 million. The transaction closed in May 2012 and we recorded a $0.6 million gain on sale of our equity investment.
2011 Divestiture
On February 28, 2011, we entered into a purchase and sale agreement with a third party for the purchase of our lessor interest
in the Topsham project. The transaction closed on May 6, 2011 and we received proceeds of $8.5 million. No gain or loss was recorded on the sale.
11
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
3. Equity method investments
The following summarizes the operating results for the three and nine months ended September 30, 2012 and 2011, respectively, for earnings in our equity method investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
Project revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chambers
|
|
$
|
12,196
|
|
$
|
11,616
|
|
$
|
40,148
|
|
$
|
37,894
|
|
Badger Creek
|
|
|
1,087
|
|
|
1,415
|
|
|
3,357
|
|
|
6,070
|
|
Gregory
|
|
|
5,814
|
|
|
7,810
|
|
|
14,766
|
|
|
22,624
|
|
Orlando
|
|
|
11,081
|
|
|
10,549
|
|
|
32,850
|
|
|
29,851
|
|
Selkirk
|
|
|
12,248
|
|
|
14,020
|
|
|
35,857
|
|
|
37,881
|
|
Other
|
|
|
9,218
|
|
|
3,093
|
|
|
31,522
|
|
|
8,045
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51,644
|
|
|
48,503
|
|
|
158,500
|
|
|
142,365
|
|
Project expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chambers
|
|
|
9,564
|
|
|
9,107
|
|
|
28,066
|
|
|
28,032
|
|
Badger Creek
|
|
|
831
|
|
|
1,509
|
|
|
2,971
|
|
|
5,907
|
|
Gregory
|
|
|
5,262
|
|
|
7,007
|
|
|
15,392
|
|
|
20,537
|
|
Orlando
|
|
|
10,189
|
|
|
10,156
|
|
|
30,487
|
|
|
29,224
|
|
Selkirk
|
|
|
10,663
|
|
|
12,572
|
|
|
31,722
|
|
|
37,861
|
|
Other
|
|
|
11,585
|
|
|
2,617
|
|
|
30,223
|
|
|
6,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48,094
|
|
|
42,968
|
|
|
138,861
|
|
|
127,973
|
|
Project other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chambers
|
|
|
139
|
|
|
(730
|
)
|
|
(1,476
|
)
|
|
(1,820
|
)
|
Badger Creek
|
|
|
(156
|
)
|
|
(9
|
)
|
|
(3,165
|
)
|
|
(20
|
)
|
Gregory
|
|
|
(46
|
)
|
|
(218
|
)
|
|
(272
|
)
|
|
(449
|
)
|
Orlando
|
|
|
(24
|
)
|
|
(13
|
)
|
|
(58
|
)
|
|
(57
|
)
|
Selkirk
|
|
|
(671
|
)
|
|
(33
|
)
|
|
1,516
|
|
|
(2,599
|
)
|
Other
|
|
|
1,208
|
|
|
(2,158
|
)
|
|
(3,764
|
)
|
|
(3,800
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
450
|
|
|
(3,161
|
)
|
|
(7,219
|
)
|
|
(8,745
|
)
|
Project income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chambers
|
|
|
2,771
|
|
|
1,779
|
|
|
10,606
|
|
|
8,042
|
|
Badger Creek
|
|
|
100
|
|
|
(103
|
)
|
|
(2,779
|
)
|
|
143
|
|
Gregory
|
|
|
506
|
|
|
585
|
|
|
(898
|
)
|
|
1,638
|
|
Orlando
|
|
|
868
|
|
|
380
|
|
|
2,305
|
|
|
570
|
|
Selkirk
|
|
|
914
|
|
|
1,415
|
|
|
5,651
|
|
|
(2,579
|
)
|
Other
|
|
|
(1,159
|
)
|
|
(1,682
|
)
|
|
(2,465
|
)
|
|
(2,167
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,000
|
|
|
2,374
|
|
|
12,420
|
|
|
5,647
|
|
12
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
4. Long-term debt
Long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
September 30,
2012
|
|
December 31,
2011
|
|
Interest Rate
|
Recourse Debt:
|
|
|
|
|
|
|
|
|
Senior unsecured notes, due 2018
|
|
$
|
460,000
|
|
$
|
460,000
|
|
9.00%
|
Senior unsecured notes, due June 2036 (Cdn$210,000)
|
|
|
213,588
|
|
|
206,490
|
|
5.95%
|
Senior unsecured notes, due July 2014
|
|
|
190,000
|
|
|
190,000
|
|
5.90%
|
Series A senior unsecured notes, due August 2015
|
|
|
150,000
|
|
|
150,000
|
|
5.87%
|
Series B senior unsecured notes, due August 2017
|
|
|
75,000
|
|
|
75,000
|
|
5.97%
|
Non-Recourse Debt:
|
|
|
|
|
|
|
|
|
Epsilon Power Partners term facility, due 2019
|
|
|
33,857
|
|
|
34,982
|
|
7.40%
|
Path 15 senior secured bonds
|
|
|
|
(1)
|
|
145,879
|
|
7.90% 9.00%
|
Auburndale term loan, due 2013
|
|
|
6,650
|
|
|
11,900
|
|
5.10%
|
Cadillac term loan, due 2025
|
|
|
38,431
|
|
|
40,231
|
|
6.02% 8.00%
|
Piedmont construction loan, due 2013
|
|
|
123,270
|
(2)
|
|
100,796
|
|
Libor plus 3.50%
|
Canadian Hills construction loan, due 2013
|
|
|
238,755
|
(3)
|
|
|
|
Libor plus 3.00%
|
Purchase accounting fair value adjustments
|
|
|
|
(1)
|
|
10,580
|
|
|
Less current maturities
|
|
|
(303,890
|
)
|
|
(20,958
|
)
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
1,225,661
|
|
$
|
1,404,900
|
|
|
|
|
|
|
|
|
|
Current
maturities consist of the following:
|
|
|
|
|
|
|
|
|
|
|
September 30,
2012
|
|
December 31,
2011
|
|
Interest Rate
|
Current Maturities:
|
|
|
|
|
|
|
|
|
Epsilon Power Partners term facility, due 2019
|
|
$
|
2,625
|
|
$
|
1,500
|
|
7.40%
|
Path 15 senior secured bonds
|
|
|
|
(1)
|
|
8,667
|
|
7.90% 9.00%
|
Auburndale term loan, due 2013
|
|
|
5,425
|
|
|
7,000
|
|
5.10%
|
Cadillac term loan, due 2025
|
|
|
2,400
|
|
|
3,791
|
|
6.02% 8.00%
|
Piedmont construction loan, due 2013
|
|
|
54,685
|
(2)
|
|
|
|
Libor plus 3.50%
|
Canadian Hills construction loan, due 2013
|
|
|
238,755
|
(3)
|
|
|
|
Libor plus 3.00%
|
|
|
|
|
|
|
|
Total current maturities
|
|
$
|
303,890
|
|
$
|
20,958
|
|
|
|
|
|
|
|
|
|
-
(1)
-
During
the three months ended September 30, 2012, we designated the Path 15 project as an asset held for sale. Accordingly, Path 15
senior secured bonds current maturities of $9.0 million and long term debt of $143.0 million, including a purchase accounting fair value adjustment of $10.0 million, are recorded
as a component of liabilities associated with assets held for sale on the consolidated balance sheets at September 30, 2012. See Note 11 for further discussion.
-
(2)
-
The
terms of the Piedmont project-level debt financing include a $51.0 million bridge loan for approximately 95.0% of the stimulus
grant expected to be received from the U.S. Treasury 60 days after the start of commercial operations, and an $82.0 million construction term loan. The
13
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
4. Long-term debt (Continued)
$51.0 million
bridge loan will be repaid in early 2013 and repayment of the expected $82.0 million term loan will commence in 2013.
-
(3)
-
On
October 31, 2012, the Canadian Hills project entered into an equity contribution agreement with four entities for their commitment
of a tax equity investment in the project to be funded on date of commercial operations. The proceeds from our equity contribution, the tax equity investments and a draw on our senior credit facility
will be used to pay down the construction loan at the completion of construction.
On June 22, 2012, Atlantic Power, Atlantic Power (US) GP and certain other of our subsidiaries entered into an amendment
to the Note Purchase and Parent Guaranty Agreement, dated as of August 15, 2007 (the "Note Purchase Agreement"), which governs the 5.87% senior guaranteed notes, Series A, due
August 15, 2017 (the "Series A Notes") and the 5.97% senior guaranteed notes, Series B, due August 15, 2019 (the "Series B Notes" and collectively the "Notes") of
Atlantic Power (US) GP. Under the amendment, we agreed: (i) that Atlantic Power and the existing and future guarantors of our 9.00% senior notes due November 2018 (the "Senior Notes"),
our senior credit facility and refinancings thereof would provide guarantees of the Notes; (ii) to shorten the maturity of the Series A Notes from August 15, 2017 to
August 15, 2015; (iii) to shorten the maturity of the Series B Notes from August 15, 2019 to August 15, 2017; (iv) to include an event of default that would
be triggered if certain defaults occurred under the debt instruments of Atlantic Power and certain of its subsidiaries; and (v) to add certain covenants, including covenants that limit the
ability of Curtis Palmer LLC ("Curtis Palmer"), a wholly-owned subsidiary of Atlantic Power Limited Partnership (the "Partnership") to incur debt or liens, make distributions other than in the
ordinary course of business, prepay debt or sell material assets and our ability to sell Curtis Palmer. The parties entered into the amendment following a series of discussions concerning our
acquisition of the Partnership. Although we believe that the acquisition of the Partnership was in full compliance with the terms and conditions of the Note Purchase Agreement, the holders of the
Notes agreed to waive certain defaults or events of default that they alleged may have occurred as a result of our acquisition of the Partnership in return for Atlantic Power and its subsidiaries
entering into the amendment.
Project-level debt of our consolidated projects is secured by the respective project and its contracts with no other recourse to us.
Project-level debt generally amortizes during the term of the respective revenue generating contracts of the projects. The loans have certain financial covenants that must be met. At
September 30, 2012, all of our projects were in compliance with the covenants contained in project-level debt. However, our Epsilon Power Partners, Delta-Person and Gregory projects had not
achieved the levels of debt service coverage ratios required by the project-level debt arrangements as a condition to make distributions and were therefore restricted from making distributions to us.
The non-recourse holding company debt relating to our investment in Chambers is held at Epsilon Power Partners, our wholly owned subsidiary.
14
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
4. Long-term debt (Continued)
As of September 30, 2012, $20.0 million was drawn on our senior credit facility and $135.5 million and
Cnd$1.0 million were issued in letters of credit, but not drawn, to support contractual credit requirements at several of our projects. The applicable margin on our senior credit facility was
2.75% at September 30, 2012.
In
connection with the continued evolution of the Company's strategy to focus on late-stage development and construction projects, and the possible disposition of certain projects,
including our Florida projects, on November 2, 2012, we amended the senior credit facility in order to change certain financial and leverage ratio covenants and obtained certain waivers from
our lenders in connection with certain of our projects. See Item 5. Other Information to this quarterly report on Form 10-Q for additional information.
5. Convertible debentures
The following table contains details related to outstanding convertible debentures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands US$, except for share amounts)
|
|
6.5% Debentures
due October 2014
|
|
6.25% Debentures
due March 2017
|
|
5.6% Debentures
due June 2017
|
|
5.75% Debentures
due June 2019
|
|
Total
|
|
Balance at December 31, 2011
|
|
$
|
44,103
|
|
$
|
66,306
|
|
$
|
79,154
|
|
$
|
|
|
$
|
189,563
|
|
Issuance of convertible debentures
|
|
|
|
|
|
|
|
|
|
|
|
130,000
|
|
|
130,000
|
|
Principal amount converted to equity
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
(13
|
)
|
Foreign exchange loss
|
|
|
1,516
|
|
|
2,279
|
|
|
2,722
|
|
|
|
|
|
6,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2012
|
|
$
|
45,606
|
|
$
|
68,585
|
|
$
|
81,876
|
|
$
|
130,000
|
|
$
|
326,067
|
|
Common shares issued on conversion during the nine months ended September 30, 2012
|
|
|
1,048
|
|
|
|
|
|
|
|
|
|
|
|
1,048
|
|
Aggregate
interest expense related to the convertible debentures was $4.9 million and $2.8 million for the three months ended September 30, 2012 and
2011, respectively, and $10.6 million and $9.3 million for the nine months ended September 30, 2012 and 2011, respectively.
On
July 5, 2012, we issued, in a public offering, $130.0 million aggregate principal amount of 5.75% convertible unsecured subordinated debentures due June 30, 2019,
(the "2012 Debentures") for net proceeds of $124.0 million. The 2012 Debentures pay interest semi-annually on June 30 and December 30 of each year beginning
December 30, 2012. The 2012 Debentures are convertible into our common shares at an initial conversion rate of 57.9710 common shares per $1,000 principal amount of debentures. We used the
proceeds to fund a portion of our equity commitment in Canadian Hills Wind, LLC.
15
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
6. 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, 2012 and
December 31, 2011. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2012
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
42,872
|
|
$
|
|
|
$
|
|
|
$
|
42,872
|
|
Restricted cash
|
|
|
112,633
|
|
|
|
|
|
|
|
|
112,633
|
|
Derivative instruments asset
|
|
|
|
|
|
25,028
|
|
|
|
|
|
25,028
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
155,505
|
|
$
|
25,028
|
|
$
|
|
|
$
|
180,533
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments liability
|
|
$
|
|
|
$
|
145,851
|
|
$
|
|
|
$
|
145,851
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
$
|
145,851
|
|
$
|
|
|
$
|
145,851
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2011
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
60,651
|
|
$
|
|
|
$
|
|
|
$
|
60,651
|
|
Restricted cash
|
|
|
21,412
|
|
|
|
|
|
|
|
$
|
21,412
|
|
Derivative instruments asset
|
|
|
|
|
|
32,414
|
|
|
|
|
$
|
32,414
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
82,063
|
|
$
|
32,414
|
|
$
|
|
|
$
|
114,477
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments liability
|
|
$
|
|
|
$
|
53,762
|
|
$
|
|
|
$
|
53,762
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
$
|
53,762
|
|
$
|
|
|
$
|
53,762
|
|
|
|
|
|
|
|
|
|
|
|
The
fair values of our derivative instruments are based upon trades in liquid markets. Valuation model inputs can generally be verified and valuation techniques do not
involve significant judgment. The fair values of such financial instruments are classified within Level 2 of the fair value hierarchy. We use our best estimates to determine the fair value of
commodity and derivative contracts we hold. These estimates consider various factors including closing exchange prices, time value, volatility factors and credit exposure. The fair value of each
contract is discounted using a risk free interest rate.
We
also adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating and the credit rating of our counterparties. As
of September 30, 2012, the credit valuation adjustments resulted in a $19.0 million net increase in fair value, which consists of a $1.3 million pre-tax increase in
other comprehensive income and a $17.8 million increase in change in fair value of derivative instruments, offset by a $0.1 million increase to foreign exchange loss. As of
December 31, 2011, the credit valuation adjustments resulted in a $5.8 million net increase in fair value, which consists of a $0.9 million pre-tax increase in other
comprehensive income and a $5.1 million increase in change in fair value of derivative instruments, offset by a $0.2 million increase in foreign exchange loss.
16
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
7. Accounting for derivative instruments and hedging activities
We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. For a certain limited number of
contracts designated as cash flow hedges, we defer the effective portion of the change in fair value of the derivatives to accumulated other comprehensive income (loss), until the hedged transactions
occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings.
For
derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings. The guidelines apply to our natural gas swaps, interest
rate swaps, and foreign exchange contracts.
On March 12, 2012, we discontinued the application of the normal purchase normal sales ("NPNS") exemption on gas purchase
agreements at our North Bay, Kapuskasing and Nipigon projects. On that date, we entered into an agreement with a third party that resulted in the gas purchase agreements no longer qualifying for the
NPNS exemption. The agreements at North Bay and Kapuskasing expire on December 31, 2016 and the agreements at Nipigon expire on December 31, 2012. These gas purchase agreements are
derivative financial instruments and are recorded in the consolidated balance sheet at fair value and the changes in their fair market value are recorded in the consolidated statement of operations.
In
May 2012, the Nipigon project entered into a long-term contract for the purchase of natural gas beginning on January 1, 2013 and expiring on
December 31, 2022. This contract is accounted for as a derivative financial instrument and is recorded in the consolidated balance sheet at fair value
at September 30, 2012. Changes in the fair market value of the contract are recorded in the consolidated statement of operations.
In
May 2012, the Tunis project entered into a contract for the purchase of natural gas beginning on October 1, 2012 and expiring on March 31, 2013 and qualified for
the NPNS exemption. On September 27, 2012, we discontinued the application of the NPNS exemption on this contract due to net settlements of a portion of the contract to a third party. As of
September 30, 2012 this contract is accounted for as a derivative financial instrument and is recorded in the consolidated balance sheet at fair value. Changes in the fair market value of the
contract are recorded in the consolidated statement of operations.
We
have recorded a $10.0 million unrealized gain and a $49.1 million unrealized loss for the three and nine months ended September 30, 2012, respectively, related to
our gas purchase agreements accounted for as derivative financial instruments.
Our strategy to mitigate the future exposure to changes in natural gas prices at Orlando, 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 and the changes in their fair market value are recorded in the consolidated statement of operations.
17
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
7. Accounting for derivative instruments and hedging activities (Continued)
The
operating margin at our 50% owned Orlando project is exposed to changes in natural gas prices following the expiration of its fuel contract at the end of 2013. We have entered into
natural gas swaps to effectively fix the price of 3.2 million Mmbtu of future natural gas purchases, or approximately 64% of our share of the expected natural gas purchases at the project
during 2014 and 2015. We also entered into natural gas swaps to effectively fix the price of 1.3 million Mmbtu of future natural gas purchases representing approximately 25% of our share of the
expected natural gas purchases at the project during 2016 and 2017.
The
Lake project's operating margin is exposed to changes in natural gas spot market prices through the expiration of its PPA on July 31, 2013. We have entered into natural gas
swaps to effectively fix the price of approximately 90% of the expected natural gas purchases at Lake for the remainder of 2012 and 83% of the expected natural gas purchases through July 31,
2013.
The
Auburndale project's operating margin is exposed to changes in natural gas spot market prices through the expiration of its PPA at the end of 2013. We have entered into natural gas
swaps to effectively fix the price of approximately 46% of the expected natural gas purchases at Auburndale for the remainder of 2012 and 79% of the expected natural gas purchases through
December 31, 2013.
The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate on its non-recourse,
project-level debt at 6.02% until February 15, 2015, 6.14% from February 16, 2015 to February 15, 2019, 6.26% from February 16, 2019 to February 15, 2023, and 6.38%
thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac's debt. This swap agreement, which qualifies for and
is designated as a cash flow hedge, is effective through June 2025 and changes in the fair market value are recorded in accumulated other comprehensive income.
The
Auburndale project hedged a portion of its exposure to changes in interest rates related to its variable-rate, non-recourse project-level debt. The interest
rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 5.10%. The notional amount of the swap matches the outstanding principal balance over the remaining life of
Auburndale's debt. This swap agreement is effective through November 30, 2013. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the
project-level Auburndale debt agreement and changes in the fair market value are recorded in accumulated other comprehensive income.
The
Piedmont project has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable-rate, non-recourse
debt. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.75% until February 29,
2016. From March 1, 2016 until the maturity of the debt in November 2017, the fixed rate of the swap is 4.47% and the applicable margin is 4.0%, resulting in an all-in rate
of 8.47%. The swap continues at the fixed rate of 4.47% from the maturity of the debt in November 2017 until November 2030. The notional amounts of the interest rate swap agreements
match the estimated outstanding principal balance of Piedmont's cash grant bridge loan and the construction loan facility that will convert to a term loan. The interest rate swaps were executed in the
fourth quarter 2010 and expire on February 29, 2016 and November 30, 2030. The
18
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
7. Accounting for derivative instruments and hedging activities (Continued)
interest
rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations.
Epsilon
Power Partners, a wholly owned subsidiary, has an interest rate swap to economically fix the exposure to changes in interest rates related to the variable-rate
non-recourse debt. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 4.24% and has a maturity date of July 2019. The notional
amount of the swap matches the outstanding principal balance over the remaining life of Epsilon Power Partners' debt. This interest rate swap agreement is not designated as a hedge and changes in its
fair market value are recorded in the consolidated statements of operations.
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 and Canadian dollars but pay dividends to shareholders and interest on our Canadian dollar denominated convertible debentures and long-term debt predominantly in Canadian dollars.
We have a hedging strategy for the purpose of mitigating the currency risk impact on the long-term sustainability of dividends to shareholders. We have executed this strategy by entering
into forward contracts to purchase Canadian dollars at a fixed rate to hedge an average of approximately 78% of our expected dividend and convertible debenture interest payments through 2015. Changes
in the fair value of the forward contracts partially offset foreign exchange gain or losses on the U.S. dollar equivalent of our Canadian dollar obligations. At September 30, 2012, the forward
contracts consist of (1) monthly purchases through the end of 2013 of Cdn$6.0 million at an exchange rate of Cdn$1.134 per U.S. dollar and (2) contracts assumed in our acquisition
of the Partnership with various expiration dates through December 2015 to purchase a total of Cdn$112.0 million at an average exchange rate of Cdn$1.130 per U.S. dollar. It is our
intention to periodically consider extending the length or terminating these forward contracts.
We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as
summarized below, by type,
excluding those derivatives that qualified for the NPNS exemption as of September 30, 2012 and December 31, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
Units
|
|
September 30,
2012
|
|
December 31,
2011
|
|
Natural gas swaps
|
|
Natural Gas (Mmbtu)
|
|
|
11,930
|
|
|
14,140
|
|
Gas Purchase Agreements
|
|
Natural Gas (GJ)
|
|
|
51,867
|
|
|
33,957
|
|
Interest Rate Swaps
|
|
Interest (US$)
|
|
|
48,450
|
|
|
52,711
|
|
Currency forwards
|
|
Cdn$
|
|
|
202,028
|
|
|
312,533
|
|
19
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
7. Accounting for derivative instruments and hedging activities (Continued)
Fair value of derivative instruments
We have elected to disclose derivative instrument assets and liabilities on a trade-by-trade basis and do not
offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities:
|
|
|
|
|
|
|
|
|
|
September 30, 2012
|
|
|
|
Derivative
Assets
|
|
Derivative
Liabilities
|
|
Derivative instruments designated as cash flow hedges:
|
|
|
|
|
|
|
|
Interest rate swaps current
|
|
$
|
|
|
$
|
1,469
|
|
Interest rate swaps long-term
|
|
|
|
|
|
5,391
|
|
|
|
|
|
|
|
Total derivative instruments designated as cash flow hedges
|
|
|
|
|
|
6,860
|
|
|
|
|
|
|
|
Derivative instruments not designated as cash flow hedges:
|
|
|
|
|
|
|
|
Interest rate swaps current
|
|
|
|
|
|
2,531
|
|
Interest rate swaps long-term
|
|
|
|
|
|
11,436
|
|
Foreign currency forward contracts current
|
|
|
10,299
|
|
|
|
|
Foreign currency forward contracts long-term
|
|
|
13,942
|
|
|
|
|
Natural gas swaps current
|
|
|
|
|
|
18,764
|
|
Natural gas swaps long-term
|
|
|
294
|
|
|
6,588
|
|
Gas purchase agreements current
|
|
|
493
|
|
|
19,676
|
|
Gas purchase agreements long-term
|
|
|
|
|
|
79,996
|
|
|
|
|
|
|
|
Total derivative instruments not designated as cash flow hedges
|
|
|
25,028
|
|
|
138,991
|
|
|
|
|
|
|
|
Total derivative instruments
|
|
$
|
25,028
|
|
$
|
145,851
|
|
|
|
|
|
|
|
20
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
7. Accounting for derivative instruments and hedging activities (Continued)
|
|
|
|
|
|
|
|
|
|
December 31, 2011
|
|
|
|
Derivative
Assets
|
|
Derivative
Liabilities
|
|
Derivative instruments designated as cash flow hedges:
|
|
|
|
|
|
|
|
Interest rate swaps current
|
|
$
|
|
|
$
|
1,561
|
|
Interest rate swaps long-term
|
|
|
|
|
|
5,317
|
|
|
|
|
|
|
|
Total derivative instruments designated as cash flow hedges
|
|
|
|
|
|
6,878
|
|
|
|
|
|
|
|
Derivative instruments not designated as cash flow hedges:
|
|
|
|
|
|
|
|
Interest rate swaps current
|
|
|
|
|
|
2,587
|
|
Interest rate swaps long-term
|
|
|
|
|
|
9,637
|
|
Foreign currency forward contracts current
|
|
|
10,630
|
|
|
224
|
|
Foreign currency forward contracts long-term
|
|
|
22,224
|
|
|
221
|
|
Natural gas swaps current
|
|
|
|
|
|
16,439
|
|
Natural gas swaps long-term
|
|
|
|
|
|
18,216
|
|
Gas purchase agreements current
|
|
|
|
|
|
|
|
Gas purchase agreements long-term
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative instruments not designated as cash flow hedges
|
|
|
32,854
|
|
|
47,324
|
|
|
|
|
|
|
|
Total derivative instruments
|
|
$
|
32,854
|
|
$
|
54,202
|
|
|
|
|
|
|
|
The following table summarizes the changes in the accumulated other comprehensive income (loss) ("OCI") balance attributable to
derivative financial instruments designated as a hedge, net of tax:
|
|
|
|
|
|
|
|
|
|
|
For the three month period ended September 30, 2012
|
|
Interest Rate
Swaps
|
|
Natural Gas
Swaps
|
|
Total
|
|
Accumulated OCI balance at June 30, 2012
|
|
$
|
(1,667
|
)
|
$
|
207
|
|
$
|
(1,460
|
)
|
Change in fair value of cash flow hedges
|
|
|
(300
|
)
|
|
|
|
|
(300
|
)
|
Realized from OCI during the period
|
|
|
274
|
|
|
(58
|
)
|
|
216
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at September 30, 2012
|
|
$
|
(1,693
|
)
|
$
|
149
|
|
$
|
(1,544
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three month period ended September 30, 2011
|
|
Interest Rate
Swaps
|
|
Natural Gas
Swaps
|
|
Total
|
|
Accumulated OCI balance at June 30, 2011
|
|
$
|
(479
|
)
|
$
|
503
|
|
$
|
24
|
|
Change in fair value of cash flow hedges
|
|
|
(1,495
|
)
|
|
|
|
|
(1,495
|
)
|
Realized from OCI during the period
|
|
|
344
|
|
|
(91
|
)
|
|
253
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at September 30, 2011
|
|
$
|
(1,630
|
)
|
$
|
412
|
|
$
|
(1,218
|
)
|
|
|
|
|
|
|
|
|
21
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
7. Accounting for derivative instruments and hedging activities (Continued)
|
|
|
|
|
|
|
|
|
|
|
For the nine month period ended September 30, 2012
|
|
Interest Rate
Swaps
|
|
Natural Gas
Swaps
|
|
Total
|
|
Accumulated OCI balance at December 31, 2011
|
|
$
|
(1,704
|
)
|
$
|
321
|
|
$
|
(1,383
|
)
|
Change in fair value of cash flow hedges
|
|
|
(833
|
)
|
|
|
|
|
(833
|
)
|
Realized from OCI during the period
|
|
|
844
|
|
|
(172
|
)
|
|
672
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at September 30, 2012
|
|
$
|
(1,693
|
)
|
$
|
149
|
|
$
|
(1,544
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the nine month period ended September 30, 2011
|
|
Interest Rate
Swaps
|
|
Natural Gas
Swaps
|
|
Total
|
|
Accumulated OCI balance at December 31, 2010
|
|
$
|
(427
|
)
|
$
|
682
|
|
$
|
255
|
|
Change in fair value of cash flow hedges
|
|
|
(2,257
|
)
|
|
|
|
|
(2,257
|
)
|
Realized from OCI during the period
|
|
|
1,054
|
|
|
(270
|
)
|
|
784
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at September 30, 2011
|
|
$
|
(1,630
|
)
|
$
|
412
|
|
$
|
(1,218
|
)
|
|
|
|
|
|
|
|
|
The following table summarizes realized (gains) and losses for derivative instruments not designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
|
|
Classification of (gain) loss
recognized in income
|
|
|
|
2012
|
|
2011
|
|
Natural gas swaps
|
|
Fuel
|
|
$
|
5,170
|
|
$
|
1,744
|
|
Gas purchase agreements
|
|
Fuel
|
|
|
15,191
|
|
|
|
|
Foreign currency forwards
|
|
Foreign exchange (gain) loss
|
|
|
(2,068
|
)
|
|
(2,100
|
)
|
Interest rate swaps
|
|
Interest, net
|
|
|
1,208
|
|
|
1,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended
September 30,
|
|
|
|
Classification of (gain) loss recognized in income
|
|
|
|
2012
|
|
2011
|
|
Natural gas swaps
|
|
Fuel
|
|
$
|
14,994
|
|
$
|
6,275
|
|
Gas purchase agreements
|
|
Fuel
|
|
|
47,839
|
|
|
|
|
Foreign currency forwards
|
|
Foreign exchange (gain) loss
|
|
|
(17,110
|
)
|
|
(7,792
|
)
|
Interest rate swaps
|
|
Interest, net
|
|
|
3,556
|
|
|
3,022
|
|
22
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
7. Accounting for derivative instruments and hedging activities (Continued)
The
following table summarizes the unrealized gains and (losses) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
|
|
Classification of (gain) loss
recognized in income
|
|
|
|
2012
|
|
2011
|
|
Natural gas swaps
|
|
Change in fair value of derivatives
|
|
$
|
7,463
|
|
$
|
(3,017
|
)
|
Gas purchase agreements
|
|
Change in fair value of derivatives
|
|
|
10,022
|
|
|
|
|
Interest rate swaps
|
|
Change in fair value of derivatives
|
|
|
(272
|
)
|
|
(8,467
|
)
|
|
|
|
|
|
|
|
|
Total change in fair value of derivative instruments
|
|
|
|
$
|
17,213
|
|
$
|
(11,484
|
)
|
|
|
|
|
|
|
|
|
Foreign currency forwards
|
|
Foreign exchange (gain) loss
|
|
$
|
(4,694
|
)
|
$
|
39,950
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended
September 30,
|
|
|
|
Classification of (gain) loss
recognized in income
|
|
|
|
2012
|
|
2011
|
|
Natural gas swaps
|
|
Change in fair value of derivatives
|
|
$
|
9,883
|
|
$
|
(1,372
|
)
|
Gas purchase agreements
|
|
Change in fair value of derivatives
|
|
|
(49,093
|
)
|
|
|
|
Interest rate swaps
|
|
Change in fair value of derivatives
|
|
|
(1,743
|
)
|
|
(11,125
|
)
|
|
|
|
|
|
|
|
|
Total change in fair value of derivative instruments
|
|
|
|
$
|
(40,953
|
)
|
$
|
(12,497
|
)
|
|
|
|
|
|
|
|
|
Foreign currency forwards
|
|
Foreign exchange (gain) loss
|
|
$
|
8,169
|
|
$
|
37,817
|
|
|
|
|
|
|
|
|
|
8. Income taxes
The difference between the actual tax expense (benefit) of $3.2 million and $(19.1) million for the three and nine months ended September 30, 2012 and the expected
income tax benefit, based on the Canadian enacted statutory rate of 25%, of $(0.5) million and $(16.6) million, respectively, is primarily due to higher tax rates in various tax
jurisdictions, and various other permanent differences, partially offset by a change in the valuation allowance.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
Current income tax expense (benefit)
|
|
$
|
1,935
|
|
$
|
104
|
|
$
|
6,116
|
|
$
|
(366
|
)
|
Deferred tax expense (benefit)
|
|
|
1,231
|
|
|
(5,427
|
)
|
|
(25,192
|
)
|
|
(12,534
|
)
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit)
|
|
$
|
3,166
|
|
$
|
(5,323
|
)
|
$
|
(19,076
|
)
|
$
|
(12,900
|
)
|
|
|
|
|
|
|
|
|
|
|
23
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
8. Income taxes (Continued)
As of September 30, 2012, we have recorded a valuation allowance of $98.4 million. This amount is comprised primarily of provisions against available Canadian and U.S. net
operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be
realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.
9. Employee Incentive Programs
The following table summarizes the changes in LTIP notional units during the nine months ended September 30, 2012:
|
|
|
|
|
|
|
|
|
|
Units
|
|
Grant Date
Weighted-Average
Price per Unit
|
|
Outstanding at December 31, 2011
|
|
|
485,781
|
|
$
|
11.49
|
|
Granted
|
|
|
226,752
|
|
$
|
14.66
|
|
Forfeited
|
|
|
(28,932
|
)
|
$
|
13.63
|
|
Additional shares from dividends
|
|
|
27,579
|
|
$
|
13.25
|
|
Vested
|
|
|
(231,687
|
)
|
$
|
10.10
|
|
|
|
|
|
|
|
Outstanding at September 30, 2012
|
|
|
479,493
|
|
$
|
13.56
|
|
|
|
|
|
|
|
Certain
awards have a market condition based on our total shareholder return during the performance period compared to a group of peer companies. Compensation expense for notional units
granted in 2012 is recorded net of estimated forfeitures. See further details as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011.
The
calculation of simulated total shareholder return under the Monte Carlo model for the remaining time in the performance period for awards with market conditions included the
following assumptions as of September 30, 2012 and December 31, 2011:
|
|
|
|
|
|
|
|
|
|
September 30, 2012
|
|
December 31, 2011
|
|
Weighted average risk free rate of return
|
|
|
0.14 0.27%
|
|
|
0.15 0.28%
|
|
Dividend yield
|
|
|
7.80%
|
|
|
7.90%
|
|
Expected volatilityAtlantic Power
|
|
|
14.0 19.9%
|
|
|
22.20%
|
|
Expected volatilitypeer companies
|
|
|
11.3 144.6%
|
|
|
17.3 112.9%
|
|
Weighted average remaining measurement period
|
|
|
1.43 years
|
|
|
0.87 years
|
|
On April 23, 2012 the Board of Directors, upon the recommendation of the Compensation Committee, adopted the 2012 Equity
Incentive Plan (the "2012 Incentive Plan"),
which was approved by our shareholders on June 22, 2012. The 2012 Incentive Plan increases the flexibility of the Compensation Committee to use various equity-based incentive awards as
compensation tools to
24
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
9. Employee Incentive Programs (Continued)
motivate
our employees. Adoption of the 2012 Incentive Plan did not have any impact on previous award grants and 6,000 common shares have been granted under the 2012 Incentive Plan as of
September 30, 2012. The 2012 Incentive Plan has an expiration date of June 22, 2022.
10. 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, 2012. 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.
The
following table sets forth the diluted net income and potentially dilutive shares utilized in the per share calculation for the three and nine months ended September 30, 2012
and 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Atlantic Power Corporation
|
|
$
|
(7,446
|
)
|
$
|
(27,900
|
)
|
$
|
(54,824
|
)
|
$
|
(8,578
|
)
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average basic shares outstanding
|
|
|
119,011
|
|
|
68,910
|
|
|
115,437
|
|
|
68,384
|
|
Dilutive potential shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible debentures
|
|
|
20,459
|
|
|
13,718
|
|
|
15,672
|
|
|
14,190
|
|
LTIP notional units
|
|
|
481
|
|
|
415
|
|
|
477
|
|
|
363
|
|
|
|
|
|
|
|
|
|
|
|
Potentially dilutive shares
|
|
|
139,951
|
|
|
83,043
|
|
|
131,586
|
|
|
82,937
|
|
|
|
|
|
|
|
|
|
|
|
Diluted loss per share
|
|
$
|
(0.06
|
)
|
$
|
(0.40
|
)
|
$
|
(0.47
|
)
|
$
|
(0.13
|
)
|
|
|
|
|
|
|
|
|
|
|
Potentially
dilutive shares from convertible debentures and potentially dilutive shares from LTIP notional units have been excluded from fully diluted shares in the three and nine months
ended September 30, 2012 and 2011 because their impact would be anti-dilutive.
11. Held for Sale Business
During the three months ended September 30, 2012, we classified our Path 15 project, which is a component of the Southwest segment, as a held for sale business based on our
plan to sell the project within the next twelve months. Accordingly, the assets and liabilities of Path 15 have been classified separately as held for sale in the consolidated balance sheet at
September 30, 2012 and the project's net income is recorded as income from discontinued operations in the consolidated statements of operations, net of tax for the three and nine months ended
September 30, 2012 and 2011. The
25
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
11. Held for Sale Business (Continued)
following
table summarizes the revenue, income from operations and income tax expense of Path 15 for the three and nine months ended September 30, 2012 and 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
Revenue
|
|
$
|
7,227
|
|
$
|
7,638
|
|
$
|
20,751
|
|
$
|
22,773
|
|
Income from operations of discontinued businesses
|
|
|
1,261
|
|
|
2,074
|
|
|
2,356
|
|
|
5,733
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
|
488
|
|
|
803
|
|
|
912
|
|
|
2,219
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations of discontinued businesses, net of tax
|
|
$
|
773
|
|
$
|
1,271
|
|
$
|
1,444
|
|
$
|
3,514
|
|
|
|
|
|
|
|
|
|
|
|
Basic
and diluted earnings per share related to income from discontinued operations was $0.01 and $0.02 for the three months ended September 30, 2012 and 2011, respectively and
$0.01 and $0.05 for the nine months ended September 30, 2012 and 2011, respectively.
The
components of assets and liabilities held for sale are set forth in the following table:
|
|
|
|
|
|
|
September 30,
2012
|
|
Current assets:
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,742
|
|
Restricted cash
|
|
|
14,273
|
|
Accounts receivable
|
|
|
1,691
|
|
Other current assets
|
|
|
664
|
|
|
|
|
|
|
|
|
18,370
|
|
Non-current assets assets:
|
|
|
|
|
Transmission system rights
|
|
|
174,393
|
|
Goodwill
|
|
|
8,918
|
|
Other assets
|
|
|
1,430
|
|
|
|
|
|
Assets held for sale
|
|
|
203,111
|
|
Current liabilities:
|
|
|
|
|
Accounts payable and other accrued liabilities
|
|
$
|
5,380
|
|
Current portion of long-term debt
|
|
|
9,028
|
|
|
|
|
|
|
|
|
14,408
|
|
Long term liabilities
|
|
|
|
|
Long-term debt
|
|
|
143,012
|
|
|
|
|
|
Liabilities held for sale
|
|
|
157,420
|
|
26
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
12. Equity
The following table provides a reconciliation of the beginning and ending equity attributable to shareholders of Atlantic Power Corporation, preferred shares issued by a subsidiary
company, noncontrolling interest and total equity as of September 30, 2012 and 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2012
|
|
|
|
Total Atlantic
Power Corporation
Shareholders'
Equity
|
|
Preferred shares
issued by a
subsidiary
company
|
|
Noncontrolling
Interest
|
|
Total Equity
|
|
Balance at January 1
|
|
$
|
891,450
|
|
$
|
221,304
|
|
$
|
3,027
|
|
$
|
1,115,781
|
|
Net income (loss)
|
|
|
(54,824
|
)
|
|
9,767
|
|
|
(696
|
)
|
|
(45,753
|
)
|
Realized and unrealized loss on hedging activities, net of tax
|
|
|
(162
|
)
|
|
|
|
|
|
|
|
(162
|
)
|
Foreign currency translation adjustment, net of tax
|
|
|
22,608
|
|
|
|
|
|
|
|
|
22,608
|
|
Common shares issuance, net of costs
|
|
|
67,777
|
|
|
|
|
|
|
|
|
67,777
|
|
Compensation expense for LTIP
|
|
|
1,344
|
|
|
|
|
|
|
|
|
1,344
|
|
Convertible debenture conversion
|
|
|
13
|
|
|
|
|
|
|
|
|
13
|
|
Dividends declared on common shares
|
|
|
(99,043
|
)
|
|
|
|
|
|
|
|
(99,043
|
)
|
Dividends declared on preferred shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
of a subsidiary company
|
|
|
|
|
|
(9,767
|
)
|
|
|
|
|
(9,767
|
)
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30
|
|
$
|
829,163
|
|
$
|
221,304
|
|
$
|
2,331
|
|
$
|
1,052,798
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2011
|
|
|
|
Total Atlantic
Power Corporation
Shareholders'
Equity
|
|
Preferred shares
issued by a
subsidiary
company
|
|
Noncontrolling
Interest
|
|
Total Equity
|
|
Balance at January 1
|
|
$
|
429,869
|
|
$
|
|
|
$
|
3,507
|
|
$
|
433,376
|
|
Net loss
|
|
|
(8,578
|
)
|
|
|
|
|
(349
|
)
|
|
(8,927
|
)
|
Realized and unrealized loss on hedging activities, net of tax
|
|
|
(1,473
|
)
|
|
|
|
|
|
|
|
(1,473
|
)
|
Compensation expense for LTIP
|
|
|
1,232
|
|
|
|
|
|
|
|
|
1,232
|
|
Convertible debenture conversion
|
|
|
21,730
|
|
|
|
|
|
|
|
|
21,730
|
|
Dividends declared on common shares
|
|
|
(57,064
|
)
|
|
|
|
|
|
|
|
(57,064
|
)
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30
|
|
$
|
385,716
|
|
$
|
|
|
$
|
3,158
|
|
$
|
388,874
|
|
|
|
|
|
|
|
|
|
|
|
On
August 8, 2012, we announced the details of our Dividend Reinvestment Plan ("DRIP"). The DRIP allows eligible holders of common shares to reinvest their cash dividends to
acquire additional common shares of Atlantic Power at a 3% discount to market price.
On
July 5, 2012, we closed a public offering of 5,567,177 common shares, at a purchase price of $12.76 per common share and Cdn$13.10 per common share, for aggregate net proceeds,
after deducting the underwriting discounts and expenses, of approximately $67.7 million.
27
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
13. Segment and geographic information
We revised our reportable business segments during the fourth quarter of 2011 subsequent to our acquisition of the Partnership. The new operating segments are Northeast, Northwest,
Southeast, Southwest and Un-allocated Corporate. Financial results for the three and nine months ended September 30, 2012 and 2011 have been presented to reflect the change in
operating segments. We revised our segments to align with changes in management's resource allocation and assessment of performance. These changes reflect our current operating focus. The segment
classified as Un-allocated Corporate includes activities that support the executive offices, capital structure and costs of being a public registrant in the United States and Canada. These
costs are not allocated to the operating segments when determining segment profit or loss.
We
analyze the performance of our operating segments based on Project Adjusted EBITDA which is defined as project income plus interest, taxes, depreciation and amortization (including
non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under U.S. generally accepted accounting principles
("GAAP") and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to
provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value.
A reconciliation of project (loss) income to Project Adjusted EBITDA is included in the tables below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
Southeast
|
|
Northwest
|
|
Southwest
|
|
Un-allocated
Corporate
|
|
Consolidated
|
|
Three month period ended September 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
43,804
|
|
$
|
48,194
|
|
$
|
14,959
|
|
$
|
47,734
|
|
$
|
(192
|
)
|
$
|
154,499
|
|
Segment assets
|
|
|
1,157,943
|
|
|
446,313
|
|
|
851,972
|
|
|
1,162,580
|
|
|
25,187
|
|
|
3,643,995
|
|
Project Adjusted EBITDA
|
|
$
|
20,346
|
|
$
|
23,150
|
|
$
|
12,596
|
|
$
|
23,440
|
|
$
|
(2,338
|
)
|
$
|
77,194
|
|
Change in fair value of derivative instruments
|
|
|
(10,160
|
)
|
|
(7,187
|
)
|
|
|
|
|
|
|
|
|
|
|
(17,347
|
)
|
Depreciation and amortization
|
|
|
20,367
|
|
|
9,360
|
|
|
10,710
|
|
|
9,252
|
|
|
36
|
|
|
49,725
|
|
Interest, net
|
|
|
4,484
|
|
|
141
|
|
|
1,204
|
|
|
135
|
|
|
44
|
|
|
6,008
|
|
Other project (income) expense
|
|
|
258
|
|
|
|
|
|
|
|
|
156
|
|
|
415
|
|
|
829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project (loss) income
|
|
|
5,397
|
|
|
20,836
|
|
|
682
|
|
|
13,897
|
|
|
(2,833
|
)
|
|
37,979
|
|
Administration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,309
|
|
|
6,309
|
|
Interest, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,829
|
|
|
25,829
|
|
Foreign exchange gain
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,659
|
|
|
7,659
|
|
Other income, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
272
|
|
|
272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations before income taxes
|
|
|
5,397
|
|
|
20,836
|
|
|
682
|
|
|
13,897
|
|
|
(42,902
|
)
|
|
(2,090
|
)
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,166
|
|
|
3,166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
5,397
|
|
|
20,836
|
|
|
682
|
|
|
13,897
|
|
|
(46,068
|
)
|
|
(5,256
|
)
|
Income from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
773
|
|
|
|
|
|
773
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
5,397
|
|
$
|
20,836
|
|
$
|
682
|
|
$
|
14,670
|
|
$
|
(46,068
|
)
|
$
|
(4,483
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
13. Segment and geographic information (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
Southeast
|
|
Northwest
|
|
Southwest
|
|
Un-allocated
Corporate
|
|
Consolidated
|
|
Three month period ended September 30, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
4,933
|
|
$
|
39,661
|
|
$
|
|
|
$
|
|
|
$
|
101
|
|
$
|
44,695
|
|
Segment assets
|
|
|
277,314
|
|
|
419,584
|
|
|
46,841
|
|
|
224,957
|
|
|
60,325
|
|
|
1,029,021
|
|
Project Adjusted EBITDA
|
|
$
|
9,817
|
|
$
|
21,635
|
|
$
|
1,121
|
|
$
|
1,523
|
|
$
|
(233
|
)
|
$
|
33,863
|
|
Change in fair value of derivative instruments
|
|
|
224
|
|
|
10,648
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
10,871
|
|
Depreciation and amortization
|
|
|
4,636
|
|
|
9,390
|
|
|
1,001
|
|
|
757
|
|
|
13
|
|
|
15,797
|
|
Interest, net
|
|
|
2,491
|
|
|
243
|
|
|
682
|
|
|
284
|
|
|
6
|
|
|
3,706
|
|
Other project (income) expense
|
|
|
1,300
|
|
|
12
|
|
|
|
|
|
1
|
|
|
(4
|
)
|
|
1,309
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project (loss) income
|
|
|
1,166
|
|
|
1,342
|
|
|
(562
|
)
|
|
481
|
|
|
(247
|
)
|
|
2,180
|
|
Administration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,839
|
|
|
11,839
|
|
Interest, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,337
|
|
|
3,337
|
|
Foreign exchange gain
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,576
|
|
|
21,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
|
1,166
|
|
|
1,342
|
|
|
(562
|
)
|
|
481
|
|
|
(36,999
|
)
|
|
(34,572
|
)
|
Income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,323
|
)
|
|
(5,323
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
1,166
|
|
|
1,342
|
|
|
(562
|
)
|
|
481
|
|
|
(31,676
|
)
|
|
(29,249
|
)
|
Income from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
1,271
|
|
|
|
|
|
1,271
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
1,166
|
|
$
|
1,342
|
|
$
|
(562
|
)
|
$
|
1,752
|
|
$
|
(31,676
|
)
|
$
|
(27,978
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
Southeast
|
|
Northwest
|
|
Southwest
|
|
Un-allocated
Corporate
|
|
Consolidated
|
|
Nine month period ended September 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
156,632
|
|
$
|
137,406
|
|
$
|
46,923
|
|
$
|
121,674
|
|
$
|
1,195
|
|
$
|
463,830
|
|
Segment assets
|
|
|
1,157,943
|
|
|
446,313
|
|
|
851,972
|
|
|
1,162,580
|
|
|
25,187
|
|
|
3,643,995
|
|
Project Adjusted EBITDA
|
|
$
|
85,156
|
|
$
|
69,892
|
|
$
|
38,453
|
|
$
|
47,952
|
|
$
|
(9,645
|
)
|
$
|
231,808
|
|
Change in fair value of derivative instruments
|
|
|
46,283
|
|
|
(7,840
|
)
|
|
|
|
|
|
|
|
|
|
|
38,443
|
|
Depreciation and amortization
|
|
|
58,028
|
|
|
28,099
|
|
|
31,730
|
|
|
28,902
|
|
|
37
|
|
|
146,796
|
|
Interest, net
|
|
|
13,922
|
|
|
404
|
|
|
3,833
|
|
|
412
|
|
|
(2
|
)
|
|
18,569
|
|
Other project (income) expense
|
|
|
755
|
|
|
28
|
|
|
|
|
|
2,927
|
|
|
590
|
|
|
4,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project (loss) income
|
|
|
(33,832
|
)
|
|
49,201
|
|
|
2,890
|
|
|
15,711
|
|
|
(10,270
|
)
|
|
23,700
|
|
Administration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,992
|
|
|
21,992
|
|
Interest, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
69,269
|
|
|
69,269
|
|
Foreign exchange gain
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,440
|
|
|
4,440
|
|
Other income, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,728
|
)
|
|
(5,728
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations before income taxes
|
|
|
(33,832
|
)
|
|
49,201
|
|
|
2,890
|
|
|
15,711
|
|
|
(100,243
|
)
|
|
(66,273
|
)
|
Income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19,076
|
)
|
|
(19,076
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
(33,832
|
)
|
|
49,201
|
|
|
2,890
|
|
|
15,711
|
|
|
(81,167
|
)
|
|
(47,197
|
)
|
Income from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
1,444
|
|
|
|
|
|
1,444
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(33,832
|
)
|
$
|
49,201
|
|
$
|
2,890
|
|
$
|
17,155
|
|
$
|
(81,167
|
)
|
$
|
(45,753
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
13. Segment and geographic information (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
Southeast
|
|
Northwest
|
|
Southwest
|
|
Un-allocated
Corporate
|
|
Consolidated
|
|
Nine month period ended September 30, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
14,498
|
|
$
|
121,747
|
|
$
|
|
|
$
|
|
|
$
|
238
|
|
$
|
136,483
|
|
Segment assets
|
|
|
277,314
|
|
|
419,584
|
|
|
46,841
|
|
|
224,957
|
|
|
60,325
|
|
|
1,029,021
|
|
Project Adjusted EBITDA
|
|
$
|
27,400
|
|
$
|
63,892
|
|
$
|
3,606
|
|
$
|
4,894
|
|
$
|
(838
|
)
|
$
|
98,954
|
|
Change in fair value of derivative instruments
|
|
|
1,461
|
|
|
11,452
|
|
|
|
|
|
|
|
|
|
|
|
12,913
|
|
Depreciation and amortization
|
|
|
13,848
|
|
|
28,262
|
|
|
2,299
|
|
|
2,472
|
|
|
35
|
|
|
46,916
|
|
Interest, net
|
|
|
7,386
|
|
|
831
|
|
|
2,204
|
|
|
638
|
|
|
41
|
|
|
11,100
|
|
Other project (income) expense
|
|
|
1,731
|
|
|
57
|
|
|
|
|
|
5
|
|
|
(4
|
)
|
|
1,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project (loss) income
|
|
|
2,974
|
|
|
23,290
|
|
|
(897
|
)
|
|
1,779
|
|
|
(910
|
)
|
|
26,236
|
|
Administration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,379
|
|
|
20,379
|
|
Interest, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,815
|
|
|
10,815
|
|
Foreign exchange gain
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,383
|
|
|
20,383
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
|
2,974
|
|
|
23,290
|
|
|
(897
|
)
|
|
1,779
|
|
|
(52,487
|
)
|
|
(25,341
|
)
|
Income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,900
|
)
|
|
(12,900
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
2,974
|
|
|
23,290
|
|
|
(897
|
)
|
|
1,779
|
|
|
(39,587
|
)
|
|
(12,441
|
)
|
Income from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
3,514
|
|
|
|
|
|
3,514
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
2,974
|
|
$
|
23,290
|
|
$
|
(897
|
)
|
$
|
5,293
|
|
$
|
(39,587
|
)
|
$
|
(8,927
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The tables below provide information, by country, about our consolidated operations for the three and nine months ended September 30, 2012
and 2011. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project Revenue
Three Months Ended
September 30,
|
|
Project Revenue
Nine Months Ended
September 30,
|
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
United States
|
|
$
|
109,177
|
|
$
|
44,695
|
|
$
|
309,336
|
|
$
|
136,483
|
|
Canada
|
|
|
45,322
|
|
|
|
|
|
154,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
154,499
|
|
$
|
44,695
|
|
$
|
463,830
|
|
$
|
136,483
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and
Equipment, net of
accumulated depreciation
September 30,
|
|
|
|
|
|
|
|
2012
|
|
2011
|
|
|
|
|
|
United States
|
|
$
|
1,164,340
|
|
$
|
360,594
|
|
|
|
|
|
|
|
Canada
|
|
|
566,425
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,730,765
|
|
$
|
360,594
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Progress
Energy Florida ("PEF") and the Ontario Electricity Financial Corp ("OEFC") provided approximately 28% and 19%, respectively, of total consolidated revenues for the three months
ended September 30, 2012, and 26% and 22%, respectively, of total consolidated revenues for the nine
30
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
13. Segment and geographic information (Continued)
months
ended September 30, 2012. PEF and the California Independent System Operator ("CAISO") provided approximately 70% and 15%, respectively, of total consolidated revenues for the three
months ended September 30, 2011, and 74% and 15%, respectively, for the nine months ended September 30, 2011. PEF purchases electricity from the Auburndale and Lake projects in the
Southeast segment, OEFC purchases electricity from the Calstock, Kapuskasing, Nipigon, North Bay and Tunis projects in the Northeast segment and the CAISO makes payments to Path 15 in the
Southwest segment.
14. Commitments and contingencies
In February 2011, we filed a rate application with the Federal Energy Regulatory Commission ("FERC") to establish
Path 15's revenue requirement at $30.3 million for the 2011-2013 period. On March 7, 2012, Path 15 filed a formal settlement agreement establishing a revenue
requirement at $28.8 million with the Administrative Law Judge for review and certification to FERC for approval. The settlement was approved by the FERC on May 23, 2012.
In 2011, the Internal Revenue Service ("IRS") began an examination of our federal income tax returns for the tax years ended
December 31, 2007 and 2009. On April 2, 2012, the IRS issued various Notices of Proposed Adjustments. The principal area of the proposed adjustments pertain to the classification of U.S.
real property in the calculation of the gain related to our 2009 conversion from the previous Income Participating Security structure to our current traditional common share structure.
We
intend to vigorously contest these proposed adjustments, including pursuing all administrative and judicial remedies available to us. We expect to be successful in sustaining our
positions with no material
impact to our financial results. No accrual has been made for any contingency related to any of the proposed adjustments as of September 30, 2012.
Our Lake project is currently involved in a dispute with PEF over off-peak energy sales in 2010. All amounts billed for
off-peak energy during 2010 by the Lake project have been paid in full by PEF. The Lake project has filed a claim against PEF in which we seek to confirm our contractual right to sell
off-peak energy at the contractual price for such sales. PEF filed a counter-claim against the Lake project, seeking, among other things, the return of amounts paid for
off-peak power sales during 2010 and a declaratory order clarifying Lake's rights and obligations under the PPA. The Lake project has stopped dispatching during off-peak
periods pending the outcome of the dispute. However, we strongly believe that the court will confirm our contractual right to sell off-peak power using the contractual price that was used
during 2010 and that we will be able to continue such off-peak power sales for the remainder of the term of the PPA. We have not recorded any reserves related to this dispute and expect
that the outcome will not have a material adverse effect on our financial position or results of operations.
31
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
14. Commitments and contingencies (Continued)
On May 29, 2011, our Morris facility was struck by lightning. As a result, steam and electric deliveries were interrupted to our
host Equistar. We believe the interruption constitutes a force majeure under the energy services agreement with Equistar. Equistar disputes this interpretation and has initiated arbitration
proceedings under the agreement for recovery of resulting lost profits and equipment damage among other items. The agreement with Equistar specifically shields Morris from exposure to consequential
damages incurred by Equistar and management expects our insurance to cover any material losses we might incur in connection with such proceedings, including settlement costs. Management will attempt
to resolve the arbitration through settlement discussions, but is prepared to vigorously defend the arbitration on the merits.
In addition to the other matters listed above, 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 probable and can be reasonably
estimated. There are no matters pending which are expected to have a material adverse impact on our financial position or results of operations or have been reserved for as of September 30,
2012.
15. Guarantees and condensed consolidating financial information
In connection with the tax equity investments in our Canadian Hills project, we have expressly indemnified the investors for certain representations and warranties made by a wholly-owned
subsidiary with respect to matters which we believe are remote and improbable to occur. The expiration dates of these guarantees vary from less than one year through the indefinite termination date of
the project. Our maximum undiscounted potential exposure is limited to the amount of tax equity investment less the sum of cash distributions made to the investors and any net federal income tax
benefits arising from production tax credits.
As
of September 30, 2012 and December 31, 2011, we had $460.0 million of Senior Notes. These notes are guaranteed by certain of our wholly owned subsidiaries, or
guarantor subsidiaries.
Unless
otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2012:
Atlantic
Power Limited Partnership, Atlantic Power GP Inc., Atlantic Power (US) GP, Atlantic Power Corporation, Atlantic Power Generation, Inc., Atlantic
Power Transmission, Inc., Atlantic Power Holdings, Inc., Atlantic Power Services Canada GP Inc., Atlantic Power Services Canada LP, Atlantic Power
Services, LLC, Teton Power Funding, LLC, Harbor Capital Holdings, LLC, Epsilon Power Funding, LLC, Atlantic Auburndale, LLC, Auburndale LP, LLC,
Auburndale GP, LLC, Atlantic Cadillac Holdings, LLC, Atlantic Idaho Wind Holdings, LLC, Atlantic Idaho Wind C, LLC, Baker Lake Hydro, LLC, Olympia
Hydro, LLC, Teton East Coast Generation, LLC, NCP Gem, LLC, NCP Lake Power, LLC, Lake Investment, LP, Teton New Lake, LLC, Lake Cogen Ltd., Atlantic
Renewables Holdings, LLC, Orlando Power Generation I, LLC, Orlando Power Generation II, LLC, NCP Dade Power, LLC, NCP Pasco LLC, Dade
Investment, LP, Pasco Cogen, Ltd., Atlantic Piedmont
32
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
15. Guarantees and condensed consolidating financial information (Continued)
Holdings LLC,
Teton Selkirk, LLC, Atlantic Oklahoma Wind, LLC, and Teton Operating Services, LLC.
The
following condensed consolidating financial information presents the financial information of Atlantic Power, the guarantor subsidiaries, and Curtis Palmer in accordance with
Rule 3-10 under the SEC's Regulation S-X. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions. The
financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or Curtis Palmer operated as independent entities.
In
this presentation, Atlantic Power consists of parent company operations. Guarantor subsidiaries of Atlantic Power are reported on a combined basis. For companies acquired, the fair
values of the assets and liabilities acquired have been presented on a push-down accounting basis.
33
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
15. Guarantees and condensed consolidating financial information (Continued)
ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING BALANCE SHEET
September 30, 2012
(in thousands of U.S. dollars)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
Subsidiaries
|
|
Curtis
Palmer
|
|
Atlantic
Power
|
|
Eliminations
|
|
Consolidated
Balance
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
42,510
|
|
$
|
(1,939
|
)
|
$
|
2,301
|
|
$
|
|
|
$
|
42,872
|
|
Restricted cash
|
|
|
112,633
|
|
|
|
|
|
|
|
|
|
|
|
112,633
|
|
Accounts receivable
|
|
|
109,511
|
|
|
27,555
|
|
|
2,011
|
|
|
(58,887
|
)
|
|
80,190
|
|
Prepayments, supplies, and other current assets
|
|
|
49,017
|
|
|
2,968
|
|
|
10,309
|
|
|
|
|
|
62,294
|
|
Asset held for sale
|
|
|
203,111
|
|
|
|
|
|
|
|
|
|
|
|
203,111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
516,782
|
|
|
28,584
|
|
|
14,621
|
|
|
(58,887
|
)
|
|
501,100
|
|
Property, plant, and equipment, net
|
|
|
1,558,898
|
|
|
173,034
|
|
|
|
|
|
(1,167
|
)
|
|
1,730,765
|
|
Equity investments in unconsolidated affiliates
|
|
|
5,042,721
|
|
|
|
|
|
577,973
|
|
|
(5,188,169
|
)
|
|
432,525
|
|
Other intangible assets, net
|
|
|
396,794
|
|
|
160,562
|
|
|
|
|
|
|
|
|
557,356
|
|
Goodwill
|
|
|
276,440
|
|
|
58,228
|
|
|
|
|
|
|
|
|
334,668
|
|
Other assets
|
|
|
483,253
|
|
|
|
|
|
447,380
|
|
|
(843,052
|
)
|
|
87,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
8,274,888
|
|
$
|
420,408
|
|
$
|
1,039,974
|
|
$
|
(6,091,275
|
)
|
$
|
3,643,995
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
139,566
|
|
$
|
10,464
|
|
$
|
34,997
|
|
$
|
(58,887
|
)
|
$
|
126,140
|
|
Revolving credit facility
|
|
|
|
|
|
|
|
|
20,000
|
|
|
|
|
|
20,000
|
|
Current portion of long-term debt
|
|
|
303,890
|
|
|
|
|
|
|
|
|
|
|
|
303,890
|
|
Other current liabilities
|
|
|
203,874
|
|
|
|
|
|
11,627
|
|
|
|
|
|
215,501
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
647,330
|
|
|
10,464
|
|
|
66,624
|
|
|
(58,887
|
)
|
|
665,531
|
|
Long-term debt
|
|
|
575,661
|
|
|
190,000
|
|
|
460,000
|
|
|
|
|
|
1,225,661
|
|
Convertible debentures
|
|
|
|
|
|
|
|
|
326,067
|
|
|
|
|
|
326,067
|
|
Other non-current liabilities
|
|
|
1,207,579
|
|
|
8,261
|
|
|
1,150
|
|
|
(843,052
|
)
|
|
373,938
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred shares issued by a subsidiary company
|
|
|
221,304
|
|
|
|
|
|
|
|
|
|
|
|
221,304
|
|
Common shares
|
|
|
4,977,653
|
|
|
211,683
|
|
|
1,286,399
|
|
|
(5,189,336
|
)
|
|
1,286,399
|
|
Accumulated other comprehensive income (loss)
|
|
|
17,253
|
|
|
|
|
|
|
|
|
|
|
|
17,253
|
|
Retained deficit
|
|
|
625,777
|
|
|
|
|
|
(1,100,266
|
)
|
|
|
|
|
(474,489
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Atlantic Power Corporation shareholders' equity
|
|
|
5,841,987
|
|
|
211,683
|
|
|
186,133
|
|
|
(5,189,336
|
)
|
|
1,050,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncontrolling interest
|
|
|
2,331
|
|
|
|
|
|
|
|
|
|
|
|
2,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity
|
|
|
5,844,318
|
|
|
211,683
|
|
|
186,133
|
|
|
(5,189,336
|
)
|
|
1,052,798
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
8,274,888
|
|
$
|
420,408
|
|
$
|
1,039,974
|
|
$
|
(6,091,275
|
)
|
$
|
3,643,995
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
15. Guarantees and condensed consolidating financial information (Continued)
ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
Three months ended September 30, 2012
(in thousands of U.S. dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
Subsidiaries
|
|
Curtis
Palmer
|
|
Atlantic
Power
|
|
Eliminations
|
|
Consolidated
Balance
|
|
Project revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total project revenue
|
|
$
|
150,006
|
|
$
|
4,660
|
|
$
|
|
|
$
|
(167
|
)
|
$
|
154,499
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
58,565
|
|
|
|
|
|
|
|
|
|
|
|
58,565
|
|
Project operations and maintenance
|
|
|
34,858
|
|
|
1,571
|
|
|
(466
|
)
|
|
(115
|
)
|
|
35,848
|
|
Depreciation and amortization
|
|
|
34,701
|
|
|
3,841
|
|
|
|
|
|
|
|
|
38,542
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
128,124
|
|
|
5,412
|
|
|
(466
|
)
|
|
(115
|
)
|
|
132,955
|
|
Project other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivative instruments
|
|
|
17,213
|
|
|
|
|
|
|
|
|
|
|
|
17,213
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
4,000
|
|
|
|
|
|
|
|
|
|
|
|
4,000
|
|
Interest expense, net
|
|
|
(1,409
|
)
|
|
(2,802
|
)
|
|
|
|
|
|
|
|
(4,211
|
)
|
Other income, net
|
|
|
(567
|
)
|
|
|
|
|
|
|
|
|
|
|
(567
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,237
|
|
|
(2,802
|
)
|
|
|
|
|
|
|
|
16,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project income
|
|
|
41,119
|
|
|
(3,554
|
)
|
|
466
|
|
|
(52
|
)
|
|
37,979
|
|
Administrative and other expenses (income):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Administration expense
|
|
|
4,174
|
|
|
|
|
|
2,135
|
|
|
|
|
|
6,309
|
|
Interest, net
|
|
|
20,374
|
|
|
|
|
|
5,456
|
|
|
|
|
|
25,829
|
|
Foreign exchange loss
|
|
|
4,474
|
|
|
|
|
|
3,185
|
|
|
|
|
|
7,659
|
|
Other Income (loss)
|
|
|
272
|
|
|
|
|
|
|
|
|
|
|
|
272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,293
|
|
|
|
|
|
10,776
|
|
|
|
|
|
40,069
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
11,826
|
|
|
(3,554
|
)
|
|
(10,310
|
)
|
|
(52
|
)
|
|
(2,090
|
)
|
Income tax expense
|
|
|
3,166
|
|
|
|
|
|
|
|
|
|
|
|
3,166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations
|
|
|
8,660
|
|
|
(3,554
|
)
|
|
(10,310
|
)
|
|
(52
|
)
|
|
(5,256
|
)
|
Net income from discontinued operations
|
|
|
773
|
|
|
|
|
|
|
|
|
|
|
|
773
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
9,433
|
|
|
(3,554
|
)
|
|
(10,310
|
)
|
|
(52
|
)
|
|
(4,483
|
)
|
Net income attributable to noncontrolling interest
|
|
|
2,963
|
|
|
|
|
|
|
|
|
|
|
|
2,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Atlantic Power Corporation
|
|
$
|
6,470
|
|
$
|
(3,554
|
)
|
$
|
(10,310
|
)
|
$
|
(52
|
)
|
$
|
(7,446
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
35
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
15. Guarantees and condensed consolidating financial information (Continued)
ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
Nine months ended September 30, 2012
(in thousands of U.S. dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
Subsidiaries
|
|
Curtis
Palmer
|
|
Atlantic
Power
|
|
Eliminations
|
|
Consolidated
Balance
|
|
Project revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total project revenue
|
|
$
|
440,689
|
|
$
|
23,583
|
|
$
|
|
|
$
|
(442
|
)
|
$
|
463,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
176,176
|
|
|
|
|
|
|
|
|
|
|
|
176,176
|
|
Project operations and maintenance
|
|
|
106,814
|
|
|
4,709
|
|
|
(206
|
)
|
|
(290
|
)
|
|
111,027
|
|
Depreciation and amortization
|
|
|
99,774
|
|
|
11,445
|
|
|
|
|
|
|
|
|
111,219
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
382,764
|
|
|
16,154
|
|
|
(206
|
)
|
|
(290
|
)
|
|
398,422
|
|
Project other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivative instruments
|
|
|
(40,953
|
)
|
|
|
|
|
|
|
|
|
|
|
(40,953
|
)
|
Equity in earnings of unconsolidated affiliates
|
|
|
12,420
|
|
|
|
|
|
|
|
|
|
|
|
12,420
|
|
Interest expense, net
|
|
|
(4,286
|
)
|
|
(8,345
|
)
|
|
(6
|
)
|
|
|
|
|
(12,637
|
)
|
Other income, net
|
|
|
(538
|
)
|
|
|
|
|
|
|
|
|
|
|
(538
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(33,357
|
)
|
|
(8,345
|
)
|
|
(6
|
)
|
|
|
|
|
(41,708
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Project income
|
|
|
24,568
|
|
|
(916
|
)
|
|
200
|
|
|
(152
|
)
|
|
23,700
|
|
Administrative and other expenses (income):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Administration expense
|
|
|
14,118
|
|
|
|
|
|
7,874
|
|
|
|
|
|
21,992
|
|
Interest, net
|
|
|
60,476
|
|
|
|
|
|
8,620
|
|
|
173
|
|
|
69,269
|
|
Foreign exchange loss
|
|
|
3,163
|
|
|
|
|
|
1,277
|
|
|
|
|
|
4,440
|
|
Other income (loss)
|
|
|
(5,728
|
)
|
|
|
|
|
|
|
|
|
|
|
(5,728
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72,029
|
|
|
|
|
|
17,771
|
|
|
173
|
|
|
89,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations before income taxes
|
|
|
(47,461
|
)
|
|
(916
|
)
|
|
(17,571
|
)
|
|
(325
|
)
|
|
(66,273
|
)
|
Income tax benefit
|
|
|
(19,077
|
)
|
|
|
|
|
1
|
|
|
|
|
|
(19,076
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations
|
|
|
(28,384
|
)
|
|
(916
|
)
|
|
(17,572
|
)
|
|
(325
|
)
|
|
(47,197
|
)
|
Income from discontinued operations, net of tax
|
|
|
1,444
|
|
|
|
|
|
|
|
|
|
|
|
1,444
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
(26,940
|
)
|
|
(916
|
)
|
|
(17,572
|
)
|
|
(325
|
)
|
|
(45,753
|
)
|
Net income attributable to noncontrolling interest
|
|
|
9,071
|
|
|
|
|
|
|
|
|
|
|
|
9,071
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to Atlantic Power Corporation
|
|
$
|
(36,011
|
)
|
$
|
(916
|
)
|
$
|
(17,572
|
)
|
$
|
(325
|
)
|
$
|
(54,824
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
36
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
15. Guarantees and condensed consolidating financial information (Continued)
ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF COMPREHENSIVE INCOME
Three and nine months ended September 30, 2012
(in thousands of U.S. dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2012
|
|
|
|
Guarantor
Subsidiaries
|
|
Curtis
Palmer
|
|
Atlantic
Power
|
|
Eliminations
|
|
Consolidated
Balance
|
|
Net income (loss)
|
|
$
|
6,470
|
|
$
|
(3,554
|
)
|
$
|
(10,310
|
)
|
$
|
(52
|
)
|
$
|
(7,446
|
)
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on hedging activities
|
|
|
(300
|
)
|
|
|
|
|
|
|
|
|
|
|
(300
|
)
|
Net amount reclassified to earnings
|
|
|
216
|
|
|
|
|
|
|
|
|
|
|
|
216
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses on derivatives
|
|
|
(84
|
)
|
|
|
|
|
|
|
|
|
|
|
(84
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments
|
|
|
19,301
|
|
|
|
|
|
|
|
|
|
|
|
19,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income, net of tax
|
|
|
19,217
|
|
|
|
|
|
|
|
|
|
|
|
19,217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
25,687
|
|
$
|
(3,554
|
)
|
$
|
(10,310
|
)
|
$
|
(52
|
)
|
$
|
11,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2012
|
|
|
|
Guarantor
Subsidiaries
|
|
Curtis
Palmer
|
|
Atlantic
Power
|
|
Eliminations
|
|
Consolidated
Balance
|
|
Net income (loss)
|
|
$
|
(36,011
|
)
|
$
|
(916
|
)
|
$
|
(17,572
|
)
|
$
|
(325
|
)
|
$
|
(54,824
|
)
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on hedging activities
|
|
|
(833
|
)
|
|
|
|
|
|
|
|
|
|
|
(833
|
)
|
Net amount reclassified to earnings
|
|
|
672
|
|
|
|
|
|
|
|
|
|
|
|
672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses on derivatives
|
|
|
(161
|
)
|
|
|
|
|
|
|
|
|
|
|
(161
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments
|
|
|
22,608
|
|
|
|
|
|
|
|
|
|
|
|
22,608
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income, net of tax
|
|
|
22,447
|
|
|
|
|
|
|
|
|
|
|
|
22,447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
(13,564
|
)
|
$
|
(916
|
)
|
$
|
(17,572
|
)
|
$
|
(325
|
)
|
$
|
(32,377
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
37
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
15. Guarantees and condensed consolidating financial information (Continued)
ATLANTIC POWER CORPORATION
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
Nine months ended September 30, 2012
(in thousands of U.S. dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
Subsidiaries
|
|
Curtis
Palmer
|
|
Atlantic
Power
|
|
Eliminations
|
|
Consolidated
Balance
|
|
Net cash provided by (used in) operating activities
|
|
$
|
(13,219
|
)
|
$
|
(1,907
|
)
|
$
|
139,242
|
|
$
|
|
|
$
|
124,116
|
|
Cash flows used in investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions and investments, net of cash acquired
|
|
|
193,155
|
|
|
|
|
|
(193,419
|
)
|
|
|
|
|
(264
|
)
|
Proceeds from sale of equity investments
|
|
|
27,925
|
|
|
|
|
|
|
|
|
|
|
|
27,925
|
|
Construction in progress
|
|
|
(336,153
|
)
|
|
|
|
|
|
|
|
|
|
|
(336,153
|
)
|
Change in restricted cash
|
|
|
(105,494
|
)
|
|
|
|
|
|
|
|
|
|
|
(105,494
|
)
|
Biomass development costs
|
|
|
(372
|
)
|
|
|
|
|
|
|
|
|
|
|
(372
|
)
|
Purchase of property, plant and equipment
|
|
|
(1,155
|
)
|
|
(17
|
)
|
|
|
|
|
|
|
|
(1,172
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(222,094
|
)
|
|
(17
|
)
|
|
(193,419
|
)
|
|
|
|
|
(415,530
|
)
|
Cash flows provided by financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of convertible debentures
|
|
|
|
|
|
|
|
|
130,000
|
|
|
|
|
|
130,000
|
|
Net proceeds from issuance of equity
|
|
|
|
|
|
|
|
|
67,692
|
|
|
|
|
|
67,692
|
|
Repayment for long-term debt
|
|
|
(12,050
|
)
|
|
|
|
|
|
|
|
|
|
|
(12,050
|
)
|
Deferred finance costs
|
|
|
(10,179
|
)
|
|
|
|
|
(15,160
|
)
|
|
|
|
|
(25,339
|
)
|
Proceeds from project-level debt
|
|
|
261,226
|
|
|
|
|
|
|
|
|
|
|
|
261,226
|
|
Payments for revolving credit facility borrowings
|
|
|
(30,800
|
)
|
|
|
|
|
(30,000
|
)
|
|
|
|
|
(60,800
|
)
|
Proceeds from revolving credit facility borrowings
|
|
|
22,800
|
|
|
|
|
|
|
|
|
|
|
|
22,800
|
|
Dividends paid
|
|
|
(9,802
|
)
|
|
|
|
|
(98,350
|
)
|
|
|
|
|
(108,152
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
221,195
|
|
|
|
|
|
54,182
|
|
|
|
|
|
275,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
(14,118
|
)
|
|
(1,924
|
)
|
|
5
|
|
|
|
|
|
(16,037
|
)
|
Less cash at discontinued operation
|
|
|
(1,742
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,742
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
58,370
|
|
|
(15
|
)
|
|
2,296
|
|
|
|
|
|
60,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
42,510
|
|
$
|
(1,939
|
)
|
$
|
2,301
|
|
$
|
|
|
$
|
42,872
|
|
|
|
|
|
|
|
|
|
|
|
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38
Table of Contents
FORWARD-LOOKING INFORMATION
Certain statements in this Quarterly Report on Form 10-Q constitute "forward-looking statements" within the meaning
of the Private Securities Litigation Reform Act of 1995. Forward-looking statements generally can be identified by the use of forward-looking terminology such as "outlook," "objective," "may," "will,"
"expect," "intend," "estimate," "anticipate," "believe," "should," "plans," "continue," or similar expressions suggesting future outcomes or events. Examples of such statements in this Quarterly
Report on Form 10-Q include, but are not limited to, statements with respect to the following:
-
-
the amount of distributions expected to be received from the projects;
-
-
our ability to generate sufficient amounts of cash and cash equivalents to maintain our operations and meet obligations as
they become due;
-
-
expectations regarding completion of construction of certain projects; and
-
-
the impact of legislative, regulatory, competitive and technological changes.
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. 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.
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. In addition, a number of factors could cause actual results to differ materially from the
results discussed in the forward-looking statements, including, but not limited to, the factors discussed under "Risk Factors" included in the filings we make from time to time with the SEC. Our
business is both highly competitive and subject to various risks.
These
risks include, without limitation:
-
-
general economic conditions, including exchange rate fluctuations;
-
-
reductions in revenue, which could be substantial, 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 dependence of our projects on third-party suppliers;
-
-
the dependence of our windpower projects on suitable wind and associated conditions;
-
-
the adequacy of our insurance coverage;
-
-
the impact of significant environmental and other regulations on our projects;
-
-
increased competition, including for acquisitions;
-
-
our limited control over the operation of certain minority owned projects;
-
-
construction risks; and
-
-
labor disruptions.
39
Table of Contents
Material
factors or assumptions that were applied in drawing a conclusion or making an estimate set out in the forward-looking information include third party projections of regional
fuel and electric capacity and energy prices or cash flows that are based on assumptions about future economic conditions and courses of action. Although the forward-looking statements contained in
this Quarterly Report on Form 10-Q are based upon what are believed to be reasonable assumptions, investors cannot be assured that actual results will be consistent with these
forward-looking statements, and the differences may be material. Certain statements included in this Quarterly Report on Form 10-Q may be considered "financial outlook" for the
purposes of applicable securities laws, and such financial outlook may not be appropriate for purposes other than this Quarterly Report on Form 10-Q. These forward-looking
statements are made as of the date of this Form 10-Q, except as expressly required by applicable law, we assume no obligation to update or revise them to reflect new events or
circumstances.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of the financial condition and results of operations of Atlantic Power 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. All dollar amounts
discussed below are in thousands of U.S. dollars, unless otherwise stated. The interim financial statements have been prepared in accordance with GAAP.
Overview of Our Business
Atlantic Power owns and operates a diverse fleet of power generation and infrastructure assets in the United States and Canada. Our
power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements ("PPAs"), which seek to minimize exposure to
changes in commodity prices. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 3,351 megawatts ("MW") in which our aggregate ownership
interest is approximately 2,118 MW. Our current portfolio consists of interests in 30 operational power generation projects across 11 states in the United States and two provinces in Canada and a
500-kilovolt 84-mile electric transmission line located in California. In addition, we have one 53 MW biomass project under construction in Georgia and one approximately 300 MW
wind project under construction in Oklahoma. We also own a majority interest in Rollcast Energy Inc., a biomass power plant developer in North Carolina. Twenty-three of our projects are wholly
owned subsidiaries.
We
sell the capacity and energy from our power generation projects under PPAs with a number of utilities and other parties. Under the PPAs, which have expiration dates ranging from 2012
to 2037, we receive payments for electric energy delivered to our customers (known as energy payments), in addition to payments for electric generating capacity (known as capacity payments). We also
sell steam from a number of our projects to industrial and commercial purchasers under steam sales agreements. The transmission system rights associated with our power transmission project entitle us
to payments indirectly from the utilities that make use of the transmission line.
Our
power generation projects generally have long-term fuel supply agreements, typically accompanied by fuel transportation arrangements. In most cases, the term of the fuel
supply and transportation arrangements corresponds to the term of the relevant PPAs, Many of the PPAs and steam sales agreements provide for the indexing or pass-through of fuel costs to
our customers. In cases where there is not an effective pass-through of fuel costs, we often attempt to mitigate the market price risk of changing commodity costs through the use of
financial hedging strategies.
40
Table of Contents
We
directly operate and maintain more than half of our power generation fleet. We, and the manager of our equity investments, also partner with recognized leaders in the independent
power industry to operate and maintain our other projects, including Caithness Energy, LLC, Colorado Energy Management, 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.
We
revised our reportable business segments during the fourth quarter of 2011 upon completion of the Partnership acquisition. The new operating segments are Northeast, Northwest,
Southeast, Southwest and Un-allocated Corporate. Our financial results for the nine months ended September 30, 2012 have been presented to reflect these changes in our operating
segments.
RECENT DEVELOPMENTS
In connection with the continued evolution of the Company's strategy to focus on late-stage development and construction projects, and
the possible disposition of certain projects, including our Florida projects, on November 2, 2012, we amended the senior credit facility in order to change certain financial and leverage ratio
covenants and obtained certain waivers from our lenders in connection with certain of our projects. See Item 5. Other Information to this quarterly report on Form 10-Q for
additional information.
On January 31, 2012, Atlantic Oklahoma Wind, LLC ("Atlantic OW"), a Delaware limited liability company and a wholly owned
subsidiary of Atlantic Power, entered into a purchase and sale agreement with Apex Wind Energy Holdings, LLC, a Delaware limited liability company ("Apex"), pursuant to which Atlantic OW
acquired a 51% interest in Canadian Hills Wind, LLC, an Oklahoma limited liability company ("Canadian Hills") for a nominal sum. Canadian Hills is the owner of a 298.45 MW wind energy project
under construction in the State of Oklahoma. Canadian Hills executed power PPAs for all of its output with Southwestern Electric Power Company (201.25 MW), Oklahoma Municipal Power Authority (49.2
MW), and Grand River Dam Authority (48 MW).
On
March 30, 2012, we completed the purchase of an additional 48% interest in Canadian Hills for a nominal amount, bringing our total interest in the project to 99%. Apex retained
a 1% interest in the project. At the time, we also closed a $310 million non-recourse, project-level
construction financing facility for the project. The facility includes a $290 million construction loan and a $20 million 5-year letter of credit facility. Proceeds from the
construction loan were used, in part, to repay Atlantic Power $29.3 million in member loans that were made to the project to fund construction prior to closing the construction financing
facility. In connection with the closing of the construction financing facility, we committed to invest additional equity to cover the balance of the construction and development costs. We funded this
equity commitment with the net proceeds from our July 5, 2012 public offering of common shares and convertible unsecured subordinated debentures. The net proceeds of our equity contribution was
approximately $190.0 million. The acquisition of Canadian Hills was accounted for as an asset purchase and is consolidated in our consolidated balance sheet at September 30, 2012.
On
October 31, 2012, the Canadian Hills project entered into an equity contribution agreement with four entities for the commitment of a tax equity investment in the project
totalling $225.0 million in exchange for Class B equity interests in Canadian Hills which is to be funded on date of commercial operations. We are actively pursuing additional tax equity
investors to fund the remaining estimated $47.0 million needed to pay down the existing construction loan. If we are unable to subscribe additional investors, we will fund the remaining portion
with either cash on hand or proceeds from our
41
Table of Contents
senior
credit facility and will become an additional tax equity investor in the project owning the remaining Class B equity interests in Canadian Hills.
On August 8, 2012, we announced the details of our Dividend Reinvestment Plan ("DRIP"). The DRIP allows eligible holders of
common shares to reinvest their cash dividends to acquire additional common shares of Atlantic Power at a 3% discount to market price.
On July 5, 2012, we closed a public offering of 5,567,177 common shares, at a purchase price of $12.76 per common share and
Cdn$13.10 per common share, for aggregate net proceeds from the common share offering, after deducting the underwriting discounts and expenses, of
approximately, $67.7 million. We also issued, in a public offering, $130.0 million aggregate principal amount of 5.75% convertible unsecured subordinated debentures due June 30,
2019, (the "2012 Debentures"), after deducting the underwriting discounts and offering expenses, for net proceeds of $124.0 million. The 2012 Debentures pay interest semi-annually
on June 30 and December 30 of each year beginning December 30, 2012. The 2012 Debentures are convertible into our common shares at an initial conversion rate of 57.9710 common
shares per $1,000 principal amount of debentures, subject to anti-dilution adjustments in certain circumstances. The 2012 Debentures may not be redeemed prior to June 30, 2015
(except in limited circumstances). After June 30, 2015, the 2012 Debentures may be redeemed by is, in whole or in part from time to time, upon certain conditions. Upon a change of control of
the company, each holder may require that we purchase the 2012 Debentures upon the conditions set forth in the indenture governing the debentures. We used the net proceeds from the offerings to fund
our equity commitment in Canadian Hills Wind, LLC.
In February 2011, we filed a rate application with the Federal Energy Regulatory Commission ("FERC") to establish Path 15's revenue
requirement at $30.3 million for the 2011-2013 period. On March 7, 2012, Path 15 filed a formal settlement agreement establishing a revenue requirement at
$28.8 million with the Administrative Law Judge for review and certification to FERC for approval. The settlement was approved by the FERC on May 23, 2012. The new revenue requirement
maintains the project's 13.5% regulated return on equity and will allow Path 15 to continue to make distributions consistent with our expectations through the 2013 rate period.
During
the three months ended September 30, 2012, we classified our Path 15 project as a business held for sale based on our plan to sell the project within the next twelve
months. Accordingly, the assets and liabilities of Path 15 have been classified separately as held for sale in the consolidated balance sheet at September 30, 2012 and the project's net income
is recorded as income from discontinued operations, net of tax in the statement of operations for the three and nine months ended September 30, 2012 and 2011.
On August 6, 2012, we entered into a purchase and sale agreement for the sale of our 50% ownership interest in the Badger Creek
project. On September 4, 2012, the transaction closed and we received gross proceeds of $3.7 million. During the second quarter of 2012, we recorded an impairment charge of
$3.0 million which was recorded in equity in earnings from unconsolidated affiliates in the consolidated statements of operations.
42
Table of Contents
On February 16, 2012, we entered into an agreement with Primary Energy Recycling Corporation ("Primary Energy" or "PERC"),
whereby PERC agreed to purchase our 7,462,830.33 common membership interests in Primary Energy Recycling Holdings, LLC ("PERH") (14.3% of PERH total interests) for approximately
$24.2 million, plus a management agreement termination fee of approximately $6.0 million, for a total sale price of $30.2 million. The transaction closed in May 2012 and we
recorded a $0.6 million gain on sale of our equity investment.
As previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011, Chambers
filed suit against DuPont de Nemours & Company ("DuPont") for breach of the energy services agreement related to unpaid amounts associated with disputed price change calculations for
electricity. On April 25, 2012, the court issued its written opinion which ordered DuPont to pay Chambers a total of approximately $15.7 million. This amount represents DuPont's
electricity underpayments from January 2003 through June 2009, and interest through July 22, 2011. The court also ordered that from July 1, 2009 going forward, the pricing methodology
should be calculated in accordance with the court's prior ruling on summary judgment. In June 2012, Dupont paid the Chambers project the true-up settlement of this new pricing methodology
for the period July 1, 2009 through September 30, 2011 of approximately $9.0 million. On July 13, 2012, DuPont filed an appeal of this ruling and was granted a stay on
paying any damages on the electricity under payment from January 2003 through June 2009 including interest.
OUR POWER PROJECTS
The table on the following page outlines our portfolio of power generating and transmission assets in operation and under construction
as of November 1, 2012, including our interest in each facility. Management believes the portfolio is well diversified in terms of
electricity and steam buyers, fuel type, regulatory jurisdictions and regional power pools, thereby partially mitigating exposure to market, regulatory or environmental conditions specific to any
single region.
43
Table of Contents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project
|
|
Location
|
|
Type
|
|
MW
|
|
Economic
Interest
|
|
Net
MW
|
|
Primary Electric Purchasers
|
|
Power
Contract
Expiry
|
|
Customer
Credit
Rating
(S&P)
(3)
|
|
Northeast Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cadillac
|
|
Michigan
|
|
Biomass
|
|
|
40
|
|
|
100.00
|
%
|
|
40
|
|
Consumers Energy
|
|
|
2028
|
|
BBB-
|
|
Chambers
|
|
New Jersey
|
|
Coal
|
|
|
262
|
|
|
40.00
|
%
|
|
89
|
|
Atlantic City Elec.
|
|
|
2024
|
|
BBB+
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
|
|
DuPont
|
|
|
2024
|
|
A
|
|
Kenilworth
|
|
New Jersey
|
|
Natural Gas
|
|
|
30
|
|
|
100.00
|
%
|
|
30
|
|
Merck, & Co., Inc.
|
|
|
2012
|
(1)
|
AA
|
|
Curtis Palmer
|
|
New York
|
|
Hydro
|
|
|
60
|
|
|
100.00
|
%
|
|
60
|
|
Niagara Mohawk Power Corperation
|
|
|
2027
|
|
A-
|
|
Selkirk
|
|
New York
|
|
Natural Gas
|
|
|
345
|
|
|
17.70
|
%
|
|
15
|
|
Merchant
|
|
|
N/A
|
|
N/R
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49
|
|
Consolidated Edison
|
|
|
2014
|
|
A-
|
|
Calstock
|
|
Ontario
|
|
Biomass
|
|
|
35
|
|
|
100.00
|
%
|
|
35
|
|
Ontario Electricity Financial Corp
|
|
|
2020
|
|
AA-
|
|
Kapuskasing
|
|
Ontario
|
|
Natural Gas
|
|
|
40
|
|
|
100.00
|
%
|
|
40
|
|
Ontario Electricity Financial Corp
|
|
|
2017
|
|
AA-
|
|
Nipigon
|
|
Ontario
|
|
Natural Gas
|
|
|
40
|
|
|
100.00
|
%
|
|
40
|
|
Ontario Electricity Financial Corp
|
|
|
2022
|
|
AA-
|
|
North Bay
|
|
Ontario
|
|
Natural Gas
|
|
|
40
|
|
|
100.00
|
%
|
|
40
|
|
Ontario Electricity Financial Corp
|
|
|
2017
|
|
AA-
|
|
Tunis
|
|
Ontario
|
|
Natural Gas
|
|
|
43
|
|
|
100.00
|
%
|
|
43
|
|
Ontario Electricity Financial Corp
|
|
|
2014
|
|
AA-
|
|
Southeast Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Auburndale
|
|
Florida
|
|
Natural Gas
|
|
|
155
|
|
|
100.00
|
%
|
|
155
|
|
Progress Energy Florida
|
|
|
2013
|
|
BBB+
|
|
Lake
|
|
Florida
|
|
Natural Gas
|
|
|
121
|
|
|
100.00
|
%
|
|
121
|
|
Progress Energy Florida
|
|
|
2013
|
|
BBB+
|
|
Pasco
|
|
Florida
|
|
Natural Gas
|
|
|
121
|
|
|
100.00
|
%
|
|
121
|
|
Tampa Electric Company
|
|
|
2018
|
|
BBB+
|
|
Orlando
|
|
Florida
|
|
Natural Gas
|
|
|
129
|
|
|
50.00
|
%
|
|
46
|
|
Progress Energy Florida
|
|
|
2023
|
|
BBB+
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
Reedy Creek Improvement District
(2)
|
|
|
2013
|
|
A-
|
|
Piedmont
|
|
Georgia
|
|
Biomass
|
|
|
54
|
|
|
98.0
|
%
|
|
53
|
|
Georgia Power
|
|
|
2032
|
|
A
|
|
Northwest Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mamquam
|
|
British Columbia
|
|
Hydro
|
|
|
50
|
|
|
100.00
|
%
|
|
50
|
|
British Columbia Hydro and Power Authority
|
|
|
2027
|
|
AAA
|
|
Moresby Lake
|
|
British Columbia
|
|
Hydro
|
|
|
6
|
|
|
100.00
|
%
|
|
6
|
|
British Columbia Hydro and Power Authority
|
|
|
2022
|
|
AAA
|
|
Williams Lake
|
|
British Columbia
|
|
Biomass
|
|
|
66
|
|
|
100.00
|
%
|
|
66
|
|
British Columbia Hydro and Power Authority
|
|
|
2018
|
|
AAA
|
|
Idaho Wind
|
|
Idaho
|
|
Wind
|
|
|
183
|
|
|
27.56
|
%
|
|
50
|
|
Idaho Power Co.
|
|
|
2030
|
|
BBB
|
|
Rockland Wind Project
|
|
Idaho
|
|
Wind
|
|
|
80
|
|
|
30.00
|
%
|
|
24
|
|
Idaho Power Co.
|
|
|
2036
|
|
BBB
|
|
Frederickson
|
|
Washington
|
|
Natural Gas
|
|
|
250
|
|
|
50.15
|
%
|
|
125
|
|
Benton Co. PUD, Grays Harbor PUD,
Franklin Co. PUD
|
|
|
2022
|
|
A
|
|
Koma Kulshan
|
|
Washington
|
|
Hydro
|
|
|
13
|
|
|
49.80
|
%
|
|
7
|
|
Puget Sound Energy
|
|
|
2037
|
|
BBB
|
|
Southwest Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Naval Station
|
|
California
|
|
Natural Gas
|
|
|
47
|
|
|
100.00
|
%
|
|
47
|
|
San Diego Gas & Electric
|
|
|
2019
|
|
A
|
|
Naval Training Center
|
|
California
|
|
Natural Gas
|
|
|
25
|
|
|
100.00
|
%
|
|
25
|
|
San Diego Gas & Electric
|
|
|
2019
|
|
A
|
|
North Island
|
|
California
|
|
Natural Gas
|
|
|
40
|
|
|
100.00
|
%
|
|
40
|
|
San Diego Gas & Electric
|
|
|
2019
|
|
A
|
|
Oxnard
|
|
California
|
|
Natural Gas
|
|
|
49
|
|
|
100.00
|
%
|
|
49
|
|
Southern California Edison
|
|
|
2020
|
|
BBB+
|
|
Path 15
|
|
California
|
|
Transmssion
|
|
|
N/A
|
|
|
100.00
|
%
|
|
N/A
|
|
California Utilities via CAISO
|
|
|
N/A
|
|
BBB+ to A
|
|
Greeley
|
|
Colorado
|
|
Natural Gas
|
|
|
72
|
|
|
100
|
%
|
|
72
|
|
Public Service Company of Colorado
|
|
|
2013
|
|
A-
|
|
Manchief
|
|
Colorado
|
|
Natural Gas
|
|
|
300
|
|
|
100
|
%
|
|
300
|
|
Public Service Company of Colorado
|
|
|
2022
|
|
A-
|
|
Morris
|
|
Illinois
|
|
Natural Gas
|
|
|
177
|
|
|
100
|
%
|
|
77
|
|
Merchant
|
|
|
N/A
|
|
N/R
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100
|
|
Equistar Chemicals, LP
|
|
|
2023
|
|
B+
|
|
Delta-Person
|
|
New Mexico
|
|
Natural Gas
|
|
|
132
|
|
|
40.0
|
%
|
|
53
|
|
Public Service Company of New Mexico
|
|
|
2020
|
|
BBB-
|
|
Canadian Hills
|
|
Oklahoma
|
|
Wind
|
|
|
300
|
|
|
99.0
|
%
|
|
200
|
|
Southwestern Electric Power Company
|
|
|
2032
|
|
BBB
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49
|
|
Oklahoma Municipal Power Authority
|
|
|
2037
|
|
N/R
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48
|
|
Grand River Dam Authority
|
|
|
2032
|
|
N/R
|
|
Gregory
|
|
Texas
|
|
Natural Gas
|
|
|
400
|
|
|
17.10
|
%
|
|
59
|
|
Fortis Energy Marketing & Trading
|
|
|
2013
|
|
A-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
Sherwin Alumina
|
|
|
2020
|
|
N/R
|
|
-
(1)
-
The
Kenilworth PPA, which expired on July 31, 2012, was extended on a month-to month basis by agreement with the purchaser
through November 30, 2012. We are currently in negotiations with the purchaser regarding the possible renewal of the PPA.
-
(2)
-
Upon
the expiry of the Reedy Creek PPA, the associated capacity and energy will be sold to PEF under the terms of the current agreement.
-
(3)
-
Our
customers are generally large utilities and other parties with investment-grade credit ratings. Customers that have assigned ratings at
the top end of the range have, in the opinion of the rating agency, the strongest capability for payment of debt or payment of claims, while customers at the bottom end of the range have the weakest
capacity. Agency ratings are subject to change, and there can be no assurance that a ratings agency will continue to rate the customers, and/or maintain their current ratings. A security rating is not
a recommendation to buy, sell or hold securities, it may be subject to revision or withdrawal at any time by the rating agency, and each rating should be evaluated independently of any other rating.
We cannot predict the effect that a change in the ratings of the customers will have on their liquidity or their ability to pay their debts.
44
Table of Contents
Consolidated Results of Operations
The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended
September 30, 2012 and 2011. 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,
|
|
(in thousands of U.S. dollars, except as otherwise stated)
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
Project revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
$
|
43,804
|
|
$
|
4,933
|
|
$
|
156,632
|
|
$
|
14,498
|
|
Southeast
|
|
|
48,194
|
|
|
39,661
|
|
|
137,406
|
|
|
121,747
|
|
Northwest
|
|
|
14,959
|
|
|
|
|
|
46,923
|
|
|
|
|
Southwest
|
|
|
47,734
|
|
|
|
|
|
121,674
|
|
|
|
|
Un-allocated Corporate
|
|
|
(192
|
)
|
|
101
|
|
|
1,195
|
|
|
238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
154,499
|
|
|
44,695
|
|
|
463,830
|
|
|
136,483
|
|
Project expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
|
47,954
|
|
|
3,667
|
|
|
145,386
|
|
|
10,632
|
|
Southeast
|
|
|
35,298
|
|
|
27,807
|
|
|
97,976
|
|
|
86,742
|
|
Northwest
|
|
|
13,205
|
|
|
|
|
|
43,297
|
|
|
|
|
Southwest
|
|
|
34,419
|
|
|
|
|
|
100,831
|
|
|
|
|
Un-allocated Corporate
|
|
|
2,079
|
|
|
348
|
|
|
10,932
|
|
|
1,151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
132,955
|
|
|
31,822
|
|
|
398,422
|
|
|
98,525
|
|
Project other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
|
9,547
|
|
|
(100
|
)
|
|
(45,078
|
)
|
|
(892
|
)
|
Southeast
|
|
|
7,940
|
|
|
(10,512
|
)
|
|
9,771
|
|
|
(11,715
|
)
|
Northwest
|
|
|
(1,072
|
)
|
|
(562
|
)
|
|
(736
|
)
|
|
(897
|
)
|
Southwest
|
|
|
582
|
|
|
481
|
|
|
(5,132
|
)
|
|
1,779
|
|
Un-allocated Corporate
|
|
|
(562
|
)
|
|
|
|
|
(533
|
)
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,435
|
|
|
(10,693
|
)
|
|
(41,708
|
)
|
|
(11,722
|
)
|
Total project income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
|
5,397
|
|
|
1,166
|
|
|
(33,832
|
)
|
|
2,974
|
|
Southeast
|
|
|
20,836
|
|
|
1,342
|
|
|
49,201
|
|
|
23,290
|
|
Northwest
|
|
|
682
|
|
|
(562
|
)
|
|
2,890
|
|
|
(897
|
)
|
Southwest
|
|
|
13,897
|
|
|
481
|
|
|
15,711
|
|
|
1,779
|
|
Un-allocated Corporate
|
|
|
(2,833
|
)
|
|
(247
|
)
|
|
(10,270
|
)
|
|
(910
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37,979
|
|
|
2,180
|
|
|
23,700
|
|
|
26,236
|
|
Administrative and other expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Administration
|
|
|
6,309
|
|
|
11,839
|
|
|
21,992
|
|
|
20,379
|
|
Interest, net
|
|
|
25,829
|
|
|
3,337
|
|
|
69,269
|
|
|
10,815
|
|
Foreign exchange gain
|
|
|
7,659
|
|
|
21,576
|
|
|
4,440
|
|
|
20,383
|
|
Other income, net
|
|
|
272
|
|
|
|
|
|
(5,728
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total administrative and other expenses
|
|
|
40,069
|
|
|
36,752
|
|
|
89,973
|
|
|
51,577
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations before income taxes
|
|
|
(2,090
|
)
|
|
(34,572
|
)
|
|
(66,273
|
)
|
|
(25,341
|
)
|
Income tax expense (benefit)
|
|
|
3,166
|
|
|
(5,323
|
)
|
|
(19,076
|
)
|
|
(12,900
|
)
|
|
|
|
|
|
|
|
|
|
|
Net loss from continuing operations
|
|
|
(5,256
|
)
|
|
(29,249
|
)
|
|
(47,197
|
)
|
|
(12,441
|
)
|
Income from discontinued operations, net of tax
|
|
|
773
|
|
|
1,271
|
|
|
1,444
|
|
|
3,514
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
(4,483
|
)
|
|
(27,978
|
)
|
|
(45,753
|
)
|
|
(8,927
|
)
|
Net income (loss) attributable to noncontrolling interest
|
|
|
2,963
|
|
|
(78
|
)
|
|
9,071
|
|
|
(349
|
)
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to Atlantic Power Corporation shareholders
|
|
$
|
(7,446
|
)
|
$
|
(27,900
|
)
|
$
|
(54,824
|
)
|
$
|
(8,578
|
)
|
|
|
|
|
|
|
|
|
|
|
45
Table of Contents
Consolidated Overview
We have five reportable segments: Northeast, Southeast, Northwest, Southwest and Un-allocated Corporate. The consolidated
results of operations are discussed below by reportable segment. The consolidated results of operations for the three and nine months ended September 30, 2012 include the results of operations
from the Partnership, which was acquired on November 5, 2011.
Project
income is the primary GAAP measure of our operating results and is discussed in "Segment Analysis" below. In addition, an analysis of non-project expenses impacting
our results is set out in "Un-allocated Corporate" below.
Significant
non-cash items, which are subject to potentially significant fluctuations, include: (1) the change in fair value of certain derivative financial
instruments revalued at each balance sheet date (see "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information); (2) the non-cash impact
of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of our Canadian dollar denominated obligations; and (3) the related deferred income tax expense (benefit)
associated with these non-cash items.
Cash
Available for Distribution was $28.3 million and $27.0 million for the three months ended September 30, 2012 and 2011, respectively. Cash Available for
Distribution was $101.1 million and $61.6 million for the nine months ended September, 2012 and 2011, respectively. Cash Available for Distribution is a non-GAAP financial
measure that we believe is a relevant supplemental measure of our ability to pay dividends to our shareholders. The most directly comparable GAAP measure is Cash flow from operating activities. For a
reconciliation of Cash Available for Distribution to Cash flow from operating activities, see "Supplementary Non-GAAP Financial Information" and "Cash Available for Distribution".
Loss
from continuing operations before income taxes for the three months ended September 30, 2012 and 2011 was $(2.1) million and $(34.6) million, respectively. Loss from
continuing operations before income taxes for the nine months ended September 30, 2012 and 2011 was $(66.3) million and $(25.3) million, respectively. See "Segment Analysis" below for
additional information.
Segment Analysis
The following table summarizes project income (loss) for our Northeast segment for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
Northeast
|
|
|
|
|
|
|
|
|
Project income
|
|
$
|
5,397
|
|
$
|
1,166
|
|
Not Meaningful ("NM")
|
Three months ended September 30, 2012 compared with three months ended September 30, 2011
Project income for the three months ended September 30, 2012 increased $4.2 million from the comparable 2011 period
primarily due to:
-
-
project income from the newly acquired Nipigon project of $2.8 million resulting primarily from a positive
$2.1 million non-cash change in the fair value of gas purchase agreements that were accounted for as derivatives; and
-
-
increased project income of $1.9 million at Chambers due to lower operations and maintenance expenses. The project
had a forced outage in July 2011.
46
Table of Contents
These
increases were partially offset by:
-
-
a project loss from the newly acquired Curtis Palmer project of $3.6 million due to a seasonal decline in revenue.
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
Northeast
|
|
|
|
|
|
|
|
|
Project income (loss)
|
|
$
|
(33,832
|
)
|
$
|
2,974
|
|
NM
|
Nine months ended September 30, 2012 compared with nine months ended September 30, 2011
Project income (loss) for the nine months ended September 30, 2012 decreased $36.8 million from the comparable 2011
period primarily due to:
-
-
a project loss of $52.2 million from the newly acquired North Bay, Kapuskasing and Nipigon projects. The project
income (loss)for these projects was impacted by a negative $45.3 million non-cash change in the fair value of gas purchase agreements that were accounted for as derivatives.
These
decreases were partially offset by:
-
-
project income from the newly acquired Tunis project of $4.9 million;
-
-
increased project income of $4.0 million at Chambers due to the collection of the $3.6 million DuPont
partial settlement associated with the dispute of the electricity price calculation under its PPA and lower operations and maintenance expense; and
-
-
increased project income of $8.2 million at Selkirk attributable to lower operations and maintenance costs, higher
capacity revenue and a positive $3.4 million non-cash change in the fair value of gas supply agreements from the comparable 2011 period.
Southeast
The following table summarizes project income for our Southeast segment for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
Southeast
|
|
|
|
|
|
|
|
|
Project income
|
|
$
|
20,836
|
|
$
|
1,342
|
|
NM
|
Three months ended September 30, 2012 compared with three months ended September 30, 2011
Project income for the three months ended September 30, 2012 increased $19.5 million from the comparable 2011 period
primarily due to:
-
-
increased project income of $7.4 million at Piedmont attributable to an increase of $7.4 million related to
the non-cash change in fair value of derivative instruments associated with its interest rate swaps;
-
-
increased project income of $7.2 million at Auburndale primarily attributable to an increase of $4.5 million
related to the non-cash change in fair value of derivative instruments associated with its natural gas swaps as well as higher dispatch than the comparable 2011 period; and
47
Table of Contents
-
-
increased project income of $5.0 million at Lake primarily attributable to an increase of $4.5 million
related to the non-cash change in fair value of derivative instruments associated with its natural gas swaps.
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
|
Southeast
|
|
|
|
|
|
|
|
|
|
|
Project income
|
|
$
|
49,201
|
|
$
|
23,290
|
|
|
111
|
%
|
Nine months ended September 30, 2012 compared with nine months ended September 30, 2011
Project income for the nine months ended September 30, 2012 increased $25.9 million or 111% from the comparable 2011
period primarily due to:
-
-
increased project income of $9.0 million at Auburndale primarily attributable to an increase of $4.5 million
related to the non-cash change in fair value of derivative instruments associated with its natural gas swaps as well as higher dispatch than the comparable 2011 period;
-
-
increased project income of $8.4 million at Piedmont attributable to an increase of $8.4 million related to
the non-cash change in fair value of derivative instruments associated with its natural gas swaps; and
-
-
increased project income of $7.6 million at Lake primarily attributable to an increase of $6.6 million
related to the non-cash change in fair value of derivative instruments associated with its natural gas swaps.
Northwest
The following table summarizes project income (loss) for our Northwest segment for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
Northwest
|
|
|
|
|
|
|
|
|
Project income (loss)
|
|
$
|
682
|
|
$
|
(562
|
)
|
NM
|
Three months ended September 30, 2012 compared with three months ended September 30, 2011
Project income (loss) for the three months ended September 30, 2012 increased $1.2 million from the comparable 2011
period primarily due to:
-
-
project income of $1.8 million from the newly acquired Mamquam project.
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
Northwest
|
|
|
|
|
|
|
|
|
Project income (loss)
|
|
$
|
2,890
|
|
$
|
(897
|
)
|
NM
|
48
Table of Contents
Nine months ended September 30, 2012 compared with nine months ended September 30, 2011
Project income (loss) for the nine months ended September 30, 2012 increased $3.8 million from the comparable 2011 period
primarily due to:
-
-
project income of $5.7 million from the newly acquired Mamquam project.
The
increase was partially offset by:
-
-
project loss of $1.4 million from the newly acquired Williams Lake project resulting from additional amortization
associated with the intangible assets resulting from the acquisition of the Partnership.
Southwest
The following table summarizes project income for our Southwest segment for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
Southwest
|
|
|
|
|
|
|
|
|
Project Income
|
|
$
|
13,897
|
|
$
|
481
|
|
NM
|
Three months ended September 30, 2012 compared with three months ended September 30, 2011
Project income for the three months ended September 30, 2012 increased $13.4 million from the comparable 2011 period
primarily due to:
-
-
project income of $6.9 million from the newly acquired Naval Station, Naval Training Center and North Island
projects; and
-
-
project income of $4.4 million from the newly acquired Oxnard project.
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
Southwest
|
|
|
|
|
|
|
|
|
Project Income
|
|
$
|
15,711
|
|
$
|
1,779
|
|
NM
|
Nine months ended September 30, 2012 compared with nine months ended September 30, 2011
Project income for the nine months ended September 30, 2012 increased $13.9 million from the comparable 2011 period
primarily due to:
-
-
project income of $5.2 million from the newly acquired Morris project;
-
-
project income of $3.5 million from the newly acquired Manchief project; and
-
-
project income of $3.3 million from the newly acquired Oxnard project.
These
increases were partially offset by:
-
-
decreased project income of $2.9 million at Badger Creek which recorded a $3.0 million impairment charge in
the second quarter of 2012 and was sold in the third quarter of 2013; and
-
-
decreased project income of $2.5 million at Gregory attributable to higher operations and maintenance costs due to
a planned outage during the first quarter of 2012 that was longer than anticipated.
49
Table of Contents
The following table summarizes the results of operations for the Un-allocated Corporate segment for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
|
Un-Allocated Corporate
|
|
|
|
|
|
|
|
|
|
|
Project loss
|
|
$
|
(2,833
|
)
|
$
|
(247
|
)
|
|
NM
|
|
Administration
|
|
|
6,309
|
|
|
11,839
|
|
|
-47
|
%
|
Interest, net
|
|
|
25,829
|
|
|
3,337
|
|
|
NM
|
|
Foreign exchange loss (gain)
|
|
|
7,659
|
|
|
21,576
|
|
|
-65
|
%
|
Other income, net
|
|
|
272
|
|
|
|
|
|
NM
|
|
|
|
|
|
|
|
|
|
Total administrative and other expenses
|
|
|
40,069
|
|
|
36,752
|
|
|
9
|
%
|
Income tax expense (benefit)
|
|
|
3,166
|
|
|
(5,323
|
)
|
|
-159
|
%
|
Three months ended September 30, 2012 compared with three months ended September 30, 2011
Total project loss for the three months ended September 30, 2012 increased $2.6 million from the comparable 2011 period
primarily due to higher general and administrative expenses associated with operating the newly acquired Partnership projects.
Total
administrative and other expenses for the three months ended September 30, 2012 increased $3.3 million from the comparable 2011 period primarily due
to:
-
-
increased interest expense of $22.5 million primarily due to the issuance of the $130 million principal
amount of convertible debentures in the third quarter of 2012, issuance of $460 million principal amount of Senior Notes in the fourth quarter of 2011, as well as newly acquired debt assumed in
our acquisition of the Partnership.
These
increases were partially offset by:
-
-
decreased administration expense of $5.5 million primarily due to a decrease in transaction related costs from the
comparable period. The third quarter of 2011 included transaction costs related to the acquisition of the Partnership; and
-
-
decreased foreign exchange loss of $13.9 million primarily due to a $44.6 million increase in unrealized
gain on foreign exchange forward contracts offset by a $30.7 million increase in unrealized loss in the revaluation of instruments denominated in Canadian dollars. The U.S. dollar to Canadian
dollar exchange rate was .9832 at September 30, 2012 and decreased by 3.4% in the three months ended September 30, 2012 compared to an increase of 8.7% in the comparable 2011 period.
Income
tax expense for the three months ended September 30, 2012 was $3.2 million as compared to a $5.3 million benefit in the comparable 2011 period. The difference
between the actual tax expense and the expected income tax benefit, based on the Canadian enacted statutory rate of 25%, of $0.5 million for the three months ended September 30, 2012 is
primarily due to foreign currency
50
Table of Contents
translation,
difference in tax rates in other countries, change in valuation allowance and various other permanent differences.
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
|
Un-Allocated Corporate
|
|
|
|
|
|
|
|
|
|
|
Project loss
|
|
$
|
(10,270
|
)
|
$
|
(910
|
)
|
|
NM
|
|
Administration
|
|
|
21,992
|
|
|
20,379
|
|
|
8
|
%
|
Interest, net
|
|
|
69,269
|
|
|
10,815
|
|
|
NM
|
|
Foreign exchange loss (gain)
|
|
|
4,440
|
|
|
20,383
|
|
|
-78
|
%
|
Other income, net
|
|
|
(5,728
|
)
|
|
|
|
|
NM
|
|
|
|
|
|
|
|
|
|
Total administrative and other expenses
|
|
|
89,273
|
|
|
51,577
|
|
|
74
|
%
|
Income tax expense (benefit)
|
|
|
(19,076
|
)
|
|
(12,900
|
)
|
|
48
|
%
|
Nine months ended September 30, 2012 compared with nine months ended September 30, 2011
Total project loss for the nine months ended September 30, 2012 increased $9.4 million from the comparable 2011period
primarily due to higher general and administrative expenses associated with operating the newly acquired Partnership projects.
Total
administrative and other expenses for the nine months ended September 30, 2012 increased $37.7 million from the comparable 2011 period primarily due
to:
-
-
increased administration expense of $1.6 million primarily due to additional administration costs subsequent to the
acquisition of the Partnership; and
-
-
increased interest expense of $58.5 million primarily due to due to the issuance of the $130 million
principal amount of convertible debentures in the third quarter of 2012, issuance of $460 million principal amount of Senior Notes in the fourth quarter of 2011, as well as newly acquired debt
assumed in our acquisition of the Partnership.
These
increases were partially offset by:
-
-
decreased foreign exchange loss of $15.9 million primarily due to a $9.3 million increase in realized gain
on foreign exchange contract settlements and a $29.6 million decrease in unrealized loss on foreign exchange forward contracts, offset by a $23.0 million increase in unrealized loss in
the revaluation of instruments denominated in Canadian dollars. The U.S. dollar to Canadian dollar exchange rate was .9832 at September 30, 2012 and decreased by 3.3% in the nine months ended
September 30, 2012 compared to an increase of 5.4% in the comparable 2011 period; and
-
-
increased other income of $5.7 million, primarily due to the $6.0 million proceeds related to the management
agreement termination fee received in the sale of our 14.3% equity investment in PERH.
Income
tax benefit for the nine months ended September 30, 2012 was $19.01 million as compared to a $12.9 million benefit in the comparable 2011 period. The
difference between the actual tax benefit and the expected income tax benefit, based on the Canadian enacted statutory rate of 25%, of $16.6 million for the nine months ended
September 30, 2012 is primarily due to foreign currency translation, renewable energy grants received, change in valuation allowance, difference in tax rates in other countries and various
other permanent differences.
51
Table of Contents
Supplementary Non-GAAP Financial Information
A key measure we use to evaluate the results of our business is Cash Available for Distribution. Cash Available for Distribution is not
a measure recognized under GAAP, does not have a standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers. We believe Cash Available
for Distribution is a relevant supplemental measure of our ability to pay dividends to our shareholders. A reconciliation of cash flows from operating activities, the most directly comparable GAAP
measure, to Cash Available for Distribution is set out below under "Cash Available for Distribution." Investors are cautioned that we may calculate this measure in a manner that is different from
other companies.
The
primary factor influencing Cash Available for Distribution is cash distributions received from the projects. These distributions received are generally funded from Project Adjusted
EBITDA generated by the projects, reduced by project-level debt service, capital expenditures, dividends paid on preferred
shares of a subsidiary company and adjusted for changes in project-level working capital and cash reserves. Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes,
depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP
and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide
comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. A
reconciliation of project income to Project Adjusted EBITDA is set out below by segment under "Project Adjusted EBITDA." Investors are cautioned that we may calculate this measure in a manner that is
different from other companies.
Project Adjusted EBITDA (in thousands of U.S. dollars) by Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
|
(unaudited)
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
Project Adjusted EBITDA by Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
$
|
20,346
|
|
$
|
9,817
|
|
$
|
85,156
|
|
$
|
27,400
|
|
Southeast
|
|
|
23,150
|
|
|
21,635
|
|
|
69,892
|
|
|
63,892
|
|
Northwest
|
|
|
12,596
|
|
|
1,121
|
|
|
38,453
|
|
|
3,606
|
|
Southwest
|
|
|
23,440
|
|
|
1,523
|
|
|
47,952
|
|
|
4,894
|
|
Un-allocated Corporate
|
|
|
(2,338
|
)
|
|
(233
|
)
|
|
(9,645
|
)
|
|
(838
|
)
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
77,194
|
|
|
33,863
|
|
|
231,808
|
|
|
98,954
|
|
Reconciliation to project income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
49,725
|
|
|
15,797
|
|
|
146,796
|
|
|
46,916
|
|
Interest expense, net
|
|
|
6,008
|
|
|
3,706
|
|
|
18,569
|
|
|
11,100
|
|
Change in the fair value of derivative instruments
|
|
|
(17,347
|
)
|
|
10,871
|
|
|
38,443
|
|
|
12,913
|
|
Other (income) expense
|
|
|
829
|
|
|
1,309
|
|
|
4,300
|
|
|
1,789
|
|
|
|
|
|
|
|
|
|
|
|
Project income (loss)
|
|
|
37,979
|
|
|
2,180
|
|
|
23,700
|
|
|
26,236
|
|
52
Table of Contents
The following table summarizes Project Adjusted EBITDA for our Northeast segment for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
|
Northeast
|
|
|
|
|
|
|
|
|
|
|
Project Adjusted EBITDA
|
|
$
|
20,346
|
|
$
|
9,817
|
|
|
107
|
%
|
Three months ended September 30, 2012 compared with three months ended September 30, 2011
Project Adjusted EBITDA for the three months ended September 30, 2012 increased $10.5 million or 107% from the comparable
2011 period primarily due to:
-
-
Project Adjusted EBITDA of $3.1 million at the newly acquired Curtis Palmer project;
-
-
Project Adjusted EBITDA of $3.0 million at the newly acquired Nipigon project; and
-
-
Project Adjusted EBITDA of $2.0 million at the newly acquired Tunis project.
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
Northeast
|
|
|
|
|
|
|
|
|
Project Adjusted EBITDA
|
|
$
|
85,156
|
|
$
|
27,400
|
|
NM
|
Nine months ended September 30, 2012 compared with nine months ended September 30, 2011
Project Adjusted EBITDA for the nine months ended September 30, 2012 increased $57.8 million from the comparable 2011
period primarily due to:
-
-
Project Adjusted EBITDA of $18.9 million at the newly acquired Curtis Palmer project;
-
-
Project Adjusted EBITDA of $10.2 million at the newly acquired Nipigon project;
-
-
Project Adjusted EBITDA of $8.4 million at the newly acquired Tunis project;
-
-
increased Project Adjusted EBITDA of $6.3 million at Chambers due to the collection of the $3.6 million
DuPont partial settlement associated with the dispute of the electricity price calculation under its PPA, as well as lower operations and maintenance costs from the comparable period;
-
-
Project Adjusted EBITDA of $4.2 million at the newly acquired North Bay project; and
-
-
increased Project Adjusted EBITDA of $4.1 million at Selkirk due to lower operating and maintenance costs and
higher capacity revenue from the comparable 2011 period.
53
Table of Contents
The following table summarizes Project Adjusted EBITDA for our Southeast segment for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
|
Southeast
|
|
|
|
|
|
|
|
|
|
|
Project Adjusted EBITDA
|
|
$
|
23,150
|
|
$
|
21,635
|
|
|
7
|
%
|
Three months ended September 30, 2012 compared with three months ended September 30, 2011
Project Adjusted EBITDA for the three months ended September 30, 2012 increased $1.5 million or 7% from the comparable
2011 period primarily due to:
-
-
a $2.6 million increase in Project Adjusted EBITDA at Auburndale primarily attributable to higher capacity revenues
due to contractual escalation under the project's PPA as well as higher dispatch than the comparable 2011 period.
The
increase was partially offset by:
-
-
decreased Project Adjusted EBITDA of $2.0 million at Pasco which had higher operations and maintenance expenses in
the third quarter of 2012 due to the unplanned replacement of gas turbine blades during a maintenance outage.
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
|
Southeast
|
|
|
|
|
|
|
|
|
|
|
Project Adjusted EBITDA
|
|
$
|
69,892
|
|
$
|
63,892
|
|
|
9
|
%
|
Nine months ended September 30, 2012 compared with nine months ended September 30, 2011
Project Adjusted EBITDA for the nine months ended September 30, 2012 increased $6.0 million or 9% from the comparable
2011 period primarily due to:
-
-
a $4.1 million increase in Project Adjusted EBITDA at Auburndale primarily attributable to higher capacity revenues
due to contractual escalation under the project's PPA as well as higher dispatch than the comparable 2011 period.
The following table summarizes Project Adjusted EBITDA for our Northwest segment for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
Northwest
|
|
|
|
|
|
|
|
|
Project Adjusted EBITDA
|
|
$
|
12,596
|
|
$
|
1,121
|
|
NM
|
54
Table of Contents
Three months ended September 30, 2012 compared with three months ended September 30, 2011
Project Adjusted EBITDA for the three months ended September 30, 2012 increased $11.5 million from the comparable 2011
period primarily due to:
-
-
Project Adjusted EBITDA of $2.3 million from the newly acquired Mamquam project;
-
-
Project Adjusted EBITDA of $6.7 million from the newly acquired Williams Lake project; and
-
-
Project Adjusted EBITDA of $2.0 million from the newly acquired Frederickson project.
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
Northwest
|
|
|
|
|
|
|
|
|
Project Adjusted EBITDA
|
|
$
|
38,453
|
|
$
|
3,606
|
|
NM
|
Nine months ended September 30, 2012 compared with nine months ended September 30, 2011
Project Adjusted EBITDA for the nine months ended September 30, 2012 increased $34.8 million from the comparable 2011
period primarily due to:
-
-
Project Adjusted EBITDA of $7.1 million from the newly acquired Mamquam project;
-
-
Project Adjusted EBITDA of $16.0 million from the newly acquired Williams Lake project;
-
-
Project Adjusted EBITDA of $7.8 million from the newly acquired Frederickson project; and
-
-
Project Adjusted EBITDA of $2.3 million from Rockland which became operational in the first quarter of 2012.
Southwest
The following table summarizes Project Adjusted EBITDA for our Southwest segment for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
Southwest
|
|
|
|
|
|
|
|
|
Project Adjusted EBITDA
|
|
$
|
23,440
|
|
$
|
1,523
|
|
NM
|
Three months ended September 30, 2012 compared with three months ended September 30, 2011
Project Adjusted EBITDA for the three months ended September 30, 2012 increased $21.9 million from the comparable 2011
period primarily due to:
-
-
Project Adjusted EBITDA of $4.5 million from the newly acquired Naval Station project;
-
-
Project Adjusted EBITDA of $3.5 million from the newly acquired North Island project;
-
-
Project Adjusted EBITDA of $5.5 million from the newly acquired Oxnard project; and
55
Table of Contents
-
-
Project Adjusted EBITDA of $4.0 million from the newly acquired Manchief project.
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
Southwest
|
|
|
|
|
|
|
|
|
Project Adjusted EBITDA
|
|
$
|
47,952
|
|
$
|
4,894
|
|
NM
|
Nine months ended September 30, 2012 compared with nine months ended September 30, 2011
Project Adjusted EBITDA for the nine months ended September 30, 2012 increased $43.1 million from the comparable 2011
period primarily due to:
-
-
Project Adjusted EBITDA of $9.1 million from the newly acquired Naval Station project;
-
-
Project Adjusted EBITDA of $4.1 million from the newly acquired Naval Training Centre project;
-
-
Project Adjusted EBITDA of $4.0 million from the newly acquired North Island project;
-
-
Project Adjusted EBITDA of $11.5 million from the newly acquired Manchief project;
-
-
Project Adjusted EBITDA of $7.8 million from the newly acquired Morris project; and
-
-
Project Adjusted EBITDA of $6.6 million from the newly acquired Oxnard project.
These
increases were partially offset by:
-
-
decreased Project Adjusted EBITDA of $2.7 million at Gregory attributable to higher operations and maintenance
costs due to a planned outage during the first quarter of 2012 that was longer than anticipated.
Generation and Availability by Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
|
Aggregate power generation (Net MWh)
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
|
581,350
|
|
|
245,245
|
|
|
137.0
|
%
|
Southeast
|
|
|
563,848
|
|
|
455,410
|
|
|
23.8
|
%
|
Northwest
|
|
|
286,977
|
|
|
28,657
|
|
|
NM
|
|
Southwest
|
|
|
684,919
|
|
|
149,889
|
|
|
NM
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,117,094
|
|
|
879,201
|
|
|
140.8
|
%
|
Weighted average availability
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
|
97.5
|
%
|
|
85.8
|
%
|
|
13.6
|
%
|
Southeast
|
|
|
99.2
|
%
|
|
97.1
|
%
|
|
2.2
|
%
|
Northwest
|
|
|
94.3
|
%
|
|
99.1
|
%
|
|
-4.8
|
%
|
Southwest
|
|
|
96.8
|
%
|
|
99.9
|
%
|
|
-3.1
|
%
|
|
|
|
|
|
|
|
|
Total
|
|
|
97.2
|
%
|
|
94.9
|
%
|
|
2.4
|
%
|
56
Table of Contents
Three months ended September 30, 2012 compared with three months ended September 30, 2011
Aggregate power generation for the three months ended September 30, 2012 increased 140.8% from the comparable 2011 period
primarily due to:
-
-
increased generation in the Northeast segment primarily due to 380,025 MWh from the newly acquired Partnership projects,
partially offset by a 37,820 MWh decrease at Selkirk due to lower dispatch from the comparable 2011 period;
-
-
increased generation in the Southeast segment attributable to an 125,486 MWh increase at the Auburndale project that had
off-peak generation in the third quarter of 2012 compared to no off-peak generation in the comparable 2011 period;
-
-
increased generation in the Northwest segment primarily due to 242,141 MWh from the newly acquired Partnership projects as
well as generation from Rockland which became operational in the first quarter of 2012; and
-
-
increased generation in the Southwest segment primarily due to 541,639 MWh from the newly acquired Partnership projects,
partially offset by a decrease at Badger which was sold in September 2012.
Weighted
average availability for the three months ended September 30, 2012 increased to 97.2% or 2.4% from the comparable 2011 period primarily due
to:
-
-
increased availability in the Northeast segment primarily due to an increase at Chambers which had an outage in the
comparable 2011 period.
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
|
2012
|
|
2011
|
|
% change
2012 vs. 2011
|
|
Aggregate power generation (Net MWh)
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
|
1,783,240
|
|
|
694,564
|
|
|
156.7
|
%
|
Southeast
|
|
|
1,610,535
|
|
|
1,354,300
|
|
|
18.9
|
%
|
Northwest
|
|
|
847,376
|
|
|
101,926
|
|
|
NM
|
|
Southwest
|
|
|
1,849,075
|
|
|
440,500
|
|
|
NM
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
6,090,226
|
|
|
2,591,290
|
|
|
135.0
|
%
|
Weighted average availability
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
|
96.0
|
%
|
|
85.8
|
%
|
|
11.9
|
%
|
Southeast
|
|
|
98.6
|
%
|
|
98.3
|
%
|
|
0.3
|
%
|
Northwest
|
|
|
94.2
|
%
|
|
98.2
|
%
|
|
-4.0
|
%
|
Southwest
|
|
|
93.9
|
%
|
|
95.7
|
%
|
|
-1.9
|
%
|
|
|
|
|
|
|
|
|
Total
|
|
|
95.6
|
%
|
|
94.8
|
%
|
|
0.8
|
%
|
Nine months ended September 30, 2012 compared with nine months ended September 30, 2011
Aggregate power generation for the nine months ended September 30, 2012 increased 135.0% from the comparable 2011 period
primarily due to:
-
-
increased generation in the Northeast segment primarily due to 1,386,137 MWh from the newly acquired Partnership projects,
partially offset by a 96,693 MWh decrease at Selkirk due to lower dispatch from the comparable 2011 period;
-
-
increased generation in the Southeast segment attributable to an 238,786 MWh increase at the Auburndale project that had
off-peak generation in the third quarter of 2012 compared to no off-peak generation in the comparable 2011 period;
57
Table of Contents
-
-
increased generation in the Northwest segment primarily due to 666,305 MWh from the newly acquired Partnership projects as
well as generation from Rockland which became operational in the first quarter of 2012; and
-
-
increased generation in the Southwest segment primarily due to 1,457,551 MWh from the newly acquired Partnership projects.
Weighted
average availability for the nine months ended September 30, 2012 increased to 95.6% or 0.8% from the comparable 2011 period primarily due
to:
-
-
increased availability in the Northeast segment primarily due to increases at Chambers and Selkirk which had planned
outages in the comparable 2011 period.
This
increase was partially offset by:
-
-
decreased availability in the Southwest segment primarily due to a planned outage at Gregory in the first quarter of 2012
which was longer than anticipated.
At September 30, 2012, cash and cash equivalents decreased $16.0 million from December 31, 2011 to
$42.9 million. The decrease in cash and cash equivalents was primarily due
to $415.5 million of cash used in investing activities, offset by $124.1 million provided by operating activities and $275.4 million of cash provided by financing activities.
At
September 30, 2011, cash and cash equivalents decreased $7.2 million from December 31, 2010 to $38.3 million. The decrease in cash and cash equivalents was
due to $68.2 million used in investing activities and $5.3 million used in financing activities, offset by $66.3 million of cash provided by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended
September 30,
|
|
$ Change
|
|
|
|
2012
|
|
2011
|
|
2012 vs. 2011
|
|
Net cash provided by operating activities
|
|
$
|
124,116
|
|
$
|
66,339
|
|
$
|
57,777
|
|
Net cash used in investing activities
|
|
|
(415,530
|
)
|
|
(68,247
|
)
|
|
(347,283
|
)
|
Net cash provided by (used in) financing activities
|
|
|
275,377
|
|
|
(5,335
|
)
|
|
280,712
|
|
Our cash flow from the projects may vary from year to year based on working capital requirements and the operating performance of the
projects, as well as changes in prices under the PPAs, fuel supply and transportation agreements, steam sales agreements and other project contracts, changes in regulated transmission rates and the
transition to market or re-contracted pricing following the expiration of PPAs. Project cash flows may have some seasonality and the pattern and frequency of distributions to us from the
projects during the year can also vary, although such seasonal variances do not typically have a material impact on our business.
Cash
flows from operating activities increased by $57.8 million for the nine months ended September 30, 2012 over the comparable period in 2011. The change from the prior
year is primarily attributable to
the increases in Project Adjusted EBITDA noted above as well as an increase in distributions from equity method investments.
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Table of Contents
Investing Activities
Cash flow from investing activities includes changes in restricted cash. Restricted cash fluctuates from period to period in part
because non-recourse project-level financing arrangements typically require all operating cash flow from the project to be deposited in restricted accounts and then released at the time
that principal payments are made and project-level debt service coverage ratios are met. As a result, the timing of principal payments on project-level debt causes significant fluctuations in
restricted cash balances, which typically benefits investing cash flow in the second and fourth quarters of the year and decreases investing cash flow in the first and third quarters of the year.
In
July 2012 we raised approximately $190.0 million of net proceeds in new convertible debentures and equity offerings to fund our equity commitment in the Canadian Hills project.
A portion of these funds was used to support the construction of the project and the remainder was placed in restricted cash accounts to be utilized during the remainder of the construction process.
Cash
flows used in investing activities for the nine months ended September 30, 2012 were $415.5 million compared to cash flows used in investing activities of
$68.2 million for the comparable 2011 period. The change is primarily attributable to $336.2 million of construction in progress related to the Piedmont and Canadian Hills projects and
$105.5 million increase in restricted cash as noted above, partially offset by $27.9 million of proceeds from our sale of our interest in PERH and Badger Creek.
Financing Activities
Cash provided by financing activities for the nine months ended September 30, 2012 resulted in a net inflow of
$275.4 million compared with a $5.3 million outflow for the comparable 2011 period. The change is primarily due to $124.8 million of proceeds from the July 2012 convertible
debentures offering, $67.7 million of net proceeds from our July 2012 equity offering and $261.2 million of proceeds from the Piedmont and Canadian Hills construction loans. This
increase was partially offset by an increase in dividend payments attributable to shares issued in connection with the July 2012 equity offering and the acquisition of the Partnership in the fourth
quarter of 2011, the dividend increase that was effective November 2011, as well as repayments of borrowings under our senior credit facility.
Cash Available for Distribution
Initially in 2011, holders of our common shares received monthly cash dividends at an annual rate of Cdn$1.094 per share. This dividend
was increased to an annual rate of Cdn$1.15 per share in November 2011 upon the closing of the Partnership acquisition. The payout ratio associated with the cash dividends declared was 120% and 70%
for the three months ended September 30, 2012 and 2011 and 98% and 93% for the nine months ended September 30, 2012 and 2011, respectively. The payout ratio for the three months ended
September 30, 2012 was negatively impacted as a result of the timing of contractual receipts with two off-takers at a number of our facilities. The collection of receivables occured during the
first week in October and negatively impacted working capital for the quarter. The payout ratio for the nine months ended September 30, 2012 was positively impacted by the termination of the
management service contract as part of the sale of our interest in PERH, the proceeds from the sale of Badger Creek as well as reducing our combined foreign currency forward positions as a result of
the Partnership acquisition, partially offset by interest payments associated with newly acquired debt from the Partnership acquisition and the additional convertible debentures offered in July 2012.
Due to the timing of working capital adjustments and the cash payments associated with our corporate level interest payments, our payout ratio will fluctuate from quarter to quarter. For example, the
interest payments on the $460 million Senior Notes are due semi-annually (May and November) and will impact our payout ratios in the second and fourth quarters.
59
Table of Contents
The
table below presents our calculation of cash available for distribution for the three and nine months ended September 30, 2012 and 2011, and the reconciliation to Cash flows
from operating activities, the most directly comparable GAAP measure:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
(unaudited)
(in thousands of U.S. dollars, except as otherwise stated)
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
Cash flows from operating activities
|
|
$
|
34,744
|
|
$
|
21,624
|
|
$
|
124,116
|
|
$
|
66,339
|
|
Project-level debt repayments
|
|
|
(2,725
|
)
|
|
(2,825
|
)
|
|
(12,050
|
)
|
|
(13,166
|
)
|
Purchases of property, plant and equipment
|
|
|
(370
|
)
|
|
(268
|
)
|
|
(1,172
|
)
|
|
(814
|
)
|
Transaction costs
(1)
|
|
|
|
|
|
8,470
|
|
|
|
|
|
9,238
|
|
Dividends on preferred shares of a subsidiary company
|
|
|
(3,321
|
)
|
|
|
|
|
(9,767
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Available for Distribution
(2)
|
|
|
28,328
|
|
|
27,001
|
|
|
101,127
|
|
|
61,597
|
|
Total cash dividends declared to shareholders
|
|
|
34,035
|
|
|
19,010
|
|
|
99,090
|
|
|
57,552
|
|
Payout ratio
|
|
|
120
|
%
|
|
70
|
%
|
|
98
|
%
|
|
93
|
%
|
Expressed in Cdn$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Available for Distribution
|
|
|
28,188
|
|
|
26,833
|
|
|
101,339
|
|
|
60,520
|
|
Total dividends declared to shareholders
|
|
|
34,288
|
|
|
18,874
|
|
|
99,637
|
|
|
56,259
|
|
-
(1)
-
Represents
business development costs associated with the acquisition of the Partnership.
-
(2)
-
Cash
Available for Distribution is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP.
Therefore, this measure may not be comparable to similar measures presented by other companies. See "Supplementary Non-GAAP Financial Information" above.
Liquidity and Capital Resources
Liquidity Position
|
|
|
|
|
|
|
|
(in thousands of U.S. dollars, except as otherwise stated)
|
|
September 30,
2012
|
|
December 31,
2011
|
|
Cash and cash equivalents
|
|
$
|
42,872
|
|
$
|
60,651
|
|
Restricted cash
|
|
|
112,633
|
|
|
21,412
|
|
|
|
|
|
|
|
Total
|
|
|
155,505
|
|
|
82,063
|
|
Revolving credit facility availability
|
|
|
143,501
|
|
|
134,700
|
|
|
|
|
|
|
|
Total liquidity
|
|
$
|
299,006
|
|
$
|
216,763
|
|
For
the nine months ended September 30, 2012, total liquidity, increased by $82.2 million due to higher availability under our senior credit facility and restricted cash,
offset by lower cash and cash equivalents balances. The increase in the senior credit facility availability was primarily due to a $38.0 million reduction in the amount drawn on our senior
credit facility. As of November 1, 2012, we have $20.0 million drawn on the senior credit facility and $135.3 million outstanding in letters of credit. Changes in cash and cash
equivalent balances were previously discussed herein under the heading
Consolidated Cash Flows
above. Total liquidity excludes $1.7 million of
cash and cash equivalents and $14.3 million of restricted cash from the Path 15 project which is recorded as an asset held for sale at September 30, 2012. Cash and cash equivalents at
September 30, 2012 were predominantly held in money market funds invested in treasury securities.
The
projects with project-level debt generally have reserve requirements to support payments for major maintenance costs, construction costs, and project-level debt service.
Project-level debt
60
Table of Contents
agreements
also contain covenants that restrict the amount of cash distributed by the project if certain debt service coverage ratios are not attained. For projects that are consolidated, our share of
these amounts is reflected as restricted cash on the consolidated balance sheet. Changes in restricted cash were previously discussed herein under
Investing
Activities
above. At September 30, 2012, restricted cash at the consolidated projects totalled $112.6 million.
We
believe existing cash, cash equivalents and marketable securities and funds generated from operations should be sufficient to meet our working capital and capital expenditure
requirements, and meet our obligations for the next 12 months.
Sources of Liquidity
Our primary source of liquidity is distributions from our projects and availability under our senior credit facility. As described in
Note 4,
Long-term debt
and Note 5,
Convertible debentures,
to this
Form 10-Q and Note 9,
Long-term debt
, and Note 10,
Convertible
debentures,
to our Annual Report on Form 10-K for the year ended December 31, 2011, our financing arrangements consist primarily of the senior credit
facility, convertible debentures, senior notes of Atlantic Power, senior unsecured notes of the Partnership, senior unsecured notes of Atlantic Power (US) GP and non-recourse
project level debt.
Project-Level Debt
The following table summarizes the maturities of project-level debt. The amounts represent our share of the non-recourse
project-level debt balances at September 30, 2012 and exclude any purchase accounting adjustments recorded to adjust the debt to its fair value at the time the project was acquired. Certain of
the projects have more than one tranche of debt outstanding with different maturities, different interest rates and/or debt containing variable interest rates. Project-level debt agreements contain
covenants that restrict the amount of cash distributed by the project if certain debt service coverage ratios are not attained. As of September 30, 2012, the covenants at the Gregory,
Delta-Person and at Epsilon Power Partners are temporarily preventing those projects from making cash distributions to us. We expect to resume receiving distributions from Epsilon Power Partners in
2013 and Gregory and Delta-Person in 2014. All project-level debt is non-recourse to us and substantially the entire principal is
amortized over the life of the projects' PPAs. The non-recourse holding company debt relating to our investment in Chambers is held at Epsilon Power Partners, our wholly owned subsidiary.
61
Table of Contents
The
range of interest rates presented represents the rates in effect at September 30, 2012. The amounts listed below are in thousands of U.S. dollars, except as otherwise stated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Range of
Interest Rates
|
|
Total
Remaining
Principal
Repayments
|
|
2012
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
Thereafter
|
|
Consolidated Projects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Epsilon Power Partners
|
|
7.40%
|
|
$
|
33,857
|
|
$
|
375
|
|
$
|
3,000
|
|
$
|
5,000
|
|
$
|
5,750
|
|
$
|
6,000
|
|
$
|
13,732
|
|
Piedmont
(1)
|
|
3.80% 5.20%
|
|
|
123,270
|
|
|
|
|
|
55,357
|
|
|
4,789
|
|
|
4,772
|
|
|
3,690
|
|
|
54,662
|
|
Canadian Hills
(2)
|
|
3.20%
|
|
|
238,755
|
|
|
238,755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Path 15
(3)
|
|
7.90% 9.00%
|
|
|
142,005
|
|
|
4,792
|
|
|
9,402
|
|
|
8,065
|
|
|
8,749
|
|
|
9,487
|
|
|
101,510
|
|
Auburndale
|
|
5.10%
|
|
|
6,650
|
|
|
1,750
|
|
|
4,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cadillac
|
|
6.00% 8.00%
|
|
|
38,431
|
|
|
600
|
|
|
2,400
|
|
|
2,000
|
|
|
3,891
|
|
|
2,500
|
|
|
27,040
|
|
Curtis Palmer
(4)
|
|
5.90%
|
|
|
190,000
|
|
|
|
|
|
|
|
|
190,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated Projects
|
|
|
|
|
772,968
|
|
|
246,272
|
|
|
75,059
|
|
|
209,854
|
|
|
23,162
|
|
|
21,677
|
|
|
196,944
|
|
Equity Method Projects:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chambers
|
|
0.60% 7.20%
|
|
|
55,201
|
|
|
3,274
|
|
|
10,783
|
|
|
5,780
|
|
|
5,213
|
|
|
5,447
|
|
|
24,704
|
|
Delta-Person
|
|
1.90%
|
|
|
8,281
|
|
|
101
|
|
|
1,300
|
|
|
1,394
|
|
|
1,495
|
|
|
1,604
|
|
|
2,387
|
|
Gregory
|
|
2.30% 7.70%
|
|
|
11,186
|
|
|
417
|
|
|
2,007
|
|
|
2,170
|
|
|
2,268
|
|
|
2,448
|
|
|
1,876
|
|
Rockland
|
|
6.40%
|
|
|
26,006
|
|
|
335
|
|
|
368
|
|
|
445
|
|
|
529
|
|
|
583
|
|
|
23,746
|
|
Idaho Wind
|
|
5.60%
|
|
|
49,633
|
|
|
797
|
|
|
2,198
|
|
|
2,364
|
|
|
2,554
|
|
|
2,511
|
|
|
39,209
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Equity Method Projects
|
|
|
|
|
150,307
|
|
|
4,924
|
|
|
16,656
|
|
|
12,153
|
|
|
12,059
|
|
|
12,593
|
|
|
91,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Project-Level Debt
|
|
|
|
$
|
923,275
|
|
$
|
251,196
|
|
$
|
91,715
|
|
$
|
222,007
|
|
$
|
35,221
|
|
$
|
34,270
|
|
$
|
288,866
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
As
of September 30, 2012 the balance of $123.3 million on the Piedmont debt is funded by the related bridge loan of
$51.0 million and $72.3 million funded by the construction loan that will convert to a term loan. The terms of the Piedmont project-level debt financing include a $51.0 million
bridge loan for approximately 95.0% of the stimulus grant expected to be received from the U.S. Treasury 60 days after the start of commercial operations, and an $82.0 million
construction term loan. The $51.0 million bridge loan is expected to be repaid in early 2013 and repayment of the expected $82.0 million term loan is scheduled to commence in 2013.
-
(2)
-
Canadian
Hills debt outstanding is funded by a $290.0 million construction loan of which $238.8 million has been drawn as of
September 30, 2012. The facility is expected to be repaid in late 2012 by proceeds from our equity contribution, the tax equity investments and a draw on our senior credit facility. See
"Recent DevelopmentsCanadian Hills."
-
(3)
-
Path
15 is classified as an asset held for sale as of September 30, 2012. Accordingly, the outstanding debt is recorded as a component
of liabilities associated with an asset held for sale on the consolidated balance sheet at September 30, 2012.
-
(4)
-
The
Curtis Palmer Notes are not considered non-recourse project-level debt as these notes are guaranteed by the Partnership.
Interest expense associated with the Curtis Palmer notes are recorded as a component of project income.
Uses of Liquidity
Our requirements for liquidity and capital resources, other than operating our projects, consist primarily of dividend payments to our
common shareholders and preferred shareholders of a subsidiary company, interest on our outstanding convertible debentures, Senior Notes and other corporate and project level debt and capital
expenditures, including major maintenance and business development costs. We may fund future acquisitions with a combination of cash on hand, the issuance of additional corporate debt or equity
securities and the incurrence of privately placed bank or institutional
62
Table of Contents
non-recourse
operating level debt, although we can provide no assurances regarding the availability of public or private financing on acceptable terms or at all.
We
do not expect any material, unusual requirements for cash outflows for the remainder of 2012 for capital expenditures or other required investments. In addition, there are no debt
instruments, other than the construction loan for Canadian Hills, with significant maturities or refinancing requirements in 2012. We expect to pay down the construction loan facility at Canadian
Hills with proceeds from our equity contribution as well as proceeds from the tax equity investments. See "Recent DevelopmentsCanadian Hills."
Capital and Major Maintenance Expenditures
Capital expenditures and maintenance expenses for the projects are generally paid at the project level using project cash flows and
project reserves. Therefore, the distributions that we receive from the projects are made net of capital expenditures needed at the projects. The operating projects which we own consist of large
capital assets that have established commercial operations. On-going capital expenditures for assets of this nature are generally not significant because most major expenditures relate to
planned repairs and maintenance and are expensed when incurred.
We
expect to reinvest approximately $30.0 million in 2012 in our project portfolio in the form of capital expenditures and major maintenance expenses. As explained above, this
investment is generally paid at the project level. We believe one of the benefits of our diverse fleet is that plant overhauls and other major expenditures do not occur in the same year for each
facility. Recognized industry guidelines and original equipment manufacturer recommendations allow us to predict major maintenance events and balance the funds necessary for these expenditures over
time. Future capital expenditures and major maintenance expenses may exceed the level in 2012 as a result of the timing of more infrequent events such as steam turbine overhauls and/or gas turbine and
hydroelectric turbine upgrades.
In
2012, several of our projects have or will conduct scheduled outages to complete major maintenance work. The level of maintenance and capital expenditures for our legacy portfolio of
projects is expected to be consistent with prior years. However, overall maintenance and capital expenditures will be higher than in 2011 due to our acquisition of the Partnership project portfolio.
There were no significant capital expenditures at our operating projects during the third quarter of 2012, but maintenance expenses were substantial, including outage related work performed at the
Auburndale, Pasco, Tunis, Chambers, Kapuskasing, Nipigon, Morris and Selkirk facilities.
In
all cases, maintenance outages occurred at such times that did not adversely impact the facilities' availability requirements under their respective PPAs.
In
the third quarter of 2012, we incurred approximately $5.4 million in capital expenditures for the construction of our Piedmont biomass project which is close to commercial
operation. In 2012, we expect to incur a total of approximately $35.2 million in capital expenditures related to the Piedmont project, with total project costs through expected completion in
November 2012 of approximately $207.0 million.
In
the third quarter of 2012, we also incurred approximately $113.9 million in capital expenditures for the construction of our Canadian Hills Wind project. We expect to incur
approximately $470 million in
total construction costs with expected completion late in the fourth quarter of 2012. See "Recent DevelopmentsCanadian Hills."
Recently Adopted and Recently Issued Accounting Guidance
See Note 1 to the consolidated financial statements in Part I Item 1 of this Form 10-Q.
Off-Balance Sheet Arrangements
As of September 30, 2012, we had no off-balance sheet arrangements as defined in Item 303(a)(4) of
Regulation S-K.
63
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