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EX-32.2 - EX-32.2 - ATLANTIC POWER CORPat-20160930ex3226b7a46.htm
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EX-31.2 - EX-31.2 - ATLANTIC POWER CORPat-20160930ex3128495c2.htm
EX-31.1 - EX-31.1 - ATLANTIC POWER CORPat-20160930ex3116bca32.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549


FORM 10‑Q

 

 

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

For the quarterly period ended September 30, 2016

OR

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

For the transition period from          to        

 

COMMISSION FILE NUMBER 001‑34691

ATLANTIC POWER CORPORATION

(Exact name of registrant as specified in its charter)

 

 

British Columbia, Canada
(State or other jurisdiction of
incorporation or organization)

55‑0886410
(I.R.S. Employer
Identification No.)

3 Allied Drive, Suite 220
Dedham, MA
(Address of principal executive offices)

02026
(Zip code)

 

(617) 977‑2400

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b‑2 of the Exchange Act. (Check one):

 

 

 

 

Large accelerated filer ☐

Accelerated filer ☒

Non‑accelerated filer ☐
(Do not check if a
smaller reporting company)

Smaller reporting company ☐

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Yes ☐  No ☒

The number of shares outstanding of the registrant’s Common Stock as of November 4, 2016 was 115,635,212.

 

 

 

 


 

 

ATLANTIC POWER CORPORATION

 

FORM 10‑Q

 

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2016

 

Index

 

 

    

 

PART I—FINANCIAL INFORMATION

 

 

ITEM 1.

CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

 

 

 

Consolidated Balance Sheets as of September 30, 2016 (unaudited) and December 31, 2015

 

 

Consolidated Statements of Operations for the three and nine months ended September 30, 2016 and September 30, 2015 (unaudited)

 

 

Consolidated Statements of Comprehensive Loss for the three and nine months ended September 30, 2016 and September 30, 2015 (unaudited)

 

 

Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and September 30, 2015 (unaudited)

 

 

Notes to Consolidated Financial Statements (unaudited)

 

ITEM 2. 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

37 

ITEM 3. 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

61 

ITEM 4. 

CONTROLS AND PROCEDURES

 

61 

 

PART II—OTHER INFORMATION

 

 

ITEM 1A. 

RISK FACTORS

 

63 

ITEM 2. 

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

64 

ITEM 6. 

EXHIBITS

 

64 

 

 

 

 


 

 

GENERAL

 

In this Quarterly Report on Form 10‑Q, references to “Cdn$” and “Canadian dollars” are to the lawful currency of Canada and references to “$” and “US$” and “U.S. dollars” are to the lawful currency of the United States. All dollar amounts herein are in U.S. dollars, unless otherwise indicated.

 

Unless otherwise stated, or the context otherwise requires, references in this Quarterly Report on Form 10‑Q to “we,” “us,” “our,” “Atlantic Power” and the “Company” refer to Atlantic Power Corporation, those entities owned or controlled by Atlantic Power Corporation and predecessors of Atlantic Power Corporation.

3


 

ATLANTIC POWER CORPORATION

 

CONSOLIDATED BALANCE SHEETS

 

(in millions of U.S. dollars)

 

 

 

 

 

 

 

 

 

 

September 30, 

 

December 31, 

 

 

 

2016

 

2015

    

 

 

 

(unaudited)

 

 

 

 

Assets

    

 

    

    

 

    

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

93.8

 

$

72.4

 

Restricted cash

 

 

12.6

 

 

15.2

 

Accounts receivable

 

 

39.5

 

 

39.6

 

Current portion of derivative instruments asset (Notes 8 and 9)

 

 

1.6

 

 

 —

 

Inventory

 

 

15.9

 

 

16.9

 

Prepayments

 

 

10.1

 

 

8.3

 

Other current assets

 

 

2.5

 

 

4.5

 

Total current assets

 

 

176.0

 

 

156.9

 

Property, plant, and equipment, net of accumulated depreciation of $279.2 million and $236.3 million at September 30, 2016 and December 31, 2015, respectively

 

 

749.8

 

 

777.7

 

Equity investments in unconsolidated affiliates (Note 5)

 

 

277.6

 

 

286.2

 

Power purchase agreements and intangible assets, net of accumulated amortization of $282.5 million and $238.0 million at September 30, 2016 and December 31, 2015, respectively

 

 

273.0

 

 

308.9

 

Goodwill (Note 3)

 

 

37.6

 

 

134.5

 

Derivative instruments asset (Notes 8 and 9)

 

 

1.3

 

 

0.3

 

Deferred income taxes

 

 

1.0

 

 

 —

 

Other assets

 

 

5.6

 

 

6.7

 

Total assets

 

$

1,521.9

 

$

1,671.2

 

Liabilities

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Accounts payable

 

$

3.7

 

$

6.9

 

Accrued interest

 

 

10.9

 

 

1.6

 

Other accrued liabilities

 

 

24.3

 

 

25.4

 

Current portion of long-term debt (Note 6)

 

 

101.4

 

 

15.8

 

Current portion of derivative instruments liability (Notes 8 and 9)

 

 

15.2

 

 

36.7

 

Other current liabilities

 

 

4.1

 

 

2.5

 

Total current liabilities

 

 

159.6

 

 

88.9

 

Long-term debt, net of unamortized discount and deferred financing costs (Note 6)

 

 

778.9

 

 

682.7

 

Convertible debentures, net of unamortized deferred financing costs (Note 7)

 

 

101.4

 

 

277.7

 

Derivative instruments liability (Notes 8 and 9)

 

 

27.3

 

 

20.8

 

Deferred income taxes

 

 

69.8

 

 

85.7

 

Power purchase and fuel supply agreement liabilities, net of accumulated amortization of $15.9 million and $14.0 million at September 30, 2016 and December 31, 2015, respectively

 

 

26.2

 

 

27.0

 

Other long-term liabilities

 

 

54.9

 

 

53.2

 

Total liabilities

 

 

1,218.1

 

 

1,236.0

 

Equity

 

 

 

 

 

 

 

Common shares, no par value, unlimited authorized shares; 117,029,308 and 122,153,082 issued and outstanding at September 30, 2016 and December 31, 2015, respectively (Note 13)

 

 

1,278.1

 

 

1,290.6

 

Accumulated other comprehensive loss (Note 2)

 

 

(142.0)

 

 

(139.3)

 

Retained deficit (Note 13)

 

 

(1,053.6)

 

 

(937.4)

 

Total Atlantic Power Corporation shareholders’ equity

 

 

82.5

 

 

213.9

 

Preferred shares issued by a subsidiary company (Note 13)

 

 

221.3

 

 

221.3

 

Total equity

 

 

303.8

 

 

435.2

 

Total liabilities and equity

 

$

1,521.9

 

$

1,671.2

 

 

See accompanying notes to consolidated financial statements.

4


 

ATLANTIC POWER CORPORATION

 

CONSOLIDATED STATEMENTS OF OPERATIONS

 

(in millions of U.S. dollars, except per share amounts)

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30, 

 

Nine Months Ended September 30, 

 

 

 

2016

 

2015

 

2016

    

2015

 

Project revenue:

    

 

    

    

 

    

    

 

    

 

 

    

    

Energy sales

 

$

40.7

 

$

43.4

 

$

138.4

 

$

144.9

 

Energy capacity revenue

 

 

44.0

 

 

45.9

 

 

113.2

 

 

117.4

 

Other

 

 

16.5

 

 

18.2

 

 

54.2

 

 

59.5

 

 

 

 

101.2

 

 

107.5

 

 

305.8

 

 

321.8

 

Project expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel

 

 

36.8

 

 

41.1

 

 

110.8

 

 

125.3

 

Operations and maintenance

 

 

28.2

 

 

24.8

 

 

79.4

 

 

81.6

 

Development

 

 

 —

 

 

 —

 

 

 —

 

 

1.1

 

Depreciation and amortization

 

 

25.3

 

 

27.8

 

 

75.6

 

 

83.8

 

 

 

 

90.3

 

 

93.7

 

 

265.8

 

 

291.8

 

Project other income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Change in fair value of derivative instruments (Notes 8 and 9)

 

 

9.0

 

 

3.6

 

 

20.0

 

 

8.7

 

Equity in earnings of unconsolidated affiliates (Note 5)

 

 

9.6

 

 

8.9

 

 

27.9

 

 

28.3

 

Interest, net

 

 

(2.4)

 

 

(2.1)

 

 

(6.9)

 

 

(6.2)

 

Impairment (Note 3)

 

 

(84.7)

 

 

 —

 

 

(84.7)

 

 

 —

 

Other income, net

 

 

0.5

 

 

 —

 

 

0.4

 

 

2.2

 

 

 

 

(68.0)

 

 

10.4

 

 

(43.3)

 

 

33.0

 

Project (loss) income

 

 

(57.1)

 

 

24.2

 

 

(3.3)

 

 

63.0

 

Administrative and other expenses (income):

 

 

 

 

 

 

 

 

 

 

 

 

 

Administration

 

 

5.7

 

 

6.9

 

 

17.6

 

 

23.0

 

Interest, net

 

 

20.0

 

 

41.0

 

 

87.9

 

 

91.3

 

Foreign exchange (gain) loss

 

 

(3.4)

 

 

(21.7)

 

 

19.1

 

 

(49.1)

 

Other income, net (Note 7)

 

 

(1.7)

 

 

 —

 

 

(3.9)

 

 

(3.1)

 

 

 

 

20.6

 

 

26.2

 

 

120.7

 

 

62.1

 

(Loss) income from continuing operations before income taxes

 

 

(77.7)

 

 

(2.0)

 

 

(124.0)

 

 

0.9

 

Income tax expense (benefit) (Note 10)

 

 

2.6

 

 

1.4

 

 

(14.2)

 

 

(0.3)

 

(Loss) income from continuing operations

 

 

(80.3)

 

 

(3.4)

 

 

(109.8)

 

 

1.2

 

Net (loss) income from discontinued operations, net of tax (Note 4)

 

 

 —

 

 

(0.5)

 

 

 —

 

 

20.6

 

Net (loss) income

 

 

(80.3)

 

 

(3.9)

 

 

(109.8)

 

 

21.8

 

Net loss attributable to noncontrolling interests

 

 

 —

 

 

 —

 

 

 —

 

 

(11.0)

 

Net income attributable to preferred shares dividends of a subsidiary company

 

 

2.1

 

 

2.1

 

 

6.4

 

 

6.7

 

Net (loss) income attributable to Atlantic Power Corporation

 

$

(82.4)

 

$

(6.0)

 

$

(116.2)

 

$

26.1

 

Basic and diluted (loss) income per share: (Note 12)

 

 

 

 

 

 

 

 

 

 

 

 

 

Loss from continuing operations attributable to Atlantic Power Corporation

 

$

(0.69)

 

$

(0.05)

 

$

(0.96)

 

$

(0.05)

 

Income from discontinued operations, net of tax

 

 

 

 

 —

 

 

 

 

0.26

 

Net (loss) income attributable to Atlantic Power Corporation

 

$

(0.69)

 

$

(0.05)

 

$

(0.96)

 

$

0.21

 

Weighted average number of common shares outstanding: (Note 12)

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

119.3

 

 

122.1

 

 

120.9

 

 

121.8

 

Diluted

 

 

119.3

 

 

122.2

 

 

120.9

 

 

121.9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dividends per common share:

 

$

 —

 

$

0.02

 

$

 —

 

$

0.07

 

 

 

See accompanying notes to consolidated financial statements.

 

5


 

ATLANTIC POWER CORPORATION

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

 

(in millions of U.S. dollars)

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30, 

 

Nine Months Ended September 30, 

 

 

 

 

2016

 

2015

 

2016

 

2015

 

 

Net (loss) income

    

$

(80.3)

    

$

(3.9)

    

$

(109.8)

    

$

21.8

 

    

Other comprehensive (loss) income, net of tax:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrealized (loss) gain on hedging activities

 

$

 —

 

$

(0.4)

 

$

(0.6)

 

$

(0.8)

 

 

Net amount reclassified to earnings

 

 

0.2

 

 

0.2

 

 

0.5

 

 

0.6

 

 

Net unrealized gain (loss) on derivatives

 

 

0.2

 

 

(0.2)

 

 

(0.1)

 

 

(0.2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign currency translation adjustments

 

 

(22.0)

 

 

(22.1)

 

 

(2.6)

 

 

(52.7)

 

 

Other comprehensive loss, net of tax

 

 

(21.8)

 

 

(22.3)

 

 

(2.7)

 

 

(52.9)

 

 

Comprehensive loss

 

 

(102.1)

 

 

(26.2)

 

 

(112.5)

 

 

(31.1)

 

 

Less: Comprehensive income (loss) attributable to noncontrolling interests

 

 

2.1

 

 

2.1

 

 

6.4

 

 

(4.3)

 

 

Comprehensive loss attributable to Atlantic Power Corporation

 

$

(104.2)

 

$

(28.3)

 

$

(118.9)

 

$

(26.8)

 

 

 

See accompanying notes to consolidated financial statements.

6


 

ATLANTIC POWER CORPORATION

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(in millions of U.S. dollars)

 

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

Nine months ended

 

 

 

September 30, 

 

 

 

2016

 

2015

 

Cash provided by operating activities:

    

 

    

    

 

    

    

Net (loss) income

 

$

(109.8)

 

$

21.8

 

Adjustments to reconcile net (loss) income to net cash provided by operating activities:

 

 

 

 

 

 

 

Depreciation and amortization

 

 

75.6

 

 

94.1

 

Gain from discontinued operations

 

 

 —

 

 

(47.2)

 

Gain on sale of development project and other assets

 

 

 —

 

 

(2.3)

 

Gain on purchase and cancellation of convertible debentures

 

 

(4.7)

 

 

(3.1)

 

Loss on disposal of fixed assets

 

 

0.2

 

 

 —

 

Stock-based compensation expense

 

 

1.4

 

 

2.1

 

Long-lived asset and goodwill impairment

 

 

84.7

 

 

 —

 

Equity in earnings from unconsolidated affiliates

 

 

(27.9)

 

 

(28.3)

 

Distributions from unconsolidated affiliates

 

 

36.5

 

 

40.0

 

Unrealized foreign exchange loss (gain)

 

 

19.1

 

 

(49.3)

 

Change in fair value of derivative instruments

 

 

(20.0)

 

 

(8.0)

 

Change in deferred income taxes

 

 

(16.8)

 

 

23.6

 

Change in other operating balances

 

 

 

 

 

 

 

Accounts receivable

 

 

 —

 

 

4.3

 

Inventory

 

 

1.1

 

 

1.7

 

Prepayments and other assets

 

 

42.1

 

 

20.2

 

Accounts payable

 

 

0.3

 

 

(6.1)

 

Accruals and other liabilities

 

 

10.1

 

 

4.2

 

Cash provided by operating activities:

 

 

91.9

 

 

67.7

 

Cash provided by investing activities:

 

 

 

 

 

 

 

Change in restricted cash

 

 

2.6

 

 

8.0

 

Proceeds from sale of assets and equity investments, net

 

 

 —

 

 

326.3

 

Contribution to unconsolidated affiliate

 

 

 —

 

 

(0.5)

 

Capitalized development costs

 

 

 —

 

 

(0.8)

 

Reimbursement of costs for third-party construction project

 

 

4.7

 

 

 —

 

Purchase of property, plant and equipment

 

 

(6.5)

 

 

(9.4)

 

Cash provided by investing activities

 

 

0.8

 

 

323.6

 

Cash used in financing activities:

 

 

 

 

 

 

 

Proceeds from senior secured term loan facility, net of discount

 

 

679.0

 

 

 —

 

Common share repurchases

 

 

(13.9)

 

 

 —

 

Repayment of corporate and project-level debt

 

 

(526.4)

 

 

(387.1)

 

Repayment of convertible debentures

 

 

(187.4)

 

 

(18.7)

 

Deferred financing costs

 

 

(16.2)

 

 

 —

 

Dividends paid to common shareholders

 

 

 —

 

 

(8.5)

 

Dividends paid to noncontrolling interests

 

 

 —

 

 

(3.8)

 

Dividends paid to preferred shareholders

 

 

(6.4)

 

 

(6.7)

 

Cash used in financing activities

 

 

(71.3)

 

 

(424.8)

 

Increase (decrease) in cash and cash equivalents

 

 

21.4

 

 

(33.5)

 

Less cash at discontinued operations

 

 

 —

 

 

3.9

 

Cash and cash equivalents at beginning of period at discontinued operations

 

 

 —

 

 

 —

 

Cash and cash equivalents at beginning of period

 

 

72.4

 

 

106.0

 

Cash and cash equivalents at end of period

 

$

93.8

 

$

76.4

 

Supplemental cash flow information

 

 

 

 

 

 

 

Interest paid

 

$

43.3

 

$

75.5

 

Income taxes paid, net

 

$

2.8

 

$

4.1

 

Accruals for construction in progress

 

$

0.4

 

$

1.2

 

 

 

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

 

General

 

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 September 30, 2016, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,138 megawatts (“MW”) in which our aggregate ownership interest is approximately 1,500 MW. Our current portfolio consists of interests in twenty-three operational power generation projects across nine states in the United States and two provinces in Canada. Eighteen of our projects are majority‑owned subsidiaries.

 

Atlantic Power is a corporation established under the laws of the Province of Ontario 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 215-10451 Shellbridge Way, Richmond, British Columbia V6X 2W8 Canada and our headquarters is located at 3 Allied Drive, Suite 220, Dedham, Massachusetts 02026, USA. Our telephone number in Dedham 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, 2015. Interim results are not necessarily indicative of results for the full year.

 

In our opinion, the accompanying unaudited interim consolidated financial statements present fairly our consolidated financial position as of September 30, 2016, the results of operations and comprehensive loss for the three and nine months ended September 30, 2016 and 2015, and our cash flows for the nine months ended September 30, 2016 and 2015 in accordance with U.S generally accepted accounting policies. In the opinion of management, all adjustments (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 useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to

8


 

Table of Contents

ATLANTIC POWER CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

(in millions U.S. dollars, except per‑share amounts)

 

(Unaudited)

 

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 equity-based compensation. 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 Operations—Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2015. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

 

Recently issued accounting standards

 

Adopted

 

In January 2015, the Financial Accounting Standards Board (“FASB”) issued changes to the presentation of extraordinary items. Such items are defined as transactions or events that are both unusual in nature and infrequent in occurrence, and, currently, are required to be presented separately in an entity’s statement of operations, net of income tax, after income from continuing operations. The changes eliminate the concept of an extraordinary item and, therefore, the presentation of such items will no longer be required. Notwithstanding this change, an entity will still be required to present and disclose a transaction or event that is both unusual in nature and infrequent in occurrence in the notes to the financial statements. These changes became effective for us on January 1, 2016. The adoption of these changes did not have an impact on the consolidated financial statements.

 

In February 2015, the FASB issued changes to the analysis that an entity must perform to determine whether it should consolidate certain types of legal entities. These changes (i) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminate the presumption that a general partner should consolidate a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships, and (iv) provide a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. These changes became effective for us on January 1, 2016. The adoption of these changes did not have an impact on the consolidated financial statements.

 

In April 2015, the FASB issued changes to the presentation of debt issuance costs. Currently, such costs are required to be presented as a noncurrent asset in an entity’s balance sheet and amortized into interest expense over the term of the related debt instrument. The changes require that debt issuance costs be presented in an entity’s balance sheet as a direct deduction from the carrying value of the related debt liability. The amortization of debt issuance costs remains unchanged. These changes became effective for us on January 1, 2016. As a result, we have presented $19.5 million and $42.5 million of deferred financing costs as a direct deduction from long-term debt and convertible debentures for the periods ended September 30, 2016 and December 31, 2015, respectively. 

 

In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the statement of operations or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the

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ATLANTIC POWER CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

(in millions U.S. dollars, except per‑share amounts)

 

(Unaudited)

 

adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements became effective for us beginning January 1, 2016. We will apply this new guidance to any future business combinations.

 

Issued

 

In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for us beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. Management is currently evaluating the potential impact of this new guidance on our consolidated financial statements and which implementation approach to select.

 

In July 2015, the FASB issued changes to the subsequent measurement of inventory. Currently, an entity is required to measure its inventory at the lower of cost or market, whereby market can be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. The changes require that inventory be measured at the lower of cost and net realizable value, thereby eliminating the use of the other two market methodologies. Net realizable value is defined as the estimated selling prices in the ordinary course of business less reasonably predictable costs of completion, disposal, and transportation. These changes become effective for us on January 1, 2017. Management has determined that the adoption of these changes will not have a material impact on the consolidated financial statements.

 

In November 2015, the FASB issued changes to the balance sheet classification of deferred taxes. These changes simplify the presentation of deferred income taxes by requiring all deferred income tax assets and liabilities, along with any related valuation allowance, to be classified as noncurrent in a classified balance sheet. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by these changes. The new guidance will be effective for us in fiscal years beginning after December 15, 2016 and is not expected to have a material impact on the consolidated financial statements.

 

In February 2016, the FASB issued authoritative guidance intended to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new guidance, lessees will be required to recognize a right-of-use asset and a lease liability, measured on a discounted basis, at the commencement date for all leases with terms greater than twelve months. Additionally, this guidance will require disclosures to help investors and other financial statement users to better understand the amount, timing, and uncertainty of cash flows arising from leases, including qualitative and quantitative requirements. The guidance should be applied under a modified retrospective transition approach for leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. This guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the potential impact on our financial position and results of operations upon adoption of this guidance.

 

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ATLANTIC POWER CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

(in millions U.S. dollars, except per‑share amounts)

 

(Unaudited)

 

In March 2016, the FASB issued authoritative guidance intended to simplify and improve several aspects of the accounting for share-based payment transactions. The new guidance includes amendments to share-based accounting for income taxes, including adjustments to how excess tax benefits and a company's payments for tax withholdings should be classified in the statement of cash flows. This guidance is effective for annual and interim reporting periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the potential impact on our financial position and results of operations upon adoption of this guidance.

 

In August 2016, the FASB issued authoritative guidance intended to clarify classification of specific cash flows that have aspects of more than one class of cash flows. As a result of this new guidance, entities should be applying specific GAAP in the following eight cash flow issues: Debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The guidance is effective for fiscal years beginning after December 15, 2017, with early adoption permitted. The guidance is not expected to have a material impact on the consolidated financial statements.

 

2. Changes in accumulated other comprehensive loss by component

 

The changes in accumulated other comprehensive loss by component were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30, 

 

Nine Months Ended September 30, 

 

 

 

 

2016

 

2015

 

2016

    

2015

 

 

Foreign currency translation

    

 

    

    

 

    

    

 

    

 

 

    

    

 

Balance at beginning of period

 

$

(119.7)

 

$

(96.9)

 

$

(139.1)

 

$

(66.3)

 

 

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign currency translation adjustments(1)

 

 

(22.0)

 

 

(22.1)

 

 

(2.6)

 

 

(52.7)

 

 

Balance at end of period

 

$

(141.7)

 

$

(119.0)

 

$

(141.7)

 

$

(119.0)

 

 

Cash flow hedges

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at beginning of period

 

$

(0.1)

 

$

0.1

 

$

0.2

 

$

0.1

 

 

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net change from periodic revaluations

 

 

0.1

 

 

(0.7)

 

 

(1.0)

 

 

(1.3)

 

 

Tax (expense) benefit

 

 

(0.1)

 

 

0.3

 

 

0.4

 

 

0.5

 

 

Total Other comprehensive income before reclassifications, net of tax

 

 

 —

 

 

(0.4)

 

 

(0.6)

 

 

(0.8)

 

 

Net amount reclassified to earnings:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate swaps(2)

 

 

0.3

 

 

0.3

 

 

0.9

 

 

1.0

 

 

Tax expense

 

 

(0.1)

 

 

(0.1)

 

 

(0.4)

 

 

(0.4)

 

 

Total amount reclassified from Accumulated other comprehensive loss, net of tax

 

 

0.2

 

 

0.2

 

 

0.5

 

 

0.6

 

 

Total Other comprehensive income

 

 

0.2

 

 

(0.2)

 

 

(0.1)

 

 

(0.2)

 

 

Balance at end of period

 

$

0.1

 

$

(0.1)

 

$

0.1

 

$

(0.1)

 

 

 


(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.

 

 

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ATLANTIC POWER CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

(in millions U.S. dollars, except per‑share amounts)

 

(Unaudited)

 

 

 

3. Goodwill

 

Our goodwill balance was $37.6 million and $134.5 million as of September 30, 2016 and December 31, 2015, respectively. 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.

 

In the third quarter of 2016, we performed an event-driven goodwill impairment test. While declining power prices have been observed over the past two years, we identified a significant decrease in the long-term outlook for power prices in the regions where our reporting units operate in the third quarter of 2016. Because the estimated future cash flows of our reporting units are sensitive to fluctuations in forward power prices and these prices are the most impactful input in calculating a reporting unit’s fair value, we determined that it was appropriate to perform an event-driven impairment test. For two of our reporting units (Morris and Nipigon) we performed a qualitative assessment and concluded that it was likely that the fair values significantly exceed the carrying values. These reporting units have aggregate goodwill of $6.9 million and have PPAs with significant remaining time before their expiration and are not significantly impacted by the decrease in the long-term outlook for power prices.

 

The other five of the reporting units tested (Curtis Palmer, Mamquam, North Bay, Kapuskasing and Moresby Lake) failed step 1 of our quantitative two‑step test. Because five reporting units failed step 1 of the two-step goodwill impairment test, we identified a triggering event and initiated a test of the recoverability of their long-lived assets. The asset group for testing the long-lived assets for impairment is the same as the reporting unit for goodwill impairment testing purposes. In order to test the recoverability of the assets in the asset groups, we compared the carrying amount of the assets to estimated undiscounted future cash flows expected to be generated by the asset group. The carrying value of each asset group includes its recorded property, plant equipment, intangible assets related to PPAs and goodwill. Of the five asset groups tested, the North Bay and Kapuskasing asset groups (Canada segment) failed the recoverability test and we recorded property, plant and equipment impairment charges aggregating $5.9 million for the periods ended September 30, 2016. For these asset groups, we estimated their fair value utilizing an income approach based on market participant assumptions. These assumptions include estimated cash flows under the remaining period of their respective PPAs.

 

Subsequent to recording long-lived asset impairments, we performed the step 2 goodwill impairment test and recorded a $50.2 million full impairment at the Mamquam reporting unit, a $15.4 million partial impairment at the Curtis Palmer reporting unit, a $6.5 million full impairment at the North Bay reporting unit, a $6.7 million full impairment at the Kapuskasing reporting unit and no impairment at the Moresby Lake reporting unit for a total goodwill impairment charge of $78.8 million for the periods ended September 30, 2016. At the time of their acquisition in November 2011, the fair value of the assets acquired and liabilities assumed for the Mamquam and Curtis Palmer reporting units were valued assuming a merchant basis for the period subsequent to the expiration of the projects’ original PPAs. The forecasted energy revenue on a merchant basis, in the respective markets in which those plants operate, was higher than the energy prices currently forecasted to be in effect subsequent to the expiration of the reporting unit’s PPA. Power prices, in the respective markets in which those plants operate, have declined from 2011 and from the dates of our previous impairment assessments due to several factors including decreased demand, lower oil prices and lower natural gas prices resulting from an abundance of shale gas. Our forecasts for discounted cash flows also reflect a higher level of uncertainty for re‑contracting at prices than were previously forecasted in 2011. The decline in forward power prices for British Columbia since our last goodwill impairment performed as of November 30, 2015, in particular, had a significant impact on the estimated discounted cash flows of our Mamquam reporting unit and was the primary driver for its recorded goodwill impairment. British Columbia’s peak demand outlook has declined primarily attributable to a

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ATLANTIC POWER CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

(in millions U.S. dollars, except per‑share amounts)

 

(Unaudited)

 

reduction in forecasted liquefaction build and need in the region and the associated loss of power demand. The resulting drop in the peak demand reduces the amount of needed capacity and therefore the capacity prices also were reduced.  Furthermore, the PPA at the Curtis Palmer reporting unit expires at the earlier of December 2027 or the provision of 10,000 GWh of generation. Based on Curtis Palmer’s cumulative generation through the date of the goodwill impairment test, we anticipate the PPA expiring two years before December 2027. As a result, the discounted cash flow model for Curtis Palmer utilizes forward power prices for that two-year period that are substantially lower than the prices under the current PPA.

 

The long-lived asset and goodwill impairment charges were recorded in the third quarter of 2016 and not earlier in the fiscal year because we did not identify any triggering events that would have required an event-driven impairment assessment. While declining power prices have been observed over the past two years, the significant decrease in the long-term outlook for power prices in the regions where our reporting units operate identified in the third quarter of 2016 had the most significant impact to the key inputs to our long-term forecasted cash flow models. Additionally, the PPAs at our North Bay and Kapuskasing reporting units expire on December 31, 2017. As these projects approach the expiration date, the remaining estimated contracted future cash flows decrease.

 

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 merchant 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 and 2 goodwill impairment tests for our reporting units are generally based on approved reporting unit operating plans for years with contracted PPAs and historical relationships for estimates at the expiration of PPAs. 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 discount rate applied to the DCF models represents the weighted average cost of capital (“WACC”) consistent with the risk inherent in future cash flows of the particular reporting unit and is 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. We utilized the assistance of valuation experts to perform step 1 and step 2 of the quantitative impairment test for several of our reporting units. The fair value that could be realized in an actual transaction may differ from that used to evaluate the impairment of goodwill.

 

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ATLANTIC POWER CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

(in millions U.S. dollars, except per‑share amounts)

 

(Unaudited)

 

The valuation of long-lived assets and goodwill for the impairment analyses is considered a level 3 fair value measurement, 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. Fair value determinations require considerable judgment and are sensitive to changes in these underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of a goodwill impairment test will prove to be accurate predictions of the future. Examples of events or circumstances that could reasonably be expected to negatively affect the underlying key assumptions and ultimately impact the estimated fair value of our reporting units may include macroeconomic factors that significantly differ from our assumptions in timing or degree, increased input costs such as higher fuel prices and maintenance costs, or lower power prices than incorporated in our long-term forecasts.

 

The following table is a rollforward of goodwill for the nine months ended September 30, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

December 31, 

    

 

 

Translation

    

September 30, 

    

Reporting unit

 

Segment

 

2015

 

Impairment

 

adjustment

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Curtis Palmer

 

East U.S.

 

$

44.5

 

$

(15.4)

 

$

 —

 

$

29.1

 

Morris

 

East U.S.

 

 

3.3

 

 

 —

 

 

 —

 

 

3.3

 

Kapuskasing

 

Canada

 

 

8.8

 

 

(6.7)

 

 

(2.1)

 

 

 —

 

Mamquam

 

Canada

 

 

64.4

 

 

(50.2)

 

 

(14.2)

 

 

 —

 

Moresby Lake

 

Canada

 

 

1.6

 

 

 —

 

 

 —

 

 

1.6

 

Nipigon

 

Canada

 

 

3.6

 

 

 —

 

 

 —

 

 

3.6

 

North Bay

 

Canada

 

 

8.3

 

 

(6.5)

 

 

(1.8)

 

 

 —

 

 

 

 

 

$

134.5

 

$

(78.8)

 

$

(18.1)

 

$

37.6

 

 

 

 

4. Discontinued operations

 

On June 26, 2015, Atlantic Power Transmission, Inc. (“APT”), our wholly-owned, direct subsidiary, sold our Wind Projects under a definitive agreement (the “Purchase Agreement”) with TerraForm AP Acquisition Holdings, LLC (“TerraForm”), an affiliate of SunEdison, Inc. (an affiliate of TerraForm Power, Inc.). The sale was completed for aggregate cash proceeds of approximately $335 million after transaction fees, exclusive of transaction-related taxes. We recorded an approximate $47.2 million gain on sale, which is included as a component of income from discontinued operations in the consolidated statements of operations for the nine months ended September 30, 2015.

 

Terraform acquired from APT, 100% of APT’s direct membership interests in a holding company formed to facilitate the sale, thereby acquiring our indirect interests in our portfolio of Wind Projects consisting of five operating wind projects in Idaho and Oklahoma and representing 521 MW net ownership: Goshen (12.5% economic interest), Idaho Wind (27.6% economic interest), Meadow Creek (100% economic interest); Rockland Wind Farm (50% economic interest, but consolidated on a 100% basis); and Canadian Hills (99% economic interest). As a result of the sale, we deconsolidated approximately $249 million of project debt (or approximately $274 million as adjusted for our proportional ownership of Rockland, Goshen North and Idaho Wind) and approximately $224 million of non-controlling interest related to tax equity interests at Canadian Hills and the minority ownership interests at Rockland and Canadian Hills.

 

The Wind Projects were designated as assets held for sale and discontinued operations on March 31, 2015, the date we established a firm commitment to a plan to sell the wind assets. Our determination to designate the Wind Projects as discontinued operations was based on the impact the sale would have on our operations and financial results and because the Wind Projects made up the entirety of our Wind reportable segment. We stopped depreciating the property, plant and equipment of the Wind Projects on the designation date.

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ATLANTIC POWER CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

(in millions U.S. dollars, except per‑share amounts)

 

(Unaudited)

 

 

The following table summarizes the revenue and income from operations of the Wind Projects for the three and nine months ended September 30, 2015:

 

 

 

 

 

 

 

 

 

 

Three months

 

Nine months

 

 

ended

 

ended

 

 

September 30, 

 

September 30, 

 

 

2015

 

2015

Revenue

 

$

 —

 

$

34.8

Project expenses:

 

 

 

 

 

 

Operations and maintenance

 

 

 —

 

 

10.8

Depreciation and amortization

 

 

 —

 

 

10.3

 

 

 

 —

 

 

21.1

Project other expense:

 

 

 

 

 

 

Change in fair value of derivatives

 

 

 —

 

 

(0.7)

Equity in earnings of unconsolidated affiliates

 

 

 —

 

 

(0.3)

Interest expense, net

 

 

 —

 

 

(6.7)

Gain (loss) on sale of asset

 

 

(0.2)

 

 

47.2

 

 

 

(0.2)

 

 

39.5

Income (loss) from operations of discontinued businesses

 

 

(0.2)

 

 

53.2

Income tax expense

 

 

0.3

 

 

32.6

Income (loss) from operations of discontinued businesses, net of tax

 

 

(0.5)

 

 

20.6

Net loss attributable to noncontrolling interests of discontinued businesses

 

 

 —

 

 

(11.0)

Income (loss) from operations of discontinued businesses, net of noncontrolling interests

 

$

(0.5)

 

$

31.6

 

 

Basic and diluted earnings per share related to income (loss) from discontinued operations for the Wind Projects was $0.00 and $0.26 for the three and nine months ended September 30, 2015, respectively.

 

The following table summarizes the operating and investing cash flows of the Wind Projects for the nine months ended September 30, 2015:

 

 

 

 

 

 

Nine months

 

 

ended

 

 

September 30, 

 

 

2015

 

Cash provided by operating activities

$

21.9

 

Cash used in investing activities

 

(12.8)

 

 

 

 

 

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ATLANTIC POWER CORPORATION

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

(in millions U.S. dollars, except per‑share amounts)

 

(Unaudited)

 

5. Equity method investments in unconsolidated affiliates

 

The following summarizes the operating results for the three and nine months ended September 30, 2016 and 2015, respectively, for our equity method investments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended September 30, 

 

Nine Months Ended September 30, 

 

Operating results

    

2016

    

2015

    

2016

    

2015

    

Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

Chambers

 

$

11.2

 

$

11.0

 

$

34.3

 

$

37.3

 

Frederickson

 

 

5.8

 

 

5.8

 

 

15.7

 

 

15.9

 

Orlando

 

 

13.9

 

 

13.9

 

 

40.6

 

 

40.9

 

Other(1)

 

 

3.2

 

 

3.4

 

 

7.2

 

 

10.8

 

 

 

 

34.1

 

 

34.1

 

 

97.8

 

 

104.9

 

Project expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Chambers

 

 

9.3

 

 

9.2

 

 

27.8

 

 

30.2

 

Frederickson

 

 

4.9

 

 

5.1

 

 

14.3

 

 

14.1

 

Orlando

 

 

6.9

 

 

7.3

 

 

19.6

 

 

20.6

 

Other(1)

 

 

3.0

 

 

3.1

 

 

6.8

 

 

10.3

 

 

 

 

24.1

 

 

24.7

 

 

68.5

 

 

75.2

 

Project other expense

 

 

 

 

 

 

 

 

 

 

 

 

 

Chambers

 

 

(0.4)

 

 

(0.5)

 

 

(1.4)

 

 

(1.4)

 

Frederickson

 

 

 —

 

 

 —

 

 

 —

 

 

 —

 

Orlando

 

 

 —

 

 

 —

 

 

 —

 

 

 —

 

Other(1)

 

 

 —