ATLANTIC POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
(in millions of U.S. dollars)
|
|
|
|
|
|
|
|
|
|
June 30,
2014
|
|
December 31,
2013
|
|
|
|
(unaudited)
|
|
|
|
Assets
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
157.6
|
|
$
|
158.6
|
|
Restricted cash
|
|
|
17.8
|
|
|
96.2
|
|
Accounts receivable
|
|
|
61.5
|
|
|
64.3
|
|
Current portion of derivative instruments asset (Notes 7 and 8)
|
|
|
1.7
|
|
|
0.2
|
|
Inventory
|
|
|
18.6
|
|
|
16.0
|
|
Prepayments and other current assets
|
|
|
15.4
|
|
|
16.1
|
|
Refundable income taxes
|
|
|
2.1
|
|
|
4.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
274.7
|
|
|
355.4
|
|
Property, plant, and equipment, net of accumulated depreciation of $241.2 million and $175.1 million at June 30, 2014 and
December 31, 2013, respectively
|
|
|
1,751.2
|
|
|
1,813.4
|
|
Equity investments in unconsolidated affiliates (Note 4)
|
|
|
368.5
|
|
|
394.3
|
|
Other intangible assets, net of accumulated amortization of $177.0 million and $136.9 million at June 30, 2014 and December 31, 2013,
respectively
|
|
|
420.6
|
|
|
451.5
|
|
Goodwill (Note 5)
|
|
|
291.1
|
|
|
296.3
|
|
Derivative instruments asset (Notes 7 and 8)
|
|
|
6.3
|
|
|
13.0
|
|
Other assets
|
|
|
98.3
|
|
|
71.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,210.7
|
|
$
|
3,395.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
10.5
|
|
$
|
14.0
|
|
Accrued interest
|
|
|
6.3
|
|
|
17.7
|
|
Other accrued liabilities
|
|
|
48.9
|
|
|
58.8
|
|
Current portion of long-term debt (Note 6)
|
|
|
26.4
|
|
|
216.2
|
|
Current portion of convertible debentures
|
|
|
42.0
|
|
|
42.1
|
|
Current portion of derivative instruments liability (Notes 7 and 8)
|
|
|
28.4
|
|
|
28.5
|
|
Dividends payable
|
|
|
3.8
|
|
|
6.8
|
|
Other current liabilities
|
|
|
8.1
|
|
|
5.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
174.4
|
|
|
389.4
|
|
Long-term debt (Note 6)
|
|
|
1,436.0
|
|
|
1,254.8
|
|
Convertible debentures
|
|
|
362.4
|
|
|
363.1
|
|
Derivative instruments liability (Notes 7 and 8)
|
|
|
58.2
|
|
|
76.1
|
|
Deferred income taxes (Note 9)
|
|
|
95.7
|
|
|
111.5
|
|
Power purchase and fuel supply agreement liabilities, net of accumulated amortization of $9.9 million and $8.1 million at June 30, 2014 and
December 31, 2013, respectively
|
|
|
36.9
|
|
|
38.7
|
|
Other non-current liabilities
|
|
|
63.2
|
|
|
65.4
|
|
Commitments and contingencies (Note 16)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
2,226.8
|
|
|
2,299.0
|
|
Equity
|
|
|
|
|
|
|
|
Common shares, no par value, unlimited authorized shares; 120,712,916 and 120,205,813 issued and outstanding at June 30, 2014 and December 31,
2013, respectively (Note 13)
|
|
|
1,286.5
|
|
|
1,286.1
|
|
Preferred shares issued by a subsidiary company (Note 13)
|
|
|
221.3
|
|
|
221.3
|
|
Accumulated other comprehensive loss
|
|
|
(24.1
|
)
|
|
(22.4
|
)
|
Retained deficit
|
|
|
(754.3
|
)
|
|
(655.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Atlantic Power Corporation shareholders' equity
|
|
|
729.4
|
|
|
829.6
|
|
Noncontrolling interests (Note 13)
|
|
|
254.5
|
|
|
266.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity
|
|
|
983.9
|
|
|
1,096.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
3,210.7
|
|
$
|
3,395.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
4
Table of Contents
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions of U.S. dollars, except per share amounts)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
June 30,
|
|
Six months ended
June 30,
|
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
Project revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy sales
|
|
$
|
82.4
|
|
$
|
76.9
|
|
$
|
164.7
|
|
$
|
153.8
|
|
Energy capacity revenue
|
|
|
41.3
|
|
|
42.9
|
|
|
74.8
|
|
|
77.2
|
|
Other
|
|
|
19.5
|
|
|
16.3
|
|
|
49.0
|
|
|
42.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
143.2
|
|
|
136.1
|
|
|
288.5
|
|
|
273.6
|
|
Project expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
50.4
|
|
|
50.0
|
|
|
110.2
|
|
|
97.7
|
|
Operations and maintenance
|
|
|
34.5
|
|
|
46.4
|
|
|
67.2
|
|
|
73.9
|
|
Development
|
|
|
1.1
|
|
|
1.8
|
|
|
1.8
|
|
|
3.5
|
|
Depreciation and amortization
|
|
|
40.9
|
|
|
41.8
|
|
|
81.5
|
|
|
82.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
126.9
|
|
|
140.0
|
|
|
260.7
|
|
|
257.8
|
|
Project other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivative instruments (Notes 7 and 8)
|
|
|
(2.8
|
)
|
|
24.3
|
|
|
11.9
|
|
|
36.9
|
|
Equity in earnings of unconsolidated affiliates (Note 4)
|
|
|
3.3
|
|
|
8.7
|
|
|
11.9
|
|
|
15.9
|
|
Interest expense, net
|
|
|
(5.8
|
)
|
|
(8.8
|
)
|
|
(20.4
|
)
|
|
(16.8
|
)
|
Impairment
|
|
|
(14.8
|
)
|
|
|
|
|
(14.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20.1
|
)
|
|
24.2
|
|
|
(11.4
|
)
|
|
36.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project (loss) income
|
|
|
(3.8
|
)
|
|
20.3
|
|
|
16.4
|
|
|
51.8
|
|
Administrative and other expenses (income):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Administration
|
|
|
10.2
|
|
|
11.8
|
|
|
17.5
|
|
|
20.1
|
|
Interest, net
|
|
|
27.7
|
|
|
25.3
|
|
|
94.1
|
|
|
51.2
|
|
Foreign exchange loss (gain) (Note 8)
|
|
|
15.3
|
|
|
(14.5
|
)
|
|
(1.5
|
)
|
|
(22.0
|
)
|
Other income, net (Note 3)
|
|
|
|
|
|
(9.5
|
)
|
|
(2.1
|
)
|
|
(9.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53.2
|
|
|
13.1
|
|
|
108.0
|
|
|
39.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing operations before income taxes
|
|
|
(57.0
|
)
|
|
7.2
|
|
|
(91.6
|
)
|
|
12.0
|
|
Income tax (benefit) expense (Note 9)
|
|
|
(0.6
|
)
|
|
0.6
|
|
|
(12.9
|
)
|
|
(1.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing operations
|
|
|
(56.4
|
)
|
|
6.6
|
|
|
(78.7
|
)
|
|
13.9
|
|
Net loss from discontinued operations, net of tax (Note 12)
|
|
|
|
|
|
(5.4
|
)
|
|
(0.1
|
)
|
|
(4.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
|
(56.4
|
)
|
|
1.2
|
|
|
(78.8
|
)
|
|
9.0
|
|
Net (loss) income attributable to noncontrolling interests
|
|
|
(0.3
|
)
|
|
1.1
|
|
|
(6.7
|
)
|
|
(0.8
|
)
|
Net income attributable to preferred shares dividends of a subsidiary company
|
|
|
3.1
|
|
|
3.1
|
|
|
5.9
|
|
|
6.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to Atlantic Power Corporation
|
|
$
|
(59.2
|
)
|
$
|
(3.0
|
)
|
$
|
(78.0
|
)
|
$
|
3.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share: (Note 11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing operations attributable to Atlantic Power Corporation
|
|
$
|
(0.49
|
)
|
$
|
0.02
|
|
$
|
(0.65
|
)
|
$
|
0.07
|
|
Loss from discontinued operations, net of tax
|
|
|
|
|
|
(0.05
|
)
|
|
|
|
|
(0.04
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to Atlantic Power Corporation
|
|
$
|
(0.49
|
)
|
$
|
(0.03
|
)
|
$
|
(0.65
|
)
|
$
|
0.03
|
|
Diluted earnings per share: (Note 11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing operations attributable to Atlantic Power Corporation
|
|
$
|
(0.49
|
)
|
$
|
0.02
|
|
$
|
(0.65
|
)
|
$
|
0.07
|
|
Loss from discontinued operations, net of tax
|
|
|
|
|
|
(0.05
|
)
|
|
|
|
|
(0.04
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to Atlantic Power Corporation
|
|
$
|
(0.49
|
)
|
$
|
(0.03
|
)
|
$
|
(0.65
|
)
|
$
|
0.03
|
|
Weighted average number of common shares outstanding: (Note 11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
120.6
|
|
|
119.9
|
|
|
120.5
|
|
|
119.7
|
|
Diluted
|
|
|
120.6
|
|
|
119.9
|
|
|
120.5
|
|
|
120.3
|
|
See accompanying notes to consolidated financial statements.
5
Table of Contents
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in millions of U.S. dollars)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
Three months ended
June 30,
|
|
|
|
2014
|
|
2013
|
|
Net (loss) income
|
|
$
|
(56.4
|
)
|
$
|
1.2
|
|
Other comprehensive (loss) income, net of tax:
|
|
|
|
|
|
|
|
Unrealized (loss) income on hedging activities
|
|
$
|
(0.3
|
)
|
$
|
0.6
|
|
Net amount reclassified to earnings
|
|
|
0.1
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized (loss) gain on derivatives
|
|
|
(0.2
|
)
|
|
0.7
|
|
Foreign currency translation adjustments
|
|
|
17.3
|
|
|
(18.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax
|
|
|
17.1
|
|
|
(17.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss
|
|
|
(39.3
|
)
|
|
(16.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Comprehensive income attributable to noncontrolling interests
|
|
|
2.8
|
|
|
4.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss attributable to Atlantic Power Corporation
|
|
$
|
(42.1
|
)
|
$
|
(20.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended
June 30,
|
|
|
|
2014
|
|
2013
|
|
Net (loss) income
|
|
$
|
(78.8
|
)
|
$
|
9.0
|
|
Other comprehensive (loss) income, net of tax:
|
|
|
|
|
|
|
|
Unrealized (loss) income on hedging activities
|
|
$
|
(0.7
|
)
|
$
|
0.6
|
|
Net amount reclassified to earnings
|
|
|
0.4
|
|
|
0.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized (loss) gain on derivatives
|
|
|
(0.3
|
)
|
|
1.0
|
|
Foreign currency translation adjustments
|
|
|
(1.4
|
)
|
|
(30.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive loss, net of tax
|
|
|
(1.7
|
)
|
|
(29.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss
|
|
|
(80.5
|
)
|
|
(20.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Comprehensive (loss) income attributable to noncontrolling interests
|
|
|
(0.8
|
)
|
|
5.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss attributable to Atlantic Power Corporation
|
|
$
|
(79.7
|
)
|
$
|
(25.6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
6
Table of Contents
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions of U.S. dollars)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
Six months ended
June 30,
|
|
|
|
2014
|
|
2013
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(78.8
|
)
|
$
|
9.0
|
|
Adjustments to reconcile to net cash provided by operating activities:
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
81.5
|
|
|
92.8
|
|
Loss of discontinued operations
|
|
|
|
|
|
32.8
|
|
Gain on sale of asset
|
|
|
(2.1
|
)
|
|
(4.4
|
)
|
Long-term incentive plan expense
|
|
|
0.9
|
|
|
1.2
|
|
Impairment charges
|
|
|
14.8
|
|
|
4.9
|
|
Equity in earnings from unconsolidated affiliates
|
|
|
(11.9
|
)
|
|
(15.9
|
)
|
Distributions from unconsolidated affiliates
|
|
|
37.8
|
|
|
18.0
|
|
Unrealized foreign exchange gain
|
|
|
(1.4
|
)
|
|
(8.7
|
)
|
Change in fair value of derivative instruments
|
|
|
(11.9
|
)
|
|
(47.7
|
)
|
Change in deferred income taxes
|
|
|
(15.5
|
)
|
|
(6.5
|
)
|
Change in other operating balances
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
2.8
|
|
|
(3.6
|
)
|
Inventory
|
|
|
(2.6
|
)
|
|
(1.3
|
)
|
Prepayments, refundable income taxes and other assets
|
|
|
14.7
|
|
|
46.3
|
|
Accounts payable
|
|
|
(4.6
|
)
|
|
(9.4
|
)
|
Accruals and other liabilities
|
|
|
(18.2
|
)
|
|
(10.6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
5.5
|
|
|
96.9
|
|
Cash flows provided by investing activities:
|
|
|
|
|
|
|
|
Change in restricted cash
|
|
|
78.4
|
|
|
(19.4
|
)
|
Proceeds from sale of asset, net
|
|
|
1.0
|
|
|
148.3
|
|
Proceeds from treasury grant
|
|
|
|
|
|
53.7
|
|
Biomass development costs
|
|
|
|
|
|
(0.1
|
)
|
Construction in progress
|
|
|
(1.5
|
)
|
|
(28.5
|
)
|
Purchase of property, plant and equipment
|
|
|
(2.5
|
)
|
|
(2.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by investing activities
|
|
|
75.4
|
|
|
151.3
|
|
Cash flows used in financing activities:
|
|
|
|
|
|
|
|
Proceeds from senior secured term loan facility
|
|
|
600.0
|
|
|
|
|
Proceeds from project-level debt
|
|
|
|
|
|
20.8
|
|
Repayment of corporate and project-level debt
|
|
|
(608.0
|
)
|
|
(64.2
|
)
|
Payments for revolving credit facility borrowings
|
|
|
|
|
|
(67.0
|
)
|
Deferred financing costs
|
|
|
(38.8
|
)
|
|
|
|
Equity contribution from noncontrolling interest
|
|
|
|
|
|
44.6
|
|
Offering costs related to tax equity
|
|
|
|
|
|
(1.0
|
)
|
Dividends paid to common shareholders
|
|
|
(20.9
|
)
|
|
(43.2
|
)
|
Dividends paid to noncontrolling interests
|
|
|
(14.2
|
)
|
|
(9.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in financing activities
|
|
|
(81.9
|
)
|
|
(119.3
|
)
|
Net (decrease) increase in cash and cash equivalents
|
|
|
(1.0
|
)
|
|
128.9
|
|
Cash and cash equivalents at beginning of period at discontinued operations
|
|
|
|
|
|
6.5
|
|
Cash and cash equivalents at beginning of period
|
|
|
158.6
|
|
|
60.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
157.6
|
|
$
|
195.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
114.7
|
|
$
|
65.3
|
|
Income taxes paid, net
|
|
$
|
1.0
|
|
$
|
1.4
|
|
Accruals for construction in progress
|
|
$
|
8.2
|
|
$
|
8.6
|
|
See accompanying notes to consolidated financial statements.
7
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
1. Nature of business and basis of presentation
Nature of business
Atlantic Power owns and operates a diverse fleet of power generation 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.
As of June 30, 2014, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,945 megawatts ("MW") in which our aggregate ownership
interest is approximately 2,024 MW. These totals exclude our 40% interest in the Delta-Person generating station ("Delta-Person") which we sold in a transaction that closed in July 2014. Our current
portfolio consists of interests in twenty-eight operational power generation projects across eleven states in the United States and two provinces in Canada. We also own Ridgeline Energy
Holdings, Inc. ("Ridgeline"), a wind and solar developer based in Seattle, Washington. Twenty of our projects are majority-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, 30
th
Floor, 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. We have included our website address only as an inactive textual reference and do not
intend it to be an active link to our website. We make available on our website, free of charge, 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.
Basis of presentation
The interim consolidated financial statements included in this Quarterly Report on Form 10-Q 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, 2013. 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 June 30, 2014, the results of
operations and comprehensive income (loss) for the three and six months ended June 30, 2014 and 2013, and our cash flows for the six months ended June 30, 2014 and 2013. In the opinion
of management, all adjustments
8
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
1. Nature of business and basis of presentation (Continued)
(consisting
of normal recurring accruals and other adjustments) considered necessary for a fair presentation have been included.
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, valuation of goodwill, 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 fair value of financial instruments and derivatives, pension obligations, asset retirement obligations and the allocation of taxable income and losses, tax
credits and cash distributions using the hypothetical liquidation book value ("HLBV") method. 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, 2013. 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.
Reclassifications
Certain prior year amounts have been reclassified to conform to the current period presentation.
Recently issued accounting standards
Adopted
In July 2013, the FASB issued changes to the presentation of an unrecognized tax benefit when a net operating loss carryforward, a
similar tax loss, or a tax credit carryforward exists. These changes require an entity to present an unrecognized tax benefit as a liability in the financial statements if (i) a net operating
loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that
would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred
tax asset to settle any additional income taxes that would result from the disallowance of a tax position. Otherwise, an unrecognized tax benefit is required to be presented in the financial
statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. Previously, there was diversity in practice as no explicit
guidance existed. These changes became effective for us on January 1, 2014 and did not have a material impact on the consolidated financial statements.
9
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
1. Nature of business and basis of presentation (Continued)
In
March 2013, the FASB issued changes to a parent entity's accounting for the cumulative translation adjustment upon derecognition of certain subsidiaries or groups of assets within a
foreign entity or of an investment in a foreign entity. A parent entity is required to release any related cumulative foreign currency translation adjustment from accumulated other comprehensive
income (loss) into net income (loss) in the following circumstances: (i) a parent entity ceases to have a controlling financial interest in a subsidiary or group of assets that is a business
within a foreign entity if the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the subsidiary or group of assets had resided;
(ii) a partial sale of an equity method investment that is a foreign entity; (iii) a partial sale of an equity method investment that is not a foreign entity whereby the partial sale
represents a complete or substantially complete liquidation of the foreign entity that held the equity method investment; and (iv) the sale of an investment in a foreign entity. These changes
became effective for us on January 1, 2014 and did not have a material impact on the consolidated financial statements.
In
February 2013, the FASB issued changes to the accounting for obligations resulting from joint and several liability arrangements. These changes require an entity to measure such
obligations for which the total amount of the obligation is fixed at the reporting date as the sum of (i) the amount the reporting entity agreed to pay on the basis of its arrangement among its
co-obligors, and (ii) any additional amount the reporting entity expects to pay on behalf of its co-obligors. An entity will also be required to disclose the nature and amount of the obligation
as well as other information about those obligations. Examples of obligations subject to these requirements are debt arrangements and settled litigation and judicial rulings. These changes became
effective for us on January 1, 2014 and did not have a material impact on the consolidated financial statements.
On
January 1, 2013, we adopted changes issued by the FASB to the reporting of amounts reclassified out of accumulated other comprehensive income (loss). These changes require an
entity to report the effect of significant reclassifications out of accumulated other comprehensive income (loss) on the respective line items in net income (loss) if the amount being reclassified is
required to be reclassified in its entirety to net income (loss). For other amounts that are not required to be reclassified in their entirety to net income (loss) in the same reporting period, an
entity is required to cross-reference other disclosures that provide additional detail about those amounts. These requirements are to be applied to each component of accumulated other comprehensive
income (loss). Other than the additional disclosure requirements (see below), the adoption of these changes had no impact on the consolidated financial statements.
Issued
In April 2014, the FASB issued changes to reporting discontinued operations and disclosures of disposals of components of an entity.
These changes require a disposal of a component to meet a higher threshold in order to be reported as a discontinued operation in an entity's financial statements. The threshold is defined as a
strategic shift that has, or will have, a major effect on an entity's operations and financial results such as a disposal of a major geographical area or a major line of business. Additionally, the
following two criteria have been removed from consideration of whether a component meets the requirements for discontinued operations presentation: (i) the operations and
10
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
1. Nature of business and basis of presentation (Continued)
cash
flows of a disposal component have been or will be eliminated from the ongoing operations of an entity as a result of the disposal transaction, and (ii) an entity will not have any
significant continuing involvement in the operations of the disposal component after the disposal transaction. Furthermore, equity method investments now may qualify for discontinued operations
presentation. These changes also require expanded disclosures for all disposals of components of an entity, whether or not the
threshold for reporting as a discontinued operation is met, related to profit or loss information and/or asset and liability information of the component. These changes become effective on
January 1, 2015. The adoption of these changes will not have an immediate impact on the consolidated financial statements. This guidance will need to be considered in the event that we initiate
a disposal transaction.
In
May 2014, the FASB issued changes to the recognition of revenue from contracts with customers. These changes created a comprehensive framework for all entities in all industries to
apply in the determination of when to recognize revenue, and, therefore, supersede virtually all existing revenue recognition requirements and guidance. This framework is expected to result in less
complex guidance in application while providing a consistent and comparable methodology for revenue recognition. The core principle of the guidance is that an entity should recognize revenue to depict
the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this
principle, an entity should apply the following steps: (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine
the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance
obligation. These changes become effective on January 1, 2017. We are currently evaluating the potential impact of these changes on the consolidated financial statements.
11
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
2. Changes in accumulated other comprehensive loss by component
The changes in accumulated other comprehensive loss by component were as follows:
|
|
|
|
|
|
|
|
|
|
Three months ended
June 30,
|
|
|
|
2014
|
|
2013
|
|
Foreign currency translation
|
|
|
|
|
|
|
|
Balance at beginning of period
|
|
$
|
(40.9
|
)
|
$
|
0.5
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
Foreign currency translation adjustments
(1)
|
|
|
17.3
|
|
|
(18.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
(23.6
|
)
|
$
|
(17.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
|
|
|
|
|
|
|
|
Balance at beginning of period
|
|
$
|
(0.4
|
)
|
$
|
(1.8
|
)
|
Other comprehensive loss:
|
|
|
|
|
|
|
|
Amortization of net actuarial gain
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
(0.4
|
)
|
$
|
(1.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges
|
|
|
|
|
|
|
|
Balance at beginning of period
|
|
$
|
0.1
|
|
$
|
(1.1
|
)
|
Other comprehensive (loss) income:
|
|
|
|
|
|
|
|
Net change from periodic revaluations
|
|
|
(0.5
|
)
|
|
1.0
|
|
Tax benefit (expense)
|
|
|
0.2
|
|
|
(0.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other comprehensive income (loss) before reclassifications, net of tax
|
|
|
(0.3
|
)
|
|
0.6
|
|
Net amount reclassified to earnings (loss):
|
|
|
|
|
|
|
|
Interest rate swaps
(2)
|
|
|
0.3
|
|
|
0.4
|
|
Fuel commodity swaps
(3)
|
|
|
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sub-total
|
|
|
0.3
|
|
|
0.3
|
|
Tax expense
|
|
|
0.2
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total amount reclassified from Accumulated other comprehensive loss, net
of tax
|
|
|
0.1
|
|
|
0.1
|
|
Total Other comprehensive (loss) income
|
|
|
(0.2
|
)
|
|
0.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
(0.1
|
)
|
$
|
(0.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
2. Changes in accumulated other comprehensive loss by component (Continued)
|
|
|
|
|
|
|
|
|
|
Six months ended
June 30,
|
|
|
|
2014
|
|
2013
|
|
Foreign currency translation
|
|
|
|
|
|
|
|
Balance at beginning of period
|
|
$
|
(22.2
|
)
|
$
|
12.6
|
|
Other comprehensive loss:
|
|
|
|
|
|
|
|
Foreign currency translation adjustments
(1)
|
|
|
(1.4
|
)
|
|
(30.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
(23.6
|
)
|
$
|
(17.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
|
|
|
|
|
|
|
|
Balance at beginning of period
|
|
$
|
(0.4
|
)
|
$
|
(1.8
|
)
|
Other comprehensive loss:
|
|
|
|
|
|
|
|
Amortization of net actuarial gain
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
(0.4
|
)
|
$
|
(1.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges
|
|
|
|
|
|
|
|
Balance at beginning of period
|
|
$
|
0.2
|
|
$
|
(1.4
|
)
|
Other comprehensive (loss) income:
|
|
|
|
|
|
|
|
Net change from periodic revaluations
|
|
|
(1.1
|
)
|
|
1.0
|
|
Tax benefit (expense)
|
|
|
0.4
|
|
|
(0.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other comprehensive (loss) income before reclassifications, net of tax
|
|
|
(0.7
|
)
|
|
0.6
|
|
Net amount reclassified to earnings (loss):
|
|
|
|
|
|
|
|
Interest rate swaps
(2)
|
|
|
0.7
|
|
|
0.8
|
|
Fuel commodity swaps
(3)
|
|
|
|
|
|
(0.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sub-total
|
|
|
0.7
|
|
|
0.6
|
|
Tax expense
|
|
|
0.3
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total amount reclassified from Accumulated other comprehensive loss, net
of tax
|
|
|
0.4
|
|
|
0.4
|
|
Total Other comprehensive (loss) income
|
|
|
(0.3
|
)
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
(0.1
|
)
|
$
|
(0.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
In
all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings (loss).
-
(2)
-
This
amount was included in Interest expense, net on the accompanying consolidated statements of operations.
-
(3)
-
A
positive amount indicates a corresponding charge to earnings (loss) and a negative amount indicates a corresponding benefit to earnings
(loss). These amounts were reflected on the accompanying consolidated statements of operations in the line items indicated in footnotes 1 and 2.
13
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
3. Acquisitions and divestments
2014 Divestments
-
(a)
-
Delta-Person
In
December 2012, we and the owners of Delta-Person, entered into a purchase and sale agreement with BHB Power, LLC and Public Service Company of New Mexico to sell the project
for approximately $37.2 million including working capital adjustments. We received net cash proceeds in July 2014 for our ownership interest of approximately $7.2 million in the
aggregate. We expect to receive an additional $1.4 million of cash proceeds held in escrow for up to twelve months after the close of the transaction. We intend to use the net proceeds from the
sale for general corporate purposes. The sale of Delta-Person closed in July 2014 resulting in a gain on sale of approximately $8.6 million that will be recorded as a component of other income
in the consolidated statement of operations for the three months ended September 30, 2014.
-
(b)
-
Greeley
In
March 2014, we closed a transaction with Initium Power Partners, LLC. ("Initium"), whereby Initium agreed to purchase all of the issued and outstanding membership interests in
Greeley for approximately $1.0 million. We recorded a $2.1 million non-cash gain on the sale in the consolidated statement of operations. Greeley is accounted for as a component of
discontinued operations in the consolidated statements of operations for the six months ended June 30, 2014.
2013 Divestments
-
(a)
-
Gregory
In
April 2013, we and the other owners of Gregory, entered into a purchase and sale agreement with an affiliate of NRG Energy, Inc. to sell the project for approximately
$274.2 million including working capital adjustments. We received net cash proceeds for our ownership interest of approximately $34.6 million in the aggregate, after repayment of
project-level debt and transaction expenses. Approximately $5.0 million of these proceeds will be held in escrow for up to one year after the closing date. We used the net proceeds from the
sale for general corporate purposes. The sale of Gregory closed in August 2013 resulting in a gain on sale of approximately $31.0 million, which was recorded as a component of other income in
the consolidated statement of operations for the three months ended September 30, 2013.
-
(b)
-
Auburndale,
Lake and Pasco
In
January 2013, we entered into a purchase and sale agreement for the sale of our Auburndale Power Partners, L.P. ("Auburndale"), Lake CoGen, Ltd. ("Lake") and Pasco
CoGen, Ltd. ("Pasco") projects (collectively, the "Florida Projects") for approximately $140.0 million, with working capital adjustments. The sale closed in April 2013 and we received
net cash proceeds of approximately $117.0 million in the aggregate, after repayment of project-level debt at Auburndale and settlement of all outstanding natural gas swap agreements at Lake and
Auburndale. This includes approximately $92.0 million received at
closing and cash distributions from the Florida Projects of approximately $25.0 million received since January 1, 2013. We used a portion of the net proceeds from the sale to fully repay
our senior credit facility, which had an outstanding balance of approximately $64.1 million
14
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
3. Acquisitions and divestments (Continued)
on
the closing date. The remaining cash proceeds were used for general corporate purposes. The Florida Projects were accounted for as a component of discontinued operations in the consolidated
statements of operations for the three and six months ended June 30, 2013. See Note 12,
Discontinued Operations
, for further information.
-
(c)
-
Path
15
In
March 2013, we entered into a purchase and sales agreement with Duke Energy Corporation and American Transmission Co., to sell our interests in the Path 15 transmission line
("Path 15"). The sale closed on April 30, 2013 and we received net cash proceeds from the sale, including working capital adjustments, of approximately $52.0 million, plus a management
agreement termination fee of $4.0 million, for a total sale price of approximately $56.0 million. The cash proceeds were used for general corporate purposes. All project level debt
issued by Path 15, totaling $137.2 million, transferred with the sale. Path 15 was accounted for as a component of discontinued operations in the consolidated statements of operations for the
three and six months ended June 30, 2013. See Note 12,
Discontinued Operations
, for further information.
4. Equity method investments in unconsolidated affiliates
The following summarizes the operating results for the three and six months ended June 30, 2014 and 2013, respectively, for earnings in our equity method investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
June 30,
|
|
Six months ended
June 30,
|
|
Operating results
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chambers
|
|
$
|
12.6
|
|
$
|
13.4
|
|
$
|
30.6
|
|
$
|
26.6
|
|
Other
(1)
|
|
|
33.5
|
|
|
41.2
|
|
|
73.2
|
|
|
80.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46.1
|
|
|
54.6
|
|
|
103.8
|
|
|
107.2
|
|
Project expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chambers
|
|
|
10.8
|
|
|
11.1
|
|
|
25.1
|
|
|
20.7
|
|
Other
(1)
|
|
|
28.8
|
|
|
34.5
|
|
|
61.4
|
|
|
68.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39.6
|
|
|
45.6
|
|
|
86.5
|
|
|
88.8
|
|
Project other expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chambers
|
|
|
(1.5
|
)
|
|
(0.6
|
)
|
|
(2.1
|
)
|
|
(1.2
|
)
|
Other
(1)
|
|
|
(1.7
|
)
|
|
0.3
|
|
|
(3.3
|
)
|
|
(1.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3.2
|
)
|
|
(0.3
|
)
|
|
(5.4
|
)
|
|
(2.5
|
)
|
Project income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chambers
|
|
$
|
0.3
|
|
$
|
1.7
|
|
$
|
3.4
|
|
$
|
4.7
|
|
Other
(1)
|
|
|
3.0
|
|
|
7.0
|
|
|
8.5
|
|
|
11.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.3
|
|
|
8.7
|
|
|
11.9
|
|
|
15.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Includes
equity method investments that individually do not exceed 10% of consolidated total assets or income (loss) before income taxes.
15
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
5. Goodwill
Our goodwill balance was $291.1 million and $296.3 million as of June 30, 2014 and December 31, 2013, respectively. We recorded $331.1 million of
goodwill in connection with the acquisition of Capital Power Income L.P. (the "Partnership") in 2011. We apply an accounting standard under which goodwill has an indefinite life and is not
amortized. Goodwill is tested for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a
reporting unit below its carrying amount. We test goodwill for impairment at the reporting unit level, which is at the project level and, the lowest level below the operating segments for which
discrete financial information is available. For reporting units that fail step 1 of the goodwill impairment test, we will initiate a step 2 test to quantify the amount, if any, of non-cash impairment
to record.
Under
our accounting policies for long-lived assets and goodwill impairment, we also perform an impairment analysis at the earlier of (i) executing a new PPA (or other
arrangement) and (ii) six months prior to the expiration of an existing PPA. The Tunis project's PPA expires on December 31, 2014 and accordingly, we performed a long-lived assets
impairment test and a goodwill impairment test as of June 30, 2014.
Based
on the results of our long-lived asset impairment test, it was determined that the weighted average estimated undiscounted cash flows for Tunis over its remaining useful life did
not exceed the carrying value of the property, plant and equipment at the Tunis reporting unit. As a result, the project recorded a $9.6 million long-lived asset impairment charge in the three
months ended June 30, 2014 which was the difference between the carrying value of the project's property, plant and equipment and its estimated fair market value.
Subsequent
to adjusting the carrying value of the Tunis reporting unit for the $9.6 million long-lived asset impairment, we performed an impairment analysis for the project's
goodwill. The project failed step 1 of the impairment test because the weighted average estimated discounted cash flows over its remaining useful life did not exceed the carrying value of the Tunis
reporting unit. We performed step 2 of the goodwill impairment test and wrote off all of the projects goodwill because the carrying value
of goodwill exceeded its implied fair value. As a result, Tunis, a component of the East segment, recorded a $5.2 million goodwill impairment charge in the three months ended June 30,
2014. The implied fair value of goodwill was determined in the same manner as the value of goodwill is determined in a business combination, using the fair value of the reporting unit as if it were
the purchase price.
The
total $14.8 million long-lived asset and goodwill impairment was primarily due to our assessment of the forecasted cash flows from re-contracting and other strategic outcomes.
We
determine the fair value of our reporting units using an income approach with discounted cash flow ("DCF") models, as we believe forecasted cash flows are the best indicator of such
fair value. A number of significant assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including assumptions about discount rates, projected
power prices, generation, fuel costs and capital expenditure requirements. The undiscounted and discounted cash flows utilized in our long-lived asset recovery and step 1 goodwill impairment tests for
Tunis were determined using our best estimate of the weighted average probability of several re-contracting
16
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
5. Goodwill (Continued)
scenarios
and other strategic outcomes. The fair value of Tunis used to calculate the long-lived asset impairment amount and to perform step 2 of the goodwill impairment test was determined using
market participant assumptions. All cash flow forecasts from DCF models utilized estimated plant output for determining assumptions around future generation and industry data forward power and fuel
curves to estimate future power and fuel prices. We used historical experience to determine estimated future capital investment requirements.
The
valuations of long-lived assets and goodwill for the long-lived assets and goodwill impairment analyses are considered level 3 fair value measurements, which means that the
valuation of the assets and liabilities reflect management's own judgments regarding the assumptions market participants would use in determining the fair value of the assets and liabilities.
The
discount rate applied to the DCF models represents the weighted average cost of capital ("WACC") consistent with the risk inherent in future cash flows and based upon an assumed
capital structure, cost of long-term debt and cost of equity consistent with comparable independent power producers. The betas used in calculating the WACC rate were obtained from reputable third
party sources.
Based
on the continued deficit of our market capitalization as compared to our book carrying value, we determined that it was appropriate to initiate a test of the remaining goodwill at
our reporting units to determine if it is more likely than not that the fair value of our reporting units do not exceed their carrying amounts. For reporting units, if any, that fail step 1 of the
goodwill impairment test, we will initiate a step 2 test to quantify the amount, if any, of non-cash impairment to record. As of the date of this Quarterly Report on Form 10-Q, we are currently
gathering the necessary information to perform these tests and expect to complete them during the three months ended September 30, 2014.
The
following table is a rollforward of goodwill for the six months ended June 30, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
East
|
|
West
|
|
Wind
|
|
Un-allocated
corporate
|
|
Total
|
|
Balance at December 31, 2013
|
|
$
|
107.8
|
|
$
|
188.5
|
|
$
|
|
|
$
|
|
|
$
|
296.3
|
|
Impairment of Goodwill
|
|
|
(5.2
|
)
|
|
|
|
|
|
|
|
|
|
|
(5.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at June 30, 2014
|
|
$
|
102.6
|
|
$
|
188.5
|
|
$
|
|
|
$
|
|
|
$
|
291.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
6. Long-term debt
Long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
June 30,
2014
|
|
December 31,
2013
|
|
Interest Rate
|
Recourse Debt:
|
|
|
|
|
|
|
|
|
Senior secured term loan facility, due 2021
|
|
$
|
562.5
|
|
$
|
|
|
LIBOR
(1)
plus 3.8%
|
Senior unsecured notes, due 2018
(2)
|
|
|
319.9
|
|
|
460.0
|
|
9.0%
|
Senior unsecured notes, due June 2036 (Cdn$210.0)
|
|
|
196.8
|
|
|
197.4
|
|
6.0%
|
Senior unsecured notes, due July 2014
(3)
|
|
|
|
|
|
190.0
|
|
5.9%
|
Series A senior unsecured notes, due August 2015
(3)
|
|
|
|
|
|
150.0
|
|
5.9%
|
Series B senior unsecured notes, due August 2017
(3)
|
|
|
|
|
|
75.0
|
|
6.0%
|
Non-Recourse Debt:
|
|
|
|
|
|
|
|
|
Epsilon Power Partners term facility, due 2019
|
|
|
28.0
|
|
|
30.5
|
|
LIBOR plus 3.1%
|
Cadillac term loan, due 2025
|
|
|
34.4
|
|
|
35.4
|
|
6.0% 8.0%
|
Piedmont term loan, due 2018
(4)
|
|
|
68.3
|
|
|
76.6
|
|
5.2%
|
Meadow Creek term loan, due 2024
|
|
|
167.3
|
|
|
169.8
|
|
2.9% 5.6%
|
Rockland term loan, due 2027
|
|
|
84.4
|
|
|
85.3
|
|
6.4%
|
Other long-term debt
|
|
|
0.8
|
|
|
1.0
|
|
5.5% 6.7%
|
Less: current maturities
|
|
|
(26.4
|
)
|
|
(216.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
1,436.0
|
|
$
|
1,254.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
maturities consist of the following:
|
|
|
|
|
|
|
|
|
|
|
June 30,
2014
|
|
December 31,
2013
|
|
Interest Rate
|
Current Maturities:
|
|
|
|
|
|
|
|
|
Senior secured term loan facility, due 2021
|
|
$
|
6.0
|
|
$
|
|
|
LIBOR
(1)
plus 3.8%
|
Senior unsecured notes, due July 2014
(3)
|
|
|
|
|
|
190.0
|
|
5.9%
|
Epsilon Power Partners term facility, due 2019
|
|
|
5.3
|
|
|
5.0
|
|
LIBOR plus 3.1%
|
Cadillac term loan, due 2025
|
|
|
3.6
|
|
|
2.0
|
|
6.0% 8.0%
|
Piedmont term loan, due 2018
(4)
|
|
|
4.9
|
|
|
12.6
|
|
5.2%
|
Meadow Creek term loan, due 2024
|
|
|
4.8
|
|
|
4.9
|
|
2.9% 5.6%
|
Rockland term loan, due 2027
|
|
|
1.6
|
|
|
1.5
|
|
6.4%
|
Other short-term debt
|
|
|
0.2
|
|
|
0.2
|
|
5.5 6.7%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current maturities
|
|
$
|
26.4
|
|
$
|
216.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
LIBOR
cannot be less than 1.00%. On May 5, 2014 we entered into interest rate swap agreements to mitigate the exposure to changes in
LIBOR for $199.0 million notional amount of the $568.5 million outstanding aggregate borrowings. See Note 8, Accounting for derivative instruments and hedging activities for
further details.
-
(2)
-
We
repurchased approximately $140.1 million aggregate principal amount of the 9.0% Notes in March 2014 with a portion of the proceeds
from the New Senior Secured Credit Facilities and cash on hand, as further described below.
18
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
6. Long-term debt (Continued)
-
(3)
-
The
Curtis Palmer Notes due July 2014, Series A senior guaranteed notes due August 2015 and Series B senior guaranteed notes
due August 2017 were retired on February 26, 2014 with proceeds from the New Senior Secured Credit Facilities described below.
-
(4)
-
On
February 14, 2014, we paid down $8.1 million of principal on the Piedmont construction loan and converted the remaining
$68.5 million to a term loan due August 2018.
On February 24, 2014, Atlantic Power Limited Partnership ("the Partnership"), our wholly-owned indirect subsidiary, entered into
a new senior secured term loan facility (the "New Term Loan Facility"), comprising of $600 million in aggregate principal amount, and a new senior secured revolving credit facility (the "New
Revolving Credit Facility") with a capacity of $210 million (collectively, the "New Senior Secured Credit Facilities"). Borrowings under the New Senior Secured Credit Facilities are available
in U.S. dollars and Canadian dollars and bear interest at a rate equal to the Adjusted Eurodollar Rate (LIBOR), the Base Rate or the Canadian Prime Rate, each as defined in the credit agreement
governing the New Senior Secured Credit Facilities (the "Credit Agreement"), as applicable, plus an applicable margin between 2.75% and 3.75% that varies depending on whether the loan is a Eurodollar
Rate Loan, Base Rate Loan, or Canadian Prime Rate Loan. The applicable margin for term loans bearing interest at the Adjusted Eurodollar Rate and the Base Rate is 3.75% and 2.75% respectively and was
3.75% at June 30, 2014. The Adjusted Eurodollar Rate cannot be less than 1.00% (1.00% at June 30, 2014). As further described in Note 8, the Partnership entered into interest rate
swap agreements on May 5, 2014 to mitigate the exposure to changes in the Adjusted Eurodollar Rate for a portion of the New Term Loan Facility.
In
connection with the funding of the New Senior Secured Credit Facilities, we terminated our prior revolving credit facility on February 26, 2014.
The
New Term Loan Facility matures on February 24, 2021. The revolving commitments under the New Revolving Credit Facility terminate on February 24, 2018. Letters of credit
are available to be issued
under the revolving commitments until 30 days prior to the Letter of Credit Expiration Date under, and as defined in, the Credit Agreement. The Partnership is required to pay a commitment fee
with respect to the commitments under the New Revolving Credit Facility equal to 0.75% times the average of the daily difference between the revolving commitments and all outstanding revolving loans
(excluding swing line loans) plus amounts available to be drawn under letters of credit and all outstanding reimbursement obligations with respect to drawn letters of credit.
The
New Senior Secured Credit Facilities are secured by a pledge of the equity interests in the Partnership and its subsidiaries, guaranties from the Partnership subsidiary guarantors
and a limited recourse guaranty from the entity that holds all of the Partnership equity, a pledge of certain material contracts and certain mortgages over material real estate rights, an assignment
of all revenues, funds and accounts of the Partnership and its subsidiaries (subject to certain exceptions), and certain other assets. The New Senior Secured Credit Facilities are not otherwise
guaranteed or secured by us or any of our subsidiaries (other than the Partnership subsidiary guarantors). The New Senior Secured Credit Facilities have a debt service reserve account, which is
required to be funded and maintained at the debt service reserve requirement, equal to six months of debt service. The debt service reserve requirement was funded with a $15.8 million letter of
credit.
19
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
6. Long-term debt (Continued)
The
Partnership's existing Cdn$210 million aggregate principal amount of 5.95% Medium Term Notes due June 23, 2036 (the "MTNs") prohibit the Partnership (subject to certain
exceptions) from granting liens on its assets (and those of its material subsidiaries) to secure indebtedness, unless the MTNs are secured equally and ratably with such other indebtedness.
Accordingly, in connection with the execution of the Credit Agreement, the Partnership has granted an equal and ratable security interest in the collateral package securing the New Senior Secured
Credit Facilities under the indenture governing the MTNs for the benefit of the holders of the MTNs.
The
Credit Agreement contains customary representations, warranties, terms and conditions, and covenants. The covenants include a requirement that the Partnership and its subsidiaries
maintain a Leverage Ratio (as defined in the Credit Agreement) ranging from 5.50:1.00 in 2014 to 4.00:1.00 in 2021, and an Interest Coverage Ratio (as defined in the Credit Agreement) ranging from
2.50:1.00 in 2014 to 3.25:1.00 in 2021. In addition, the Credit Agreement includes customary restrictions and limitations on the Partnership's and its subsidiaries' ability to (i) incur
additional indebtedness, (ii) grant liens on any of their assets, (iii) change their conduct of business or enter into mergers, consolidations, reorganizations, or certain other
corporate transactions, (iv) dispose of assets, (v) modify material contractual obligations, (vi) enter into affiliate transactions, (vii) incur capital expenditures, and
(viii) make dividend payments or other distributions, in each case subject to customary carve-outs and exceptions and various thresholds.
Under
the Credit Agreement, if a change of control (as defined in the Credit Agreement) occurs, unless the Partnership elects to make a voluntary prepayment of the term loans under the
New Senior Secured Credit Facilities, it will be required to offer each electing lender to prepay such lender's term loans under the New Senior Secured Credit Facilities at a price equal to 101% of
par. In addition, in the event that the Partnership elects to repay, prepay or refinance all or any portion of the term loan facilities within one year from the initial funding date under the Credit
Agreement, it will be required to do so at a price of 101% of the principal amount so repaid, prepaid or refinanced.
The
Credit Agreement also contains a mandatory amortization feature and customary mandatory prepayment provisions, including: (i) from proceeds of assets sales, insurance
proceeds, and incurrence of indebtedness, in each case subject to applicable thresholds and customary carve-outs; and (ii) the payment of 50% of the excess cash flow, as defined in the Credit
Agreement, of the Partnership and its subsidiaries.
Under
certain conditions the lending commitments under the Credit Agreement may be terminated by the lenders and amounts outstanding under the Credit Agreement may be accelerated. Such
events of default include failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations or warranties in any material respect,
non-payment or acceleration of other material debt of the Partnership and its subsidiaries, bankruptcy, material judgments rendered against the Partnership or certain of its subsidiaries, certain
ERISA or regulatory events, a change of control of the Partnership, or defaults under certain guaranties and collateral documents securing the New Senior Secured Credit Facilities, in each case
subject to various exceptions and notice, cure and grace periods.
20
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
6. Long-term debt (Continued)
On February 26, 2014, $600 million was drawn under the New Term Loan Facility, and letters of credit in an aggregate face amount of $144.1 million
($107.0 million as of June 30, 2014) were issued (but not drawn) pursuant to the revolving commitments under the New Revolving Credit Facility and used to (i) satisfy a debt
service reserve requirement in an amount equivalent to six months of debt service (approximately $15.8 million) and (ii) support contractual credit support obligations of the Partnership
and its subsidiaries and of certain other of our affiliates.
We
and our subsidiaries have used the proceeds from the New Term Loan Facility under the New Senior Secured Credit Facilities to:
-
-
redeem in whole, at a price equal to par plus $31.1 million of accrued interest and make-whole premiums
(i) the $150 million aggregate principal amount outstanding of 5.87% Senior Guaranteed Notes, Series A, due 2015 (the "Series A Notes") and the $75 million aggregate
principal amount outstanding of 5.97% Senior Guaranteed Notes, Series B, due 2017 (the "Series B Notes") issued by Atlantic Power (US) GP, and (ii) the $190 million
aggregate principal amount outstanding of 5.9% Senior Notes due 2014 issued by Curtis Palmer LLC;
-
-
pay transaction costs and expenses of approximately $40.0 million including banking, legal and consulting fees
which were capitalized as deferred financing costs; and
-
-
make a distribution to us in the amount of $122 million which was used, in addition to cash on hand, to repurchase
$140.1 million aggregate principal amount of the 9.0% Notes (as defined below) of Atlantic Power Corporation, make $15.7 million in accrued interest and premium payments as part of the
aggregate repurchase price, and $0.1 million in commission fees associated with the repurchases.
In
connection with the termination of our prior credit facility, we terminated the interest rate swap at Epsilon Power Partners, a wholly owned subsidiary, a portion of our natural gas
swaps at Orlando and foreign exchange forward contracts at the Partnership. As a result of the termination of these contracts, we recorded $2.6 million of interest expense, $4.0 million
of fuel expense and $0.4 million of foreign exchange loss, respectively.
The
prior credit facility contained certain guaranties, which were terminated in connection with the termination of the prior credit facility. In addition, the terms of the 9.0% Notes
provide that the guarantors of the prior credit facility guarantee the 9.0% Notes. As a result, upon termination of our prior credit facility and its related guaranties, the guaranties under the 9.0%
Notes were cancelled and the guarantors of the 9.0% Notes were automatically released from all of their obligations under such guaranties.
On November 5, 2011, we completed a private placement of $460.0 million aggregate principal amount of 9.0% senior notes
due 2018 (the "9.0% Notes") to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933, as amended (the "Securities Act"), and to non-U.S. persons outside of
the United States in compliance with Regulation S under the Securities Act. The
21
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
6. Long-term debt (Continued)
9.0%
Notes were issued at an issue price of 97.471% of the face amount of the Atlantic Notes for aggregate gross proceeds to us of $448.0 million.
On
March 25, 2014, we agreed, in privately-negotiated transactions, to repurchase approximately $140.1 million aggregate principal amount of the 9.0% Notes from certain
holders. We paid $15.7 million in accrued interest and premiums as part of the aggregate repurchase price, paid $0.1 million in
commission fees associated with the repurchases, and wrote off $5.3 million of deferred financing costs related to the repurchase. The premiums, accrued interest and write-off of deferred
financing costs were recorded to interest expense.
As
previously disclosed with respect to the impact of the New Senior Secured Credit Facilities in our Current Report on Form 8-K filed on January 30, 2014, in our Annual
Report on Form 10-K for the year ended December 31, 2013 and in our Quarterly Report on Form 10-Q for the three months ended March 31, 2014, due to the aggregate impact of
the up-front costs resulting from the prepayments on our indebtedness described above, including the premium payment and charges for unamortized debt discount and fee expenses and premiums as part of
the overall purchase price in respect of the repurchases of the 9.0% Notes (all such up-front costs, collectively, the "Prepayment Charges"), which were reflected as interest expense in our 2014 first
quarter results, we no longer satisfy the fixed charge coverage ratio test included in the restricted payments covenant of the indenture governing the 9.0% Notes. The fixed charge coverage ratio must
be at least 1.75 to 1.00 and is measured on a rolling four quarter basis, including after giving effect to certain pro forma adjustments. As a consequence, further dividend payments, which are
declared and paid at the discretion of our board of directors, in the aggregate cannot exceed the covenant's "basket" provision of the greater of $50 million and 2% of consolidated net assets
(approximately $61 million at June 30, 2014) until such time that we satisfy the fixed charge coverage ratio test. We have declared seven monthly dividends in January through July 2014
totaling approximately $25.6 million that were subject to the basket provision.
For
the trailing twelve months ended June 30, 2014, dividend payments to our shareholders totaled approximately Cdn$48.1 million, reflecting the lower Cdn$0.03333 per
common share monthly dividend first declared in March 2013. The Prepayment Charges would no longer be reflected in the calculation of the fixed charge coverage ratio test after the passage of four
additional successive quarters following the quarter in which the Prepayment Charges are incurred. In addition, any similar prepayment charges incurred in connection with any further debt reduction
would also be reflected in the calculation of the fixed charge coverage ratio test on a rolling four quarter basis, beginning with the quarter in which such charges are incurred, as would any
associated reduction in interest expense.
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 in order to
distribute available cash. At June 30, 2014, all of our projects with the exception of Piedmont were in compliance with the covenants contained in project-level debt. During the first
22
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
6. Long-term debt (Continued)
quarter
of 2014, Piedmont underwent forced maintenance outages that resulted in the project not meeting its debt service coverage ratio covenant as of June 30, 2014. We do not expect Piedmont
to meet its debt service coverage ratio covenant or make distributions for at least the next twelve months.
7. 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 June 30, 2014 and
December 31, 2013. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2014
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
157.6
|
|
$
|
|
|
$
|
|
|
$
|
157.6
|
|
Restricted cash
|
|
|
35.7
|
|
|
|
|
|
|
|
|
35.7
|
|
Derivative instruments asset
|
|
|
|
|
|
8.0
|
|
|
|
|
|
8.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
193.3
|
|
$
|
8.0
|
|
$
|
|
|
$
|
201.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments liability
|
|
$
|
|
|
$
|
86.6
|
|
$
|
|
|
$
|
86.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
$
|
86.6
|
|
$
|
|
|
$
|
86.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
158.6
|
|
$
|
|
|
$
|
|
|
$
|
158.6
|
|
Restricted cash
|
|
|
114.2
|
|
|
|
|
|
|
|
|
114.2
|
|
Derivative instruments asset
|
|
|
|
|
|
13.2
|
|
|
|
|
|
13.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
272.8
|
|
$
|
13.2
|
|
$
|
|
|
$
|
286.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments liability
|
|
$
|
|
|
$
|
104.6
|
|
$
|
|
|
$
|
104.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
$
|
104.6
|
|
$
|
|
|
$
|
104.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
carrying amounts for cash and cash equivalents and restricted cash approximate fair value due to their short-term nature.
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.
23
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
7. Fair value of financial instruments (Continued)
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 June 30, 2014, the credit valuation adjustments resulted in an $8.1 million net increase in fair value, which consists of a $0.5 million pre-tax gain in other comprehensive
income (loss) and a $7.6 million gain in change in fair value of derivative instruments. As of December 31, 2013, the credit valuation adjustments resulted in an $11.1 million net
increase in fair value, which consists of a $0.5 million pre-tax gain in other comprehensive income (loss) and a $10.6 million gain in change in fair value of derivative instruments.
8. 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. We have one contract designated as a
cash flow hedge, and we defer the effective portion of the change in fair value of the derivatives in accumulated other comprehensive income (loss), until the hedged transactions occur and are
recognized in earnings (loss). The ineffective portion of a cash flow hedge is immediately recognized in earnings (loss).
For
our other derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings (loss). The guidelines apply to our natural
gas swaps, interest rate swaps, and foreign exchange contracts.
Gas purchase agreements at our North Bay, Kapuskasing and Nipigon projects do not qualify for the normal purchase normal sales ("NPNS")
exemption and are accounted for as derivative financial instruments. The gas purchase agreements at North Bay and Kapuskasing satisfy all of the forecasted fuel requirements for these projects through
their expiration on December 31, 2016. The gas purchase agreement for Nipigon satisfies the majority of forecasted fuel requirements through December 31, 2022. These derivative financial
instruments are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations.
In
June 2014, the Partnership entered into contracts for the purchase of 2.9 million Gigajoules ("Gj") of future natural gas purchases beginning on November 1, 2014 and
expiring on December 31, 2017 for our projects in Ontario. These contracts effectively fix the price of approximately 98% of our expected uncontracted gas requirements for each of 2014 and 2015
and 32% and 30% of our expected uncontracted gas requirements for 2016 and 2017, respectively. These contracts are accounted for as derivative financial instruments and are recorded in the
consolidated balance sheet at fair value at June 30, 2014. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations.
24
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
8. Accounting for derivative instruments and hedging activities (Continued)
Our strategy to mitigate future exposure to changes in natural gas prices at our projects 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 sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations.
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 previously entered
into natural gas swaps to effectively fix the price of 4.5 million Mmbtu of future natural gas purchases. On February 20, 2014, we paid $4.0 million to terminate a portion of
these contracts in connection with the termination of our prior revolving credit facility. We recorded fuel expense related to the settlement of these contracts in the consolidated statement of
operations.
We
have entered into various natural gas swaps to effectively fix the price of 7.1 million Mmbtu of future natural gas purchases at Orlando, which is approximately 100% of our
share of the expected on-peak natural gas purchases at the project through 2016 or approximately 89%, 62% and 63% of our share of the expected base load natural gas purchases for 2014, 2015 and 2016,
respectively. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at June 30, 2014. Changes in the fair market
value of these contracts are recorded in the consolidated statement of operations.
The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.0% through February 15,
2015, 6.1% from February 16, 2015 to February 15, 2019, 6.3% from February 16, 2019 to February 15, 2023, and 6.4% 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 the effective portion of the changes in the fair market value is recorded in accumulated other comprehensive income (loss).
The
Piedmont project has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreement
effectively converts the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.8% through February 29, 2016. From February 2016 until the maturity
of the debt in November 2017, the fixed rate of the swap is 4.47% and the applicable margin is 4.0%, resulting in an all-in rate of 8.5%. The swap continues at the fixed rate of 4.47% from the
maturity of the debt in November 2017 until November 2030. Prior to conversion of the Piedmont Construction loan facility to a term loan, the notional amounts of the interest rate swap agreements
matched the estimated outstanding principal balance of Piedmont's construction loan facility. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on
February 29, 2016 and November 30, 2030, respectively. As a result of the Piedmont term loan conversion on February 14, 2014, these swap agreements were amended to reduce the
notional amounts to match the outstanding $68.5 million principal of the term loan. We recorded $1.0 million of deferred financing costs related to
25
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
8. Accounting for derivative instruments and hedging activities (Continued)
this
transaction in the consolidated balance sheets. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements
of operations.
Rockland
Wind Farm, LLC ("Rockland") entered into interest rate swaps to manage interest rate risk exposure. These swaps effectively modify the project's exposure by converting
the project's floating rate debt to a fixed basis. The interest rate swaps are with various counterparties and swap 100% of the expected interest payments from floating LIBOR to fixed rates structured
in two tranches. The first tranche is for the expected interest payments for the current period through December 31, 2026 and fixes the interest rate at 4.2% plus an applicable margin of
2.3%-2.8%. The second tranche is for the expected interest payments for the period beginning December 31, 2026 and ending December 31, 2031, fixing the interest rate at 7.8%. The
interest rate swap agreements are not designated as a hedge and changes in their fair market value are recorded in the consolidated statements of operations.
The
Meadow Creek project ("Meadow Creek") has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest
rate swap agreements effectively convert 75% of the floating rate debt to a fixed interest rate of 2.3% plus an applicable margin of 2.8%-3.3% through December 31, 2024. The second tranche is
the post-term portion of the loan, or the balloon payment and commences on December 31, 2024 and ends on December 31, 2030, fixing the interest rate at 7.2%. The interest rate swaps were
both executed on September 17, 2012 and expire on December 31, 2024 and December 31, 2030, respectively. The interest rate swap agreements are not designated as hedges, and
changes in their fair market value are recorded in the consolidated statements of operations.
Epsilon
Power Partners, our wholly owned subsidiary, previously had 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 7.37% and had a maturity date of July 2019. The notional amount of the swap
matched the outstanding principal balance over the remaining life of Epsilon Power Partners' debt. On February 20, 2014, we paid $2.6 million to terminate this contract in connection
with the termination of our prior revolving credit facility. We recorded interest expense related to its settlement in the consolidated statement of operations. This interest rate swap agreement was
not designated as a hedge and changes in its fair market value were recorded in the consolidated statements of operations.
On
May 5, 2014 the Partnership entered into interest rate swap agreements to mitigate exposure to changes in the Adjusted Eurodollar Rate for $199.0 million notional amount
of the $600 million aggregate principal amount of borrowings under the New Term Loan Facility. Borrowings under the $600 million New Term Loan Facility bear interest at a rate equal to
the Adjusted Eurodollar Rate plus an applicable margin of 3.75%. Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00% resulting in a minimum of a 4.75%
all-in rate on the New Term Loan Facility. As a result of entering into the swap agreements, the all-in rate for $199.0 million of the New
Term Loan Facility cannot be less than 4.91% if the Adjusted Eurodollar Rate is equal to or greater than 1.00%. If the Adjusted Eurodollar Rate is below 1.00%, we will pay interest at a rate
equivalent to the minimum 4.75% all-in rate plus any difference between the actual Adjusted Eurodollar Rate and 1.16%.
26
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
8. Accounting for derivative instruments and hedging activities (Continued)
The interest rate swap agreements are effective June 30, 2014 and terminate on December 29, 2017. The interest rate swap agreements are not designated as hedges and changes
in their fair market value will be recorded in the consolidated statements of operations.
From time to time, we use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates, as many of
our projects generate cash flow in U.S. dollars and Canadian dollars. On February 20, 2014, we paid $0.4 million to terminate all of our remaining foreign currency forward contracts in
connection with the termination of our prior revolving credit facility and recorded their settlement in foreign exchange gain in the consolidated statement of operations for the three months ended
March 31, 2014. On April 2, 2014, we executed a new foreign currency forward contract in which we agreed to sell $41.0 million on September 30, 2014 and receive
Cdn$45.3 million at a foreign exchange rate of Cdn$1.105 per U.S. dollar in order to mitigate the foreign exchange risk on the retirement of the Cdn$44.8 million convertible debentures
due in October 2014.
We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as
summarized below, by type,
excluding those derivatives that qualified for the NPNS exemption as of June 30, 2014 and December 31, 2013:
|
|
|
|
|
|
|
|
|
|
|
|
Units
|
|
June 30,
2014
|
|
December 31,
2013
|
|
Natural gas swaps
|
|
Natural Gas (Mmbtu)
|
|
|
7.1
|
|
|
5.6
|
|
Gas purchase agreements
|
|
Natural Gas (Gj)
|
|
|
38.9
|
|
|
41.1
|
|
Interest rate swaps
|
|
Interest (US$)
|
|
|
152.4
|
|
|
161.2
|
|
Currency forwards
|
|
Cdn$
|
|
|
45.3
|
|
|
34.9
|
|
27
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
8. Accounting for derivative instruments and hedging activities (Continued)
We have elected to disclose derivative instrument assets and liabilities on a trade-by-trade basis and do not offset amounts at the
counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities:
|
|
|
|
|
|
|
|
|
|
June 30, 2014
|
|
|
|
Derivative
Assets
|
|
Derivative
Liabilities
|
|
Derivative instruments designated as cash flow hedges:
|
|
|
|
|
|
|
|
Interest rate swaps current
|
|
$
|
|
|
$
|
1.3
|
|
Interest rate swaps long-term
|
|
|
|
|
|
3.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative instruments designated as cash flow hedges
|
|
|
|
|
|
4.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments not designated as cash flow hedges:
|
|
|
|
|
|
|
|
Interest rate swaps current
|
|
|
|
|
|
7.8
|
|
Interest rate swaps long-term
|
|
|
6.3
|
|
|
12.6
|
|
Foreign currency forward contracts current
|
|
|
1.4
|
|
|
|
|
Foreign currency forward contracts long-term
|
|
|
|
|
|
|
|
Natural gas swaps current
|
|
|
0.3
|
|
|
0.2
|
|
Natural gas swaps long-term
|
|
|
|
|
|
0.7
|
|
Gas purchase agreements current
|
|
|
|
|
|
19.1
|
|
Gas purchase agreements long-term
|
|
|
|
|
|
41.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative instruments not designated as cash flow hedges
|
|
|
8.0
|
|
|
82.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative instruments
|
|
$
|
8.0
|
|
$
|
86.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
8. Accounting for derivative instruments and hedging activities (Continued)
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
|
|
Derivative
Assets
|
|
Derivative
Liabilities
|
|
Derivative instruments designated as cash flow hedges:
|
|
|
|
|
|
|
|
Interest rate swaps current
|
|
$
|
|
|
$
|
1.3
|
|
Interest rate swaps long-term
|
|
|
|
|
|
2.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative instruments designated as cash flow hedges
|
|
|
|
|
|
3.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments not designated as cash flow hedges:
|
|
|
|
|
|
|
|
Interest rate swaps current
|
|
|
|
|
|
7.3
|
|
Interest rate swaps long-term
|
|
|
11.5
|
|
|
8.1
|
|
Foreign currency forward contracts current
|
|
|
0.5
|
|
|
0.7
|
|
Foreign currency forward contracts long-term
|
|
|
1.2
|
|
|
|
|
Natural gas swaps current
|
|
|
0.3
|
|
|
1.3
|
|
Natural gas swaps long-term
|
|
|
|
|
|
3.5
|
|
Gas purchase agreements current
|
|
|
0.2
|
|
|
18.4
|
|
Gas purchase agreements long-term
|
|
|
|
|
|
61.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative instruments not designated as cash flow hedges
|
|
|
13.7
|
|
|
101.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative instruments
|
|
$
|
13.7
|
|
$
|
105.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 months ended June 30, 2014
|
|
Interest Rate
Swaps
|
|
Accumulated OCI balance at March 31, 2014
|
|
$
|
0.1
|
|
Change in fair value of cash flow hedges
|
|
|
(0.3
|
)
|
Realized from OCI during the period
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at June 30, 2014
|
|
$
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended June 30, 2013
|
|
Interest Rate
Swaps
|
|
Natural Gas
Swaps
|
|
Total
|
|
Accumulated OCI balance at March 31, 2013
|
|
$
|
(1.2
|
)
|
$
|
0.1
|
|
$
|
(1.1
|
)
|
Change in fair value of cash flow hedges
|
|
|
0.6
|
|
|
|
|
|
0.6
|
|
Realized from OCI during the period
|
|
|
0.2
|
|
|
(0.1
|
)
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at June 30, 2013
|
|
$
|
(0.4
|
)
|
$
|
|
|
$
|
(0.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
8. Accounting for derivative instruments and hedging activities (Continued)
|
|
|
|
|
For the six months ended June 30, 2014
|
|
Interest Rate
Swaps
|
|
Accumulated OCI balance at January 1, 2014
|
|
$
|
0.2
|
|
Change in fair value of cash flow hedges
|
|
|
(0.7
|
)
|
Realized from OCI during the period
|
|
|
0.4
|
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at June 30, 2014
|
|
$
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the six months ended June 30, 2013
|
|
Interest Rate
Swaps
|
|
Natural Gas
Swaps
|
|
Total
|
|
Accumulated OCI balance at January 1, 2013
|
|
$
|
(1.5
|
)
|
$
|
0.1
|
|
$
|
(1.4
|
)
|
Change in fair value of cash flow hedges
|
|
|
0.6
|
|
|
|
|
|
0.6
|
|
Realized from OCI during the period
|
|
|
0.5
|
|
|
(0.1
|
)
|
|
0.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at June 30, 2013
|
|
$
|
(0.4
|
)
|
$
|
|
|
$
|
(0.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes realized (gains) and losses for derivative instruments not designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
June 30,
|
|
|
|
Classification of (gain) loss
recognized in income
|
|
|
|
2014
|
|
2013
|
|
Natural gas swaps
|
|
Fuel
|
|
$
|
(0.2
|
)
|
$
|
|
|
Gas purchase agreements
|
|
Fuel
|
|
|
13.4
|
|
|
14.1
|
|
Interest rate swaps
|
|
Interest, net
|
|
|
(3.6
|
)
|
|
(10.8
|
)
|
Foreign currency forwards
|
|
Foreign exchange loss
|
|
|
|
|
|
4.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended
June 30,
|
|
|
|
Classification of (gain) loss
recognized in income
|
|
|
|
2014
|
|
2013
|
|
Natural gas swaps
|
|
Fuel
|
|
$
|
3.7
|
|
$
|
|
|
Gas purchase agreements
|
|
Fuel
|
|
|
29.3
|
|
|
30.4
|
|
Interest rate swaps
|
|
Interest, net
|
|
|
(7.8
|
)
|
|
(13.3
|
)
|
Foreign currency forwards
|
|
Foreign exchange (gain) loss
|
|
|
(0.1
|
)
|
|
6.6
|
|
30
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
8. 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
June 30,
|
|
|
|
Classification of (gain) loss
recognized in income
|
|
|
|
2014
|
|
2013
|
|
Natural gas swaps
|
|
Change in fair value of derivatives
|
|
$
|
1.0
|
|
$
|
1.1
|
|
Gas purchase agreements
|
|
Change in fair value of derivatives
|
|
|
(2.6
|
)
|
|
(7.4
|
)
|
Interest rate swaps
|
|
Change in fair value of derivatives
|
|
|
4.4
|
|
|
(18.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total change in fair value of derivative instruments
|
|
|
|
$
|
2.8
|
|
$
|
(24.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency forwards
|
|
Foreign exchange (gain) loss
|
|
$
|
(1.4
|
)
|
$
|
12.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended
June 30,
|
|
|
|
Classification of (gain) loss
recognized in income
|
|
|
|
2014
|
|
2013
|
|
Natural gas swaps
|
|
Change in fair value of derivatives
|
|
$
|
(3.5
|
)
|
$
|
0.7
|
|
Gas purchase agreements
|
|
Change in fair value of derivatives
|
|
|
(18.6
|
)
|
|
(15.5
|
)
|
Interest rate swaps
|
|
Change in fair value of derivatives
|
|
|
10.2
|
|
|
(22.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total change in fair value of derivative instruments
|
|
|
|
$
|
(11.9
|
)
|
$
|
(36.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency forwards
|
|
Foreign exchange (gain) loss
|
|
$
|
(0.3
|
)
|
$
|
18.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9. Income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
June 30,
|
|
Six months ended
June 30,
|
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
Current income tax expense
|
|
$
|
1.4
|
|
$
|
3.4
|
|
$
|
2.6
|
|
$
|
5.4
|
|
Deferred tax benefit
|
|
|
(2.0
|
)
|
|
(2.8
|
)
|
|
(15.5
|
)
|
|
(7.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax (benefit), net
|
|
$
|
(0.6
|
)
|
$
|
0.6
|
|
$
|
(12.9
|
)
|
$
|
(1.9
|
)
|
Income
tax benefit for the three months ended June 30, 2014 was $0.6 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate
of 26%, was $14.8 million. The primary items impacting the tax rate for the three months ended June 30, 2014 were $14.2 million relating to a change in the valuation allowance,
$2.4 million relating to foreign exchange, and $1.1 million of other permanent differences. These items were partially offset by $3.5 million relating to operating in higher tax
rate jurisdictions.
Income
tax benefit for the six months ended June 30, 2014 was $12.9 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate
of 26%, was $23.8 million. The primary items impacting the tax rate for the six months ended June 30, 2014 were $29.3 million
31
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
9. Income taxes (Continued)
relating
to a change in the valuation allowance, $2.6 million relating to minority interest adjustments, and $0.5 million of other permanent differences. These items were partially
offset by $11.1 million of capital losses recognized on tax restructuring, $9.2 million relating to operating in higher tax rate jurisdictions, and $1.2 million relating to
foreign exchange.
As
of June 30, 2014, we have recorded a valuation allowance of $157.4 million. The amount is comprised primarily of provisions against 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.
10. Equity compensation plans
The following table summarizes the changes in LTIP notional units during the three months ended June 30, 2014:
|
|
|
|
|
|
|
|
|
|
Units
|
|
Grant Date
Weighted-Average
Price per Unit
|
|
Outstanding at December 31, 2013
|
|
|
766,988
|
|
$
|
7.86
|
|
Granted
|
|
|
1,776,083
|
|
|
2.64
|
|
Reinvested
|
|
|
99,452
|
|
|
4.12
|
|
Forfeited
|
|
|
(182,783
|
)
|
|
8.00
|
|
Vested
|
|
|
(242,160
|
)
|
|
8.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2014
|
|
|
2,217,580
|
|
$
|
3.41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Certain
awards have a market condition based on our total shareholder return during the performance period compared to a group of peer companies and, in some cases, Project Adjusted
EBITDA per common share compared to budget. Compensation expense for notional units granted in 2014 is recorded net of estimated forfeitures. See Note 16 to the consolidated financial
statements in our Annual Report on Form 10-K for the year ended December 31, 2013 for further details. Cash payments made for vested notional units for the six months ended
June 30, 2014 and 2013 was $0.2 million and $0.9 million, respectively. Compensation expense for LTIP was $1.0 million and $0.9 million for the three and six months
ended June 30, 2014, respectively and $0.8 million and $1.2 million for the three and six months ended June 30, 2013, respectively.
32
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
11. 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, 2013. 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 (loss)
and potentially dilutive shares utilized in the per share calculation for the three and six months ended June 30, 2014 and 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
June 30,
|
|
Six months ended
June 30,
|
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing operations attributable to Atlantic Power Corporation
|
|
$
|
(59.2
|
)
|
$
|
2.4
|
|
$
|
(77.9
|
)
|
$
|
8.4
|
|
Loss from discontinued operations, net of tax
|
|
|
|
|
|
(5.4
|
)
|
|
(0.1
|
)
|
|
(4.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to Atlantic Power Corporation
|
|
$
|
(59.2
|
)
|
$
|
(3.0
|
)
|
$
|
(78.0
|
)
|
$
|
3.5
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average basic shares outstanding
|
|
|
120.6
|
|
|
119.9
|
|
|
120.5
|
|
|
119.7
|
|
Dilutive potential shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible debentures
|
|
|
27.7
|
|
|
27.7
|
|
|
27.7
|
|
|
27.7
|
|
LTIP notional units
|
|
|
0.4
|
|
|
0.8
|
|
|
0.2
|
|
|
0.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potentially dilutive shares
|
|
|
148.7
|
|
|
148.4
|
|
|
148.4
|
|
|
148.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted (loss) earnings per share from continuing operations attributable to Atlantic Power Corporation
|
|
$
|
(0.49
|
)
|
$
|
0.02
|
|
$
|
(0.65
|
)
|
$
|
0.07
|
|
Diluted loss per share from discontinued operations
|
|
|
|
|
|
(0.05
|
)
|
|
|
|
|
(0.04
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted (loss) income per share attributable to Atlantic Power Corporation
|
|
$
|
(0.49
|
)
|
$
|
(0.03
|
)
|
$
|
(0.65
|
)
|
$
|
0.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potentially
dilutive shares from convertible debentures and LTIP notional units have been excluded from fully diluted shares for the three and six months ended June 30, 2014 and
2013 because their impact would be anti-dilutive.
12. Discontinued operations
On March 6, 2014, we sold our outstanding membership interests in Greeley for approximately $1.0 million and recorded a $2.1 million non-cash gain on the sale
related to the write-off of asset retirement obligations. Greeley is accounted for as a component of discontinued operations in the consolidated statements of operations for the three and six months
ended June 30, 2014 and 2013, respectively.
33
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
12. Discontinued operations (Continued)
On
November 5, 2013, we completed the sale of our 60% interest in Rollcast to its remaining shareholders. As consideration for the sale, we were assigned asset management
contracts valued at $0.5 million for the Cadillac and Piedmont projects as well as the remaining 2% ownership interest in Piedmont bringing our total ownership to 100%. In return, we paid
$0.5 million in cash to the minority owner and forgave an outstanding $1.0 million loan that was provided by us to Rollcast to fund working capital during 2013. Rollcast's net loss is
recorded as loss from discontinued operations in the consolidated statements of operations for the three and six months ended June 30, 2013.
The
Florida Projects and Path 15 were sold on April 12, 2013 and April 30, 2013, respectively. Accordingly, the projects' net income (loss) is recorded as income (loss)
from discontinued operations, net of tax in the statements of operations for the three and six months ended June 30, 2013.
The
following tables summarize the revenue, income (loss) from operations, and income tax expense of Greeley, Rollcast, Path 15 and the Florida Projects for the three and six months
ended June 30, 2014 and 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
June 30,
|
|
Six months ended
June 30,
|
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
Revenue
|
|
$
|
|
|
$
|
11.4
|
|
$
|
|
|
$
|
77.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from operations of discontinued businesses
|
|
|
|
|
|
(5.0
|
)
|
|
(0.1
|
)
|
|
(4.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
|
|
|
|
0.4
|
|
|
|
|
|
0.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from operations of discontinued businesses, net of tax
|
|
$
|
|
|
$
|
(5.4
|
)
|
$
|
(0.1
|
)
|
$
|
(4.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
and diluted earnings (loss) per share related to income (loss) from discontinued operations for Greeley, Rollcast, the Florida Projects and Path 15 was $0.00 and $(0.05) for the
three months ended June 30, 2014 and 2013, respectively, and $0.00 and $0.04 for the six months ended June 30, 2014 and 2013, respectively.
34
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
13. 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 interests and total equity for the six months ended June 30, 2014 and 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2014
|
|
|
|
Total Atlantic Power
Corporation
Shareholders' Equity
|
|
Preferred shares
issued by a subsidiary
company
|
|
Noncontrolling
Interests
|
|
Total Equity
|
|
Balance at January 1
|
|
$
|
608.3
|
|
$
|
221.3
|
|
$
|
266.4
|
|
$
|
1,096.0
|
|
Net (loss) income
|
|
|
(78.0
|
)
|
|
5.9
|
|
|
(6.7
|
)
|
|
(78.8
|
)
|
Realized and unrealized gain on hedging activities, net of tax
|
|
|
(0.2
|
)
|
|
|
|
|
|
|
|
(0.2
|
)
|
Foreign currency translation adjustment, net of tax
|
|
|
(1.5
|
)
|
|
|
|
|
|
|
|
(1.5
|
)
|
Common shares issued for LTIP
|
|
|
0.6
|
|
|
|
|
|
|
|
|
0.6
|
|
Dividends paid to noncontrolling interest
|
|
|
|
|
|
|
|
|
(5.2
|
)
|
|
(5.2
|
)
|
Dividends declared on common shares
|
|
|
(21.1
|
)
|
|
|
|
|
|
|
|
(21.1
|
)
|
Dividends declared on preferred shares of a subsidiary company
|
|
|
|
|
|
(5.9
|
)
|
|
|
|
|
(5.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at June 30
|
|
$
|
508.1
|
|
$
|
221.3
|
|
$
|
254.5
|
|
$
|
983.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2013
|
|
|
|
Total Atlantic Power
Corporation
Shareholders' Equity
|
|
Preferred shares
issued by a subsidiary
company
|
|
Noncontrolling
Interests
|
|
Total Equity
|
|
Balance at January 1
|
|
$
|
729.7
|
|
$
|
221.3
|
|
$
|
235.4
|
|
$
|
1,186.4
|
|
Net income (loss)
|
|
|
3.5
|
|
|
6.3
|
|
|
(0.8
|
)
|
|
9.0
|
|
Realized and unrealized gain on hedging activities, net of tax
|
|
|
1.0
|
|
|
|
|
|
|
|
|
1.0
|
|
Foreign currency translation adjustment, net of tax
|
|
|
(30.1
|
)
|
|
|
|
|
|
|
|
(30.1
|
)
|
Common shares issued for LTIP
|
|
|
0.9
|
|
|
|
|
|
|
|
|
0.9
|
|
Contribution by and sale of noncontrolling interest
|
|
|
|
|
|
|
|
|
44.5
|
|
|
44.5
|
|
Costs associated with tax equity raise
|
|
|
(0.9
|
)
|
|
|
|
|
|
|
|
(0.9
|
)
|
Dividends paid to noncontrolling interest
|
|
|
|
|
|
|
|
|
(2.9
|
)
|
|
(2.9
|
)
|
Dividends declared on common shares
|
|
|
(35.5
|
)
|
|
|
|
|
|
|
|
(35.5
|
)
|
Dividends declared on preferred shares of a subsidiary company
|
|
|
|
|
|
(6.3
|
)
|
|
|
|
|
(6.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at June 30
|
|
$
|
668.6
|
|
$
|
221.3
|
|
$
|
276.2
|
|
$
|
1,166.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
14. Segment and geographic information
We have four reportable segments: East, West, Wind and Un-allocated Corporate. We revised our reportable business segments in the fourth quarter of 2013 as a result of significant
project asset sales and in order to align our reportable business segments with changes in management's structure, resource allocation and performance assessment in making decisions regarding our
operations. Our financial results for the three and six months ended June 30, 2014 and 2013 have been presented to reflect these changes in operating segments. We analyze the performance of our
operating segments based on Project Adjusted EBITDA which 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. Greeley and Path 15, which are components of the West segment, the Florida Projects, components
of the East segment, and Rollcast, which is a component of Un-allocated Corporate, are included in the income (loss) from discontinued operations line item in the table below. We have adjusted prior
periods to reflect this reclassification. A reconciliation of project income (loss) to Project Adjusted EBITDA is included in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
East
|
|
West
|
|
Wind
|
|
Un-allocated
Corporate
|
|
Consolidated
|
|
Three months ended June 30, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project revenues
|
|
$
|
76.2
|
|
$
|
46.8
|
|
$
|
20.0
|
|
$
|
0.2
|
|
$
|
143.2
|
|
Segment assets
|
|
|
1,192.3
|
|
|
977.6
|
|
|
818.1
|
|
|
222.7
|
|
|
3,210.7
|
|
Project Adjusted EBITDA
|
|
$
|
38.5
|
|
$
|
22.9
|
|
$
|
17.2
|
|
$
|
(3.6
|
)
|
$
|
75.0
|
|
Change in fair value of derivative instruments
|
|
|
(0.8
|
)
|
|
|
|
|
2.8
|
|
|
1.1
|
|
|
3.1
|
|
Depreciation and amortization
|
|
|
24.4
|
|
|
16.2
|
|
|
11.5
|
|
|
0.2
|
|
|
52.3
|
|
Interest, net
|
|
|
3.7
|
|
|
|
|
|
4.8
|
|
|
0.1
|
|
|
8.6
|
|
Other project expense
|
|
|
14.8
|
|
|
|
|
|
|
|
|
|
|
|
14.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project income (loss)
|
|
|
(3.6
|
)
|
|
6.7
|
|
|
(1.9
|
)
|
|
(5.0
|
)
|
|
(3.8
|
)
|
Administration
|
|
|
|
|
|
|
|
|
|
|
|
10.2
|
|
|
10.2
|
|
Interest, net
|
|
|
|
|
|
|
|
|
|
|
|
27.7
|
|
|
27.7
|
|
Foreign exchange (loss) gain
|
|
|
|
|
|
|
|
|
|
|
|
15.3
|
|
|
15.3
|
|
Other income, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
(3.6
|
)
|
|
6.7
|
|
|
(1.9
|
)
|
|
(58.2
|
)
|
|
(57.0
|
)
|
Income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
(0.6
|
)
|
|
(0.6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(3.6
|
)
|
$
|
6.7
|
|
$
|
(1.9
|
)
|
$
|
(57.6
|
)
|
$
|
(56.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
14. Segment and geographic information (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
East
|
|
West
|
|
Wind
|
|
Un-allocated
Corporate
|
|
Consolidated
|
|
Three months ended June 30, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project revenues
|
|
$
|
71.9
|
|
$
|
45.8
|
|
$
|
18.2
|
|
$
|
0.2
|
|
$
|
136.1
|
|
Segment assets
|
|
|
1,468.7
|
|
|
1,056.0
|
|
|
907.4
|
|
|
135.3
|
|
|
3,567.4
|
|
Project Adjusted EBITDA
|
|
$
|
29.4
|
|
$
|
14.1
|
|
$
|
15.5
|
|
$
|
(3.1
|
)
|
$
|
55.9
|
|
Change in fair value of derivative instruments
|
|
|
(10.6
|
)
|
|
|
|
|
(15.3
|
)
|
|
(0.9
|
)
|
|
(26.8
|
)
|
Depreciation and amortization
|
|
|
21.8
|
|
|
17.1
|
|
|
11.4
|
|
|
0.2
|
|
|
50.5
|
|
Interest, net
|
|
|
5.5
|
|
|
0.1
|
|
|
4.9
|
|
|
(1.0
|
)
|
|
9.5
|
|
Other project expense
|
|
|
0.5
|
|
|
|
|
|
|
|
|
1.9
|
|
|
2.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project income (loss)
|
|
|
12.2
|
|
|
(3.1
|
)
|
|
14.5
|
|
|
(3.3
|
)
|
|
20.3
|
|
Administration
|
|
|
|
|
|
|
|
|
|
|
|
11.8
|
|
|
11.8
|
|
Interest, net
|
|
|
|
|
|
|
|
|
|
|
|
25.3
|
|
|
25.3
|
|
Foreign exchange gain
|
|
|
|
|
|
|
|
|
|
|
|
(14.5
|
)
|
|
(14.5
|
)
|
Other income, net
|
|
|
|
|
|
|
|
|
|
|
|
(9.5
|
)
|
|
(9.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
12.2
|
|
|
(3.1
|
)
|
|
14.5
|
|
|
(16.4
|
)
|
|
7.2
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
0.6
|
|
|
0.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations
|
|
|
12.2
|
|
|
(3.1
|
)
|
|
14.5
|
|
|
(17.0
|
)
|
|
6.6
|
|
Loss from discontinued operations
|
|
|
(1.2
|
)
|
|
1.2
|
|
|
|
|
|
(5.4
|
)
|
|
(5.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
11.0
|
|
$
|
(1.9
|
)
|
$
|
14.5
|
|
$
|
(22.4
|
)
|
$
|
1.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
14. Segment and geographic information (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
East
|
|
West
|
|
Wind
|
|
Un-allocated
Corporate
|
|
Consolidated
|
|
Six months ended June 30, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project revenues
|
|
$
|
162.8
|
|
$
|
85.3
|
|
$
|
40.1
|
|
$
|
0.3
|
|
$
|
288.5
|
|
Segment assets
|
|
|
1,192.3
|
|
|
977.6
|
|
|
818.1
|
|
|
222.7
|
|
|
3,210.7
|
|
Project Adjusted EBITDA
|
|
$
|
84.0
|
|
$
|
34.1
|
|
$
|
35.1
|
|
$
|
(3.6
|
)
|
$
|
149.6
|
|
Change in fair value of derivative instruments
|
|
|
(22.6
|
)
|
|
|
|
|
10.4
|
|
|
1.2
|
|
|
(11.0
|
)
|
Depreciation and amortization
|
|
|
48.8
|
|
|
32.6
|
|
|
22.8
|
|
|
0.5
|
|
|
104.7
|
|
Interest, net
|
|
|
15.3
|
|
|
|
|
|
9.4
|
|
|
|
|
|
24.7
|
|
Other project expense
|
|
|
14.8
|
|
|
|
|
|
|
|
|
|
|
|
14.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project income (loss)
|
|
|
27.7
|
|
|
1.5
|
|
|
(7.5
|
)
|
|
(5.3
|
)
|
|
16.4
|
|
Administration
|
|
|
|
|
|
|
|
|
|
|
|
17.5
|
|
|
17.5
|
|
Interest, net
|
|
|
|
|
|
|
|
|
|
|
|
94.1
|
|
|
94.1
|
|
Foreign exchange (loss) gain
|
|
|
|
|
|
|
|
|
|
|
|
(1.5
|
)
|
|
(1.5
|
)
|
Other income, net
|
|
|
|
|
|
|
|
|
|
|
|
(2.1
|
)
|
|
(2.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
27.7
|
|
|
1.5
|
|
|
(7.5
|
)
|
|
(113.3
|
)
|
|
(91.6
|
)
|
Income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
(12.9
|
)
|
|
(12.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations
|
|
|
27.7
|
|
|
1.5
|
|
|
(7.5
|
)
|
|
(100.4
|
)
|
|
(78.7
|
)
|
Loss from discontinued operations
|
|
|
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
27.7
|
|
$
|
1.4
|
|
$
|
(7.5
|
)
|
$
|
(100.4
|
)
|
$
|
(78.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
14. Segment and geographic information (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
East
|
|
West
|
|
Wind
|
|
Un-allocated
Corporate
|
|
Consolidated
|
|
Six months ended June 30, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project revenues
|
|
$
|
151.7
|
|
$
|
86.4
|
|
$
|
35.7
|
|
$
|
(0.2
|
)
|
$
|
273.6
|
|
Segment assets
|
|
|
1,468.7
|
|
|
1,056.0
|
|
|
907.4
|
|
|
135.3
|
|
|
3,567.4
|
|
Project Adjusted EBITDA
|
|
$
|
78.5
|
|
$
|
34.7
|
|
$
|
30.5
|
|
$
|
(7.6
|
)
|
$
|
136.1
|
|
Change in fair value of derivative instruments
|
|
|
(20.0
|
)
|
|
|
|
|
(18.3
|
)
|
|
|
|
|
(38.3
|
)
|
Depreciation and amortization
|
|
|
44.2
|
|
|
34.2
|
|
|
23.7
|
|
|
0.2
|
|
|
102.3
|
|
Interest, net
|
|
|
9.9
|
|
|
0.1
|
|
|
9.8
|
|
|
(0.1
|
)
|
|
19.7
|
|
Other project expense
|
|
|
1.0
|
|
|
|
|
|
|
|
|
(0.4
|
)
|
|
0.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project income (loss)
|
|
|
43.4
|
|
|
0.4
|
|
|
15.3
|
|
|
(7.3
|
)
|
|
51.8
|
|
Administration
|
|
|
|
|
|
|
|
|
|
|
|
20.1
|
|
|
20.1
|
|
Interest, net
|
|
|
|
|
|
|
|
|
|
|
|
51.2
|
|
|
51.2
|
|
Foreign exchange gain
|
|
|
|
|
|
|
|
|
|
|
|
(22.0
|
)
|
|
(22.0
|
)
|
Other income, net
|
|
|
|
|
|
|
|
|
|
|
|
(9.5
|
)
|
|
(9.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
43.4
|
|
|
0.4
|
|
|
15.3
|
|
|
(47.1
|
)
|
|
12.0
|
|
Income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
(1.9
|
)
|
|
(1.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) from continuing operations
|
|
|
43.4
|
|
|
0.4
|
|
|
15.3
|
|
|
(45.2
|
)
|
|
13.9
|
|
Loss from discontinued operations
|
|
|
(0.9
|
)
|
|
1.8
|
|
|
|
|
|
(5.8
|
)
|
|
(4.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
42.5
|
|
$
|
2.2
|
|
$
|
15.3
|
|
$
|
(51.0
|
)
|
$
|
9.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
table below provides information, by country, about our consolidated operations for the three and six months ended June 30, 2014 and 2013 and Property, Plant &
Equipment as of June 30, 2014 and December 31, 2013, respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are
located.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and
Equipment, net of
accumulated depreciation
|
|
|
|
Project Revenue
Three months ended
June 30,
|
|
Project Revenue
Six months ended
June 30,
|
|
|
|
June 30,
2014
|
|
December 31,
2013
|
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
United States
|
|
$
|
98.2
|
|
$
|
91.0
|
|
$
|
191.3
|
|
$
|
161.1
|
|
$
|
1,296.6
|
|
$
|
1,330.5
|
|
Canada
|
|
|
45.0
|
|
|
45.1
|
|
|
97.2
|
|
|
112.5
|
|
|
454.6
|
|
|
482.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
143.2
|
|
$
|
136.1
|
|
$
|
288.5
|
|
$
|
273.6
|
|
$
|
1,751.2
|
|
$
|
1,813.4
|
|
Ontario
Electricity Financial Corp ("OEFC"), San Diego Gas & Electric, and BC Hydro provided 21.9%, 16.7%, and 9.6%, respectively, of total consolidated revenues for the three
months ended June 30, 2014 and 25.0%, 15.0%, and 8.7%, respectively, of total consolidated revenues for the six months ended June 30, 2014. OEFC, San Diego Gas & Electric and BC
Hydro provided 22.6%, 15.9%, and 10.3%, respectively, of total consolidated revenues for the three months ended June 30, 2013 and
39
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
14. Segment and geographic information (Continued)
29.7%,
13.7%, and 11.3%, respectively, of total consolidated revenues for the six months ended June 30, 2013. OEFC purchases electricity from the Calstock, Kapuskasing, Nipigon, North Bay and
Tunis projects in the East segment. San Diego Gas & Electric purchases electricity from the Naval Station, Naval Training Center, and North Island projects in the West segment. BC Hydro
purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the West segment.
15. Guarantees
We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts
include asset purchases and sale agreements, joint venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and other third parties, as well as
affiliates. These
contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these
agreements.
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. 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 cash distributions made to the investors and any amount equal to the net federal income tax benefits
arising from production tax credits.
16. Contingencies
Shareholder class action lawsuits
Massachusetts District Court Actions
On
March 8, 14, 15 and 25, 2013 and April 23, 2013, five purported securities fraud class action complaints were filed by alleged investors in
Atlantic Power common shares in the United States District Court for the District of Massachusetts (the "District Court") against
Atlantic Power and Barry E. Welch, our President and Chief Executive Officer and a Director of Atlantic Power, in each of the actions, and, in addition to Mr. Welch, some or all of
Patrick J. Welch, our former Chief Financial Officer, Lisa Donahue, our former interim Chief Financial Officer, and Terrence Ronan, our current Chief Financial Officer, in certain of the actions (the
"Proposed Individual Defendants," and together with Atlantic Power, the "Proposed Defendants") (the "U.S. Actions").
The
District Court complaints differed in terms of the identities of the Proposed Individual Defendants they named, as noted above, the named plaintiffs, and the purported class period
they alleged (July 23, 2010 to March 4, 2013 in three of the District Court actions and August 8, 2012 to February 28, 2013 in the other two District Court actions), but in
general each alleged, among other things, that in Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, Atlantic Power and the Proposed
Individual Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power's common share
40
Table of Contents
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
16. Contingencies (Continued)
dividend
that artificially inflated the price of Atlantic Power's common shares. The District Court complaints assert claims under Section 10(b) and, against the Proposed Individual Defendants,
under Section 20(a) of the Securities Exchange Act of 1934, as amended.
The
parties to each District Court action filed joint motions requesting that the District Court set a schedule in the District Court actions, including: (i) setting a deadline
for the lead plaintiff to file a consolidated amended class action complaint (the "Amended Complaint"), after the appointment of lead plaintiff and counsel; (ii) setting a deadline for
Proposed Defendants to answer, file a motion to dismiss or otherwise respond to the Amended Complaint (and for subsequent briefing regarding any such motion to dismiss); and
(iii) confirming that the Proposed Defendants need not answer, move to dismiss or otherwise respond to any of the five District Court complaints prior to the filing of the Amended Complaint. On
May 7, 2013, each of six groups of investors (the "U.S. Lead Plaintiff Applicants") filed a motion (collectively, the "U.S. Lead Plaintiff Motions") with the District Court seeking:
(i) to consolidate the five U.S. Actions (the "Consolidated U.S. Action"); (ii) to be appointed lead plaintiff in the Consolidated U.S. Action; and (iii) to have its choice of
lead counsel confirmed. On May 22, 2013, three of the U.S. Lead Plaintiff Applicants filed oppositions to the other U.S. Lead Plaintiff Motions, and on June 6, 2013, those three Lead
Plaintiff Applicants filed replies in support of their respective motions. On August 19, 2013, the District Court held a status conference to address certain issues raised by the U.S. Lead
Plaintiff Motions, entered an order consolidating the five U.S. Actions, and directed two of the six U.S. Lead Plaintiff Applicants to file supplemental submissions by September 9, 2013. Both
of those U.S. Lead Plaintiff Applicants filed the requested supplemental submissions, and then sought leave to file additional briefing. The Court granted those requests for leave and additional
submissions were filed on September 13 and September 18, 2013.
On
March 31, 2014, the Court entered an order consolidating the five individual U.S. Actions, appointing the Feldman, Shapero, Carter and Smith investor group (one of the six U.S.
Lead Plaintiffs Applicants) as Lead Plaintiff and approving Lead Plaintiff's selection of counsel. The Court also granted the parties' joint motion regarding initial case scheduling and directed the
parties to resubmit a proposed schedule that contains specific dates. In response to that directive, on April 7, 2014, Lead Plaintiff filed an application and proposed order, which sought an
extension of the schedule contained in the joint motion. The application and proposed order requested that: (i) Lead Plaintiff be permitted to file an amended complaint on or before
May 30, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or otherwise respond to the amended complaint on or before July 29, 2014, (iii) Lead Plaintiff be
permitted to file an opposition, if any, on or before September 24, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead Plaintiff's opposition on or before
November 13, 2014. Proposed Defendants did not object to the schedule proposed by Lead Plaintiff. On May 29, 2014, Lead Plaintiff filed a renewed application and proposed order, which
sought another extension of the schedule, and on June 3, 2014, Lead Plaintiff and the Proposed Defendants jointly filed a stipulation and proposed order requesting the following revised
schedule: (i) Lead Plaintiff be permitted to file an amended complaint on or before June 6, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or otherwise respond
to the amended complaint on or before August 5, 2014, (iii) Lead Plaintiff be permitted to file an opposition, if any, on or before October 6, 2014, and
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ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
16. Contingencies (Continued)
(iv) the
Proposed Defendants be permitted to file a reply to Lead Plaintiff's opposition on or before November 20, 2014. On June 3, 2014, the Court entered an order setting
this requested schedule.
On
June 6, 2014, Lead Plaintiff filed the amended complaint (the "Amended Complaint"). The Amended Complaint names as defendants Barry E. Welch and Terrence Ronan (the "Individual
Defendants") and Atlantic Power (together with the Individual Defendants, the "Defendants") and alleges a class period of June 20, 2011 to March 4, 2013 (the "Class Period"). The Amended
Complaint makes allegations that are substantially similar to those asserted in the five initial complaints. Specifically, the Amended Complaint alleges, among other things, that in Atlantic Power's
press releases, quarterly and year-end filings and conference calls with analysts and investors, Defendants made materially false and misleading statements and omissions regarding the sustainability
of Atlantic Power's common share dividend, which artificially inflated the price of Atlantic Power's common shares during the class period. The Amended Complaint continues to assert claims under
Section 10(b) and, against the Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended. It also asserts a claim for unjust enrichment against the
Individual Defendants. In accordance with the schedule referenced above, Defendants filed their motion to dismiss the consolidated U.S. Action on August 5, 2014.
On
March 19, 2013, April 2, 2013 and May 10, 2013, three notices of action relating to Canadian securities class action claims against the
Proposed Defendants were also issued by alleged investors in Atlantic Power common shares, and in one of the actions, holders of Atlantic Power convertible debentures, with the Ontario Superior Court
of Justice in the Province of Ontario. On April 8, 2013, a similar claim issued by alleged investors in Atlantic Power common shares seeking to initiate a class action against the Proposed
Defendants was filed with the Superior Court of Quebec in the Province of Quebec (the "Canadian Actions").
On
April 17, May 22, and June 7, 2013 statements of claim relating to the notices of action were filed with the Ontario Superior Court of Justice in the Province of
Ontario.
On
August 30, 2013, the three Ontario actions were succeeded by one action with an amended claim being issued on behalf of Jacqeline Coffin and Sandra Lowry. As in the U.S.
Action, this claim names the Company, Barry E. Welch and Terrence Ronan as Defendants. The Plaintiffs seeks leave to commence an action for statutory misrepresentation under the Ontario Securities Act
and asserts common law claims for misrepresentation. The Plaintiffs' allegations focus on among other things, claims the Defendants made materially false and misleading statements and omissions in
Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, regarding the sustainability of Atlantic Power's common share dividend that
artificially inflated the price of Atlantic Power's common shares. The Plaintiffs seek to certify the statutory and common law claims under the Class Proceedings Act for security holders who purchased
and held securities through a proposed class period of November 5, 2012 to February 28, 2013.
On
October 4, 2013, the Plaintiffs delivered materials supporting their request for leave to commence an action for statutory misrepresentations and for certification of the
statutory and common
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ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in millions U.S. dollars, except per-share amounts)
(Unaudited)
16. Contingencies (Continued)
claims
as class proceedings. These materials estimate the damages claimed for statutory misrepresentation at $197.4 million.
The
Defendants are preparing materials to contest leave and certification.
A
schedule for the Plaintiffs' motions and the action is set that contemplates a hearing on leave and certification during the week of March 30, 2015.
The
proposed class action in Quebec is stayed until March 30, 2015 to follow the action in Ontario.
Pursuant
to the Private Securities Litigation Reform Act of 1995, all discovery is stayed in the U.S. Actions. Plaintiffs have not yet specified an amount of alleged damages in the U.S.
Actions. As noted above, the plaintiffs in the Canadian Action have estimated their alleged statutory damages at $197.4 million. Because both the U.S. and Canadian Actions are in their early
stages, Atlantic Power is unable to reasonably estimate the possible loss or range of losses, if any, arising from this litigation. Atlantic Power intends to defend vigorously against each of the
actions.
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. At
June 30, 2014, the examination is before the IRS Office of Appeals.
We
continue 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. We believe an adjustment, if any, would be offset by net operating loss carry forwards. No accrual has been made for any contingency related
to any of the proposed adjustments as of June 30, 2014.
In addition to the other matters listed, from time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes
and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There
are no matters pending which are expected to have a
material adverse impact on our financial position or results of operations or have been reserved for as of June 30, 2014.
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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:
-
-
our ability to generate sufficient cash flow to pay dividends, service our debt obligations or finance internal or
external growth opportunities;
-
-
our ability to evaluate and/or implement a broad range of potential strategic options and the impact any such potential
options may have on us or our stock price;
-
-
our ability to meet the financial covenants under our New Senior Secured Credit Facilities and other indebtedness;
-
-
expectations regarding maintenance and capital expenditures; 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 included in the filings Atlantic Power makes from time to time with the SEC and the risk factors
described under "Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2013. Our business is both highly competitive and subject to various
risks.
These
risks include, without limitation:
-
-
our ability to generate sufficient cash flow to pay dividends, if and when declared by our board of directors, service
our debt obligations or finance internal or external growth opportunities;
-
-
the ability to evaluate and/or implement a broad range of potential options, including further selected asset sales or
joint ventures to raise additional capital for growth or potential debt reduction, the acquisition of assets, the dividend level, as well as broader strategic options, including a sale or merger of
the Company, and the impact any such potential options may have on us or our stock price;
-
-
the impact of our failure to meet the fixed charge coverage ratio test in the restricted payments covenants of the
indenture governing our 9.0% senior unsecured notes;
-
-
our indebtedness and financing arrangements and the terms, covenants and restrictions included in our New Senior Secured
Credit Facilities;
-
-
exchange rate fluctuations;
-
-
the impact of downgrades in our credit rating or the credit rating of our outstanding debt securities, and changes in our
creditworthiness;
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-
-
unstable capital and credit markets;
-
-
the outcome of certain shareholder class action lawsuits;
-
-
the expiration or termination of power purchase agreements and our ability to renew or enter into new power purchase
agreements on favorable terms or at all;
-
-
the dependence of our projects on their electricity and thermal energy customers;
-
-
exposure of certain of our projects to fluctuations in the price of electricity or natural gas;
-
-
the dependence of our projects on third-party suppliers;
-
-
projects not operating according to plan;
-
-
the effects of weather, which affects demand for electricity and fuel as well as operating conditions;
-
-
the dependence of our wind power projects on suitable wind and associated conditions and of our hydropower projects on
suitable precipitation and associated weather conditions;
-
-
U.S., Canadian and/or global economic conditions and uncertainty;
-
-
risks beyond our control, including but not limited to geopolitical crisis, acts of terrorism or related acts of war,
natural disasters or other catastrophic events;
-
-
the adequacy of our insurance coverages;
-
-
the impact of significant energy, environmental and other regulations on our projects;
-
-
the impact of impairment of goodwill or long-lived assets;
-
-
increased competition, including for acquisitions;
-
-
our limited control over the operation of certain minority-owned projects;
-
-
transfer restrictions on our equity interests in certain projects;
-
-
risks inherent in the use of derivative instruments;
-
-
labor disruptions;
-
-
the impact of hostile cyber intrusions;
-
-
the impact of our failure to comply with the U.S. Foreign Corrupt Practices Act and/or Canadian Corruption of Foreign
Public Officials Act; and
-
-
our ability to retain, motivate and recruit executives and other key employees.
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 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 Quarterly Report on
Form 10-Q and, except as expressly required by applicable law, we assume no obligation to update or revise them to reflect new events or circumstances.
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