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8 years ago
Atlantic Power Corporation Releases First Quarter 2017 Results
Source: PR Newswire (Canada)
DEDHAM, Mass., May 4, 2017 /CNW/ -- Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the "Company") today reported its financial results for the three months ended March 31, 2017. Net loss attributable to Atlantic Power Corporation of $(2.7) million improved from a loss of $(14.9) million in the 2016 period; higher depreciation expense at two plants in 2017 was more than offset by a reduction in foreign exchange loss compared to a year ago. Project Adjusted EBITDA increased to $63.8 million from $62.5 million in the year-ago period, reflecting higher margins at three Ontario plants (as discussed on page 2) and settlement of favorable fuel swaps at Orlando, partially offset by higher fuel prices, a lower PJM capacity price and other factors at Morris; lower water flows at Mamquam, and lower waste heat and a contractual price adjustment at Calstock. Net loss and Project Adjusted EBITDA did not include the benefit of the payments received in the first quarter of 2017 under the OEFC settlement, as the settlement was not finalized until April. Cash provided by operating activities increased to $34.1 million from $29.4 million in the 2016 period; the 2017 amount included the approximately US$8 million of cash received under the OEFC settlement in the first quarter.
Recent Developments
In April, achieved repricing of term loan and revolver, reducing spread by 75 basis points and saving $2.4 million in 2017 and $17 million over life of facilities, net of transaction costs
Also in April, reached a settlement with Ontario Electricity Financial Corporation (OEFC) for Cdn$36.1 million (US$26 million) of additional revenues related to Global Adjustment dispute
First Quarter 2017 Financial Highlights
Global Adjustment payments of Cdn$10.7 million received in Q1 2017 were recorded as deferred revenues; benefited operating cash flow but not revenues, income or Project Adjusted EBITDA
Will be included in revenue and Project Adjusted EBITDA in Q2 2017
Net loss of $(2.7) million in Q1 2017 vs. $(14.9) million in Q1 2016
Project income of $25.3 million in Q1 2017 vs. $28.7 million in Q1 2016
Project Adjusted EBITDA of $63.8 million in Q1 2017 vs. $62.5 million in Q1 2016
Cash provided by operating activities of $34.1 million in Q1 2017 vs. $29.4 million in Q1 2016
Repaid $27.3 million of term loan and project debt during Q1 2017; for full year 2017, expect to repay a total of $150 million or more
Ended the quarter with liquidity of $214 million, including $66 million of cash at the parent
Guidance
Increased 2017 Project Adjusted EBITDA guidance to include OEFC settlement (see page 5)
"We have continued to make progress in the two months since we reported our previous quarterly results, by repricing our $615 million term loan and revolving credit facility and reaching a settlement with the OEFC regarding the Global Adjustment dispute," said James J. Moore, Jr., President and CEO of Atlantic Power. "The repricing is expected to save $2.4 million in interest costs this year and $17 million over the remaining lives of the facilities, net of transaction costs. The $26 million of Global Adjustment payments will materially increase our cash at the parent of approximately $66 million."
"During the first quarter, we repaid $27 million of term loan and project debt, and ended the quarter with a leverage ratio of 5.4 times. Our plan to repay $150 million or more of debt this year puts us on a path to achieve a leverage ratio by year-end of less than 4 times," Mr. Moore continued. "Our financial results for the first quarter put us on track with our guidance for the year, which we have revised to include the Global Adjustment payments under the OEFC settlement."
Atlantic Power Corporation
Table 1 – Summary of Financial Results
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
Three months ended
March 31,
2017
2016
Financial Highlights
Project revenue
$98.4
$106.4
Project income
25.3
28.7
Net loss attributable to Atlantic Power Corporation
(2.7)
(14.9)
Cash provided by operating activities
34.1
29.4
Project Adjusted EBITDA
63.8
62.5
All amounts are in U.S. dollars and are approximate unless otherwise indicated. Project Adjusted EBITDA is not a recognized measure under generally accepted accounting principles in the United States ("GAAP") and does not have a standardized meaning prescribed by GAAP; therefore, this measure may not be comparable to similar measures presented by other companies. Please refer to "Non-GAAP Disclosures" on page 11 of this news release for an explanation and a reconciliation of "Project Adjusted EBITDA" as used in this news release to project income (loss), the most directly comparable measure on a GAAP basis, and Net loss.
Financial Results
Enhanced Dispatch Contracts
In the first quarter of 2017, the most significant positive driver of results was the impact of changes to the operational and contractual status of the Kapuskasing, North Bay and Nipigon plants in Ontario and the expiration of an above-market gas supply contract for Kapuskasing and North Bay. As previously reported, these plants are now under enhanced dispatch contracts through December 2017 for Kapuskasing and North Bay and through October 2018 for Nipigon. The contracts provide a fixed monthly payment but do not require the plants to generate power, so they were put in a non-operational state earlier this year, which has resulted in operating and fuel cost savings. Although revenues from the three plants were $5.9 million lower in the first quarter of 2017 than in the comparable year-ago period, fuel expenses were also lower. Kapuskasing and North Bay had an $11.0 million reduction in fuel expense compared to the first quarter a year ago, when they were purchasing gas under an above-market contract that expired at year-end 2016.
The Company has accelerated depreciation at Kapuskasing and North Bay through year-end 2017, when it will have fully depreciated both plants consistent with the expiration date of the enhanced dispatch contracts. The increased depreciation associated with these plants in the first quarter of 2017 was $4.1 million.
OEFC Settlement
On April 27, 2017, the Company reached a settlement with the OEFC regarding the interpretation of the price escalator provision (the "Global Adjustment") for power sold to the OEFC under the Power Purchase Agreements (PPAs) for the Kapuskasing, North Bay and Tunis plants. Under the settlement, the OEFC agreed to pay the Company a total of Cdn$36.1 million. The Company received Cdn$10.7 million of this amount in the first quarter of 2017, consisting of Cdn$8.4 million for power sold by Kapuskasing and North Bay in 2016 and Cdn$2.3 million for Kapuskasing and North Bay under the enhanced dispatch contracts for the first quarter of 2017. In early May 2017, the Company received another Cdn$20.3 million, representing amounts for power sold by the three plants in April 2013 through year-end 2015. The remaining Cdn$5.1 million will be recorded as earned over the balance of 2017.
The Cdn$10.7 million received in the first quarter of 2017 was recorded as deferred revenue and is included as a current liability on the Company's balance sheet as of March 31, 2017. Because it was deferred, it did not benefit net income or Project Adjusted EBITDA for the quarter. However, it is included in Cash provided by operating activities. The Company expects to reverse the deferral and include all amounts collected under the settlement for this contingent gain in revenues in the second quarter of 2017.
Three Months Ended March 31, 2017
Net loss attributable to Atlantic Power Corporation for the first quarter of 2017 was $(2.7) million as compared to $(14.9) million in the first quarter of 2016. Lower revenues of $8.0 million (primarily related to the enhanced dispatch contracts) and increased depreciation of $4.7 million were partially offset by a $10.0 million reduction in fuel expense. Foreign exchange loss (mostly unrealized) decreased to $2.5 million in the first quarter of 2017 from $19.8 million in the first quarter of 2016.
Project income for the first quarter of 2017 was $25.3 million, a reduction of $3.4 million from $28.7 million in the year-ago period. The reduction was primarily attributable to accelerated depreciation expense and a slight reduction in the equity in earnings of unconsolidated affiliates.
Project Adjusted EBITDA for the first quarter of 2017 was $63.8 million, an increase of $1.3 million from $62.5 million in the year-ago period. Primary drivers were Kapuskasing (+$3.7 million) and North Bay (+$3.1 million) due to the favorable impact on margins of the enhanced dispatch contracts and the expiration of an above-market gas contract, and Orlando due to settlement of favorable fuel swaps (+$2.1 million). These positive variances were partially offset by Morris (-$4.6 million), due to higher fuel prices and lower fuel optimization, the non-recurrence of a return on a construction project in the year-ago period, and a lower PJM capacity price; Mamquam (-$1.8 million), due to lower water flows compared to a record year in 2016, and Calstock (-$1.4 million), due to lower waste heat and a contractual price adjustment in April 2016. There was a modest non-cash translation benefit on EBITDA from the appreciation of the Canadian dollar relative to the year-ago period.
Cash provided by operating activities of $34.1 million increased $4.7 million from the $29.4 million a year ago. The 2017 period included approximately $8 million of cash (recorded as deferred revenues) collected under the OEFC settlement. In addition, Kapuskasing, North Bay and Nipigon experienced a $6.6 million increase in gross margin because of the revised contractual, operating and fuel supply arrangements as previously discussed. These positive factors were partially offset by a $4.6 million reduction at Morris, because of factors previously discussed; a $2.9 million increase in cash interest payments due to a higher balance and a higher spread on the term loan (issued in April 2016) as compared to the first quarter of 2016, and a $1.8 million decrease at Mamquam due to lower water flows.
Significant uses of cash provided by operating activities during the first quarter of 2017 included $25.0 million of term loan amortization, $2.3 million of project debt amortization and $2.1 million of preferred dividend payments. These figures were comparable to the year-ago period, when the Company also used $16.3 million of cash to make discretionary purchases of its convertible debentures.
Liquidity and Balance Sheet
Liquidity
As shown in Table 2, the Company's liquidity at March 31, 2017 was $214.0 million, an increase of approximately $10 million from the December 31, 2016 level. The increase was attributable to a $5.9 million increase in unrestricted cash and a $4.0 million increase in borrowing capacity resulting from a reduction in letters of credit outstanding. The unrestricted cash of $91.5 million includes $65.6 million at the parent, of which the Company considers approximately $56 million to be discretionary cash available for general corporate purposes.
Atlantic Power Corporation
Table 2 – Liquidity (in millions of U.S. dollars)
Unaudited
March 31,
2017
December 31,
2016
Revolver capacity
$200.0
$200.0
Letters of credit outstanding
(77.5)
(81.5)
Unused borrowing capacity
122.5
118.5
Unrestricted cash
91.5
85.6
Total Liquidity
$214.0
$204.1
Note: Liquidity numbers presented do not include restricted cash of $10.0 million at March 31, 2017 and $13.3 million at December 31, 2016.
Balance Sheet
Debt Repayment
During the first quarter of 2017, the Company repaid $25.0 million of the APLP Holdings term loan and amortized $2.3 million of project-level debt. There were no redemptions or repurchases of convertible debentures during the quarter. At March 31, 2017, the Company's consolidated debt was $971 million, excluding unamortized discounts and deferred financing costs. The Company's consolidated leverage ratio (consolidated gross debt to trailing 12-month consolidated Adjusted EBITDA) was 5.4 times at March 31, 2017.
The Company expects to repay approximately $150 million or more of debt in 2017, including $100 million of its APLP Holdings term loan and $11.8 million of project-level debt. In addition, the Company plans to allocate $40 million or more of its discretionary cash to additional debt reduction (which could include convertible debentures, further repayment of term loan and repayment of Piedmont project debt).
Debt Maturity Profile
The Company has no bullet maturities in 2017. In 2018, the Company has a project debt maturity at Piedmont totaling $54 million at the maturity date in August 2018. The remaining $42.5 million of Series C convertible debentures mature in June 2019 and are callable at par in June 2017. The $60.9 million (U.S. dollar equivalent) of Series D convertible debentures mature in December 2019 and are callable at par in December 2017. The Company's revolving credit facility has a 2021 maturity and the APLP Holdings term loan has a 2023 maturity (though is expected to be more than 80% repaid by the maturity date).
Repricing of Term Loan and Revolver
On April 17, 2017, the Company executed a repricing of the APLP Holdings term loan and revolving credit facility. The interest rate margin on the term loan and revolver were reduced by 75 basis points to LIBOR plus 425 basis points. The LIBOR floor remains at 1.00%. The mandatory 1% annual amortization and cash sweep provisions of the loan were unchanged. As a result of the repricing, the Company expects to realize interest cost savings for the remainder of 2017 of $2.4 million, net of transaction fees that will be recorded in the second quarter. Cumulative savings through the maturity dates of the term loan and revolver are estimated to be approximately $17 million, net of transaction fees. The Company is permitted to prepay the term loan in the first six months following the transaction at a 1% premium. Following the six-month period, prepayment is permitted at par.
Normal Course Issuer Bid (NCIB) Update
The Company put in place a new normal course issuer bid ("NCIB") on December 29, 2016. Details of this program can be found in the Company's December 20, 2016 press release. The Company has repurchased less than $100,000 of convertible debentures and no common shares under this NCIB. As reported in the Company's fourth quarter and year-end 2016 financial results press release, the Company repurchased $18.8 million principal amount of convertible debentures and slightly less than 8.1 million common shares under the previous NCIB that expired on December 28, 2016.
Other Financial Updates
PPA Expirations and Negotiations
The Company has PPAs or other contractual arrangements scheduled to expire for nine of its projects in the next five years. Together these represent 25% of the Company's capacity and 30% of 2016 Project Adjusted EBITDA. The Company continues to work toward extensions of existing PPAs or new agreements or arrangements for certain of the Ontario, San Diego, Williams Lake and other projects for which the PPAs expire during this period.
Optimization Investments
The Company made approximately $3.4 million of optimization-related investments in its projects in 2016, with the majority of those for upgrades to a boiler and two combustion turbines at Morris and a spillway upgrade project at Curtis Palmer, all of which were completed in 2016. The Company expects to complete the upgrade of the third combustion turbine at Morris during an outage in the spring of this year. Although the Company will continue to evaluate the potential for additional such investments, they are expected to be relatively modest. The Company has begun an evaluation of its operations and maintenance costs and expects that to be a major focus in 2017.
The Company realized a cash flow benefit of approximately $8 million in 2016 from optimization investments made in 2013 through 2016 totaling approximately $25 million. The Company expects to realize a cash flow benefit of approximately $12 million in 2017 from these investments and those made in 2017, assuming average water conditions.
Maintenance and Capex
For 2017, including its share of equity-owned projects, the Company expects to incur maintenance expenses of approximately $45 million (in line with the 2016 level), which includes an estimate of the cost to prepare Tunis for a return to service in 2018 under the new PPA. Approximately $5.3 million was incurred in the first quarter of 2017. The Company's estimate of capital expenditures for 2017 is between $5 and $6 million (slightly lower than the 2016 level), which includes the upgrade of the third and final combustion turbine at Morris and several smaller projects. Approximately $1.4 million was incurred in the first quarter of 2017.
Revised 2017 Guidance
The Company has not provided guidance for Project income or Net income because of the difficulty of making accurate forecasts and projections without unreasonable efforts with respect to certain highly variable components of these comparable GAAP metrics, including changes in the fair value of derivative instruments and foreign exchange gains or losses. These factors, which generally do not affect cash flow, are not included in Project Adjusted EBITDA.
The Company has increased its guidance for 2017 Project Adjusted EBITDA to a range of $250 to $265 million from a range of $225 to $240 million to include the Global Adjustment revenues expected under the OEFC settlement, estimated to be approximately US$26 million in 2017.
Table 3 provides a bridge of the Company's 2017 Project Adjusted EBITDA guidance to Cash provided by operating activities. For purposes of providing this bridge to a cash flow measure, the impact of changes in working capital is assumed to be nil.
Atlantic Power Corporation
Table 3 – Bridge of 2017 Project Adjusted EBITDA Guidance to Cash Provided by Operating Activities
(in millions of U.S. dollars)
Unaudited
Current
Previous
(5/4/17)
(3/2/17)
2017 Project Adjusted EBITDA Guidance
$250 - $265
$225 - $240
Adjustment for equity method projects(1)
(1)
(1)
Corporate G&A expense
(22)
(22)
Cash interest payments
(67)
(67)
Cash taxes
(4)
(4)
Other
-
-
Cash provided by operating activities
$155 - $170
$130 - $145
Note: For the purpose of providing a bridge of Project Adjusted EBITDA guidance to a cash flow measure, the impact of changes in working capital on Cash provided by operating activities is assumed to be nil.
(1) For equity method projects, represents difference between Project Adjusted EBITDA and cash distribution from equity method projects.
Supplementary Information Regarding Non-GAAP Disclosures
A discussion of non-GAAP disclosures and schedules reconciling Project Adjusted EBITDA, a non-GAAP measure, to the comparable GAAP measure, can be found on page 11 of this release.
Investor Conference Call and Webcast
Atlantic Power's management team will host a telephone conference call on Friday, May 5, 2017 at 8:30 AM ET. Management's prepared remarks and an accompanying presentation will be available on the Conference Calls page of the Company's website prior to the call.
Conference Call / Webcast Information:
Date: Friday, May 5, 2017
Start Time: 8:30 AM ET
Phone Number: U.S. (Toll Free) 1-855-239-3193; Canada (Toll Free) 1-855-669-9657; International (Toll) 1-412-542-4129.
Conference Access: Please request access to the Atlantic Power conference call.
Webcast: The call will be broadcast over Atlantic Power's website at www.atlanticpower.com.
Replay/Archive Information:
Replay: Access conference call number 10104126 at the following telephone numbers: U.S. (Toll Free) 1-877-344-7529; Canada (Toll Free) 1-855-669-9658; International (Toll) 1-412-317-0088. The replay will be available one hour after the end of the conference call through June 5, 2017 at 11:59 PM ET.
Webcast archive: The conference call will be archived on Atlantic Power's website at www.atlanticpower.com for a period of 12 months.
About Atlantic Power
Atlantic Power owns and operates a diverse fleet of twenty-three power generation assets across nine states in the United States and two provinces in Canada. The Company's power generation projects sell electricity to utilities and other large commercial customers largely under long-term PPAs, which seek to minimize exposure to changes in commodity prices. The aggregate gross electric generation capacity of this portfolio is approximately 2,138 megawatts (MW), and the Company's aggregate net ownership interest is approximately 1,500 MW. Nineteen of the projects are currently operational, totaling 1,975 MW on a gross capacity basis and 1,337 MW on a net ownership basis. The remaining four projects, all in Ontario, are not operational, three due to revised contractual arrangements with the offtaker and the other, Tunis, has a forward-starting 15-year contractual agreement that will commence between November 2017 and June 2019.
Atlantic Power's shares trade on the New York Stock Exchange under the symbol AT and on the Toronto Stock Exchange under the symbol ATP. For more information, please visit the Company's website at www.atlanticpower.com or contact:
Atlantic Power Corporation
Investor Relations
(617) 977-2700
info@atlanticpower.com
Copies of the Company's financial data and other publicly filed documents are available on SEDAR at www.sedar.com or on EDGAR at www.sec.gov/edgar.shtml under "Atlantic Power Corporation" or on the Company's website.
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Cautionary Note Regarding Forward-Looking Statements
To the extent any statements made in this news release contain information that is not historical, these statements are forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended, and under Canadian securities law (collectively, "forward-looking statements").
Certain statements in this news release may constitute "forward-looking statements", which reflect the expectations of management regarding the future growth, results of operations, performance and business prospects and opportunities of the Company and its projects. These statements, which are based on certain assumptions and describe the Company's future plans, strategies and expectations, can generally be identified by the use of the words "may," "will," "project," "continue," "believe," "intend," "anticipate," "expect" or similar expressions that are predictions of or indicate future events or trends and which do not relate solely to present or historical matters. Examples of such statements in this press release include, but are not limited, to statements with respect to the following:
the Company's estimation that the repricing of its term loan and revolver will yield approximately $2.4 million of interest cost savings in 2017 and $17 million over the remaining lives of the facilities, net of transaction fees;
the Company's expectation that it will receive another Cdn$5.1 million of Global Adjustment revenues under the OEFC settlement over the remainder of 2017;
the Company's expectation that it will repay $150 million or more of debt in 2017, including $100 million of its term loan and $11.8 million of project-level debt;
the Company's estimate of discretionary cash ($56 million) and its plans to allocate approximately $40 million or more to discretionary debt repayment in 2017;
the Company's expectation that it will repay more than 80% of its term loan by the maturity date in 2023;
the Company's expectation that it will realize a cash flow benefit of approximately $12 million in 2017 from discretionary investments made in 2013 through 2016 totaling approximately $25 million;
the Company's expectation that it will complete the upgrade of the third combustion turbine at Morris during an outage in the spring of this year;
the Company's expectation that evaluation of its operations and maintenance costs will be a major focus in 2017;
the Company's expectation that in 2017, including its share of equity-owned projects, capital expenditures will total approximately $5 to $6 million and maintenance expense will total approximately $45 million;
the Company's estimation that 2017 Project Adjusted EBITDA will be in the range of $250 to $265 million;
the Company's estimation that 2017 cash flows provided by operating activities will be in the range of $155 to $170 million, assuming for this purpose that working capital changes are nil; and
the results of operations and performance of the Company's projects, business prospects, opportunities and future growth of the Company will be as described herein.
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. Please refer to the factors discussed under "Risk Factors" and "Forward-Looking Information" in the Company's periodic reports as filed with the Securities and Exchange Commission from time to time for a detailed discussion of the risks and uncertainties affecting the Company, including, without limitation, the outcome or impact of the Company's business strategy to increase the intrinsic value of the Company on a per-share basis through disciplined management of its balance sheet and cost structure and investment of its discretionary cash in a combination of organic and external growth projects, acquisitions, and repurchases of debt and equity securities; the Company's ability to enter into new PPAs on favorable terms or at all after the expiration of existing agreements, and the outcome or impact on the Company's business of any such actions. Although the forward-looking statements contained in this news release 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. These forward-looking statements are made as of the date of this news release and, except as expressly required by applicable law, the Company assumes no obligation to update or revise them to reflect new events or circumstances. The Company's ability to achieve its longer-term goals, including those described in this news release, is based on significant assumptions relating to and including, among other things, the general conditions of the markets in which it operates, revenues, internal and external growth opportunities, its ability to sell assets at favorable prices or at all and general financial market and interest rate conditions. The Company's actual results may differ, possibly materially and adversely, from these goals.
Atlantic Power Corporation
Table 4 – Consolidated Balance Sheet (in millions of U.S. dollars)
Unaudited
March 31,
December 31,
2017
2016
Assets
Current assets:
Cash and cash equivalents
$91.5
$85.6
Restricted cash
10.0
13.3
Accounts receivable
37.1
37.3
Current portion of derivative instruments asset
3.7
4.0
Inventory
16.2
16.0
Prepayments
9.8
5.9
Other current assets
2.6
2.8
Total current assets
170.9
164.9
Property, plant and equipment, net
717.0
733.2
Equity investments in unconsolidated affiliates
272.2
266.8
Power purchase agreements and intangible assets, net
236.6
246.2
Goodwill
36.0
36.0
Derivative instruments asset
4.1
4.6
Other assets
4.7
5.1
Total assets
$1,441.5
$1,456.8
Liabilities
Current liabilities:
Accounts payable
$4.7
$4.5
Accrued interest
4.3
0.7
Other accrued liabilities
20.6
24.4
Current portion of long-term debt
109.4
111.9
Current portion of derivative instruments liability
6.0
7.6
Other current liabilities
9.7
1.8
Total current liabilities
154.7
150.9
Long-term debt (1)
728.3
749.2
Convertible debentures (2)
101.1
100.4
Derivative instruments liability
23.4
21.3
Deferred income taxes
67.3
68.3
Power purchase and fuel supply agreement liabilities, net
24.9
25.3
Other long-term liabilities
56.0
55.5
Total liabilities
$1,155.7
$1,170.9
Equity
Common shares, no par value, unlimited authorized shares; 115,229,497 and 114,649,888 issued and outstanding at March 31, 2017 and December 31, 2016, respectively
1,273.4
1,272.9
Accumulated other comprehensive loss
(146.4)
(148.5)
Retained deficit
(1,062.5)
(1,059.8)
Total Atlantic Power Corporation shareholders' equity
64.5
64.6
Preferred shares issued by a subsidiary company
221.3
221.3
Total equity
285.8
285.9
Total liabilities and equity
$1,441.5
$1,456.8
(1) Net of unamortized discount and deferred financing costs
(2) Net of unamortized deferred financing costs
Atlantic Power Corporation
Table 5 – Consolidated Statements of Operations
(in millions of U.S. dollars, except per share amounts)
Unaudited
Three months ended
March 31,
2017
2016
Project revenue:
Energy sales
$37.1
$52.5
Energy capacity revenue
19.5
31.9
Other
41.8
22.0
98.4
106.4
Project expenses:
Fuel
28.9
38.9
Operations and maintenance
20.4
21.2
Depreciation and amortization
29.5
24.8
78.8
84.9
Project other income (expense):
Change in fair value of derivative instruments
(1.2)
(1.2)
Equity in earnings of unconsolidated affiliates
9.0
10.7
Interest expense, net
(2.2)
(2.1)
Other income (expense), net
0.1
(0.2)
5.7
7.2
Project income
25.3
28.7
Administrative and other expenses:
Administration
6.4
6.1
Interest expense, net
17.3
16.6
Foreign exchange loss
2.5
19.8
Other income, net
-
(2.5)
26.2
40.0
Loss from operations before income taxes
(0.9)
(11.3)
Income tax (benefit) expense
(0.3)
1.6
Net loss
(0.6)
(12.9)
Net income attributable to preferred share dividends of a subsidiary company
2.1
2.0
Net loss attributable to Atlantic Power Corporation
($2.7)
($14.9)
Net loss per share attributable to Atlantic Power Corporation shareholders:
Basic
($0.02)
($0.12)
Diluted
(0.02)
(0.12)
Weighted average number of common shares outstanding:
Basic
114.8
121.9
Diluted
114.8
121.9
Atlantic Power Corporation
Table 6 – Consolidated Statements of Cash Flows (in millions of U.S. dollars)
Unaudited
Three months ended March 31,
2017
2016
Cash provided by operating activities:
Net loss
($0.6)
($12.9)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization
29.5
24.8
Loss on sale of assets
-
0.2
Gain on purchase and cancellation of convertible debentures
-
(2.5)
Stock-based compensation expense
0.4
0.6
Equity in earnings from unconsolidated affiliates
(9.0)
(10.7)
Distributions from unconsolidated affiliates
3.7
4.3
Unrealized foreign exchange loss
2.5
20.1
Change in fair value of derivative instruments
1.2
1.2
Change in deferred income taxes
(1.2)
0.1
Change in other operating balances
Accounts receivable
0.2
(0.5)
Inventory
(0.1)
2.8
Prepayments and other assets
(0.5)
(10.4)
Accounts payable
(0.4)
1.4
Accruals and other liabilities
8.4
10.9
Cash provided by operating activities
34.1
29.4
Cash provided by investing activities:
Change in restricted cash
3.3
5.2
Reimbursement of costs for third-party construction project
-
4.7
Purchase of property, plant and equipment
(2.0)
(0.7)
Cash provided by investing activities
1.3
9.2
Cash used in financing activities:
Common share repurchases
-
(0.9)
Repayment of corporate and project-level debt
(27.4)
(27.5)
Repayment of convertible debentures
-
(16.3)
Dividends paid to preferred shareholders
(2.2)
(2.0)
Cash used in financing activities
(29.5)
(46.7)
Net increase (decrease) in cash and cash equivalents
5.9
(8.1)
Cash and cash equivalents at beginning of period
85.6
72.4
Cash and cash equivalents at end of period
$91.5
$64.3
Supplemental cash flow information
Interest paid
$13.1
$10.2
Income taxes paid, net
$0.9
$0.9
Accruals for construction in progress
$-
1.0
Non-GAAP Disclosures
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. Investors are cautioned that the Company may calculate this non-GAAP measure in a manner that is different from other companies. The most directly comparable GAAP measure is Project income (loss). Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation, amortization (including non-cash impairment charges), and changes in the fair value of derivative instruments. Management uses Project Adjusted EBITDA at the project level to provide comparative information about project performance and believes such information is helpful to investors. A reconciliation of Project Adjusted EBITDA to Project income (loss) and to Net loss on a consolidated basis is provided in Table 7 below.
Cash Distributions from Projects is the amount of cash distributed by the projects to the Company out of available project cash flow after all project-level operating costs, interest payments, principal repayment, capital expenditures and working capital requirements. A bridge of Project Adjusted EBITDA to Cash Distributions from Projects can be found in the first quarter 2017 presentation on the Company's website.
Project income (loss) and Project Adjusted EBITDA by project also can be found in the first quarter 2017 presentation on the Company's website.
Atlantic Power Corporation
Table 7 – Reconciliation of Net loss to Project Adjusted EBITDA
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
Three months ended
March 31
2017
2016
Net loss attributable to Atlantic Power Corporation
($2.7)
($14.9)
Net income attributable to preferred share dividends of a subsidiary company
2.1
2.0
Net loss from operations
($0.6)
($12.9)
Income tax (benefit) expense
(0.3)
1.6
Loss from operations before income taxes
(0.9)
(11.3)
Administration
6.4
6.1
Interest expense, net
17.3
16.6
Foreign exchange loss
2.5
19.8
Other income, net
-
(2.5)
Project income
$25.3
$28.7
Reconciliation to Project Adjusted EBITDA
Depreciation and amortization
$34.9
$29.9
Interest expense, net
2.4
2.5
Change in the fair value of derivative instruments
1.2
1.2
Other expense
-
0.2
Project Adjusted EBITDA
$63.8
$62.5
To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/atlantic-power-corporation-releases-first-quarter-2017-results-300452021.html
SOURCE Atlantic Power Corporation
Copyright 2017 Canada NewsWire
Easy1
8 years ago
Atlantic Power Corporation Releases Fourth Quarter and Year End 2016 Results
Source: PR Newswire (Canada)
DEDHAM, Mass., March 2, 2017 /CNW/ -- Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the "Company") today reported its financial results for the three months and year ended December 31, 2016. For additional information regarding the Company's 2016 performance, 2017 guidance and certain operational updates, including the status of certain upcoming Power Purchase Agreement (PPA) renewals, please consult Management's prepared remarks and the accompanying presentation, which will be available on the Conference Calls page of the Company's website (www.atlanticpower.com).
Fourth Quarter 2016 Financial Results (vs. 2015)
Cash provided by operating activities of $19.9 million vs. $19.7 million
Net loss of $(6.6) million vs. $(88.6) million; 2015 included a $127.8 million impairment charge
Project income of $13.3 million vs. project loss of $(104.3) million, including impairment charges
Project Adjusted EBITDA of $42.3 million vs. $50.4 million; decline was attributable to lower water flows at Curtis Palmer, lower waste heat, and a scheduled maintenance outage at Oxnard
Full Year 2016 Financial Results (vs. 2015)
Cash provided by operating activities of $111.8 million vs. $87.4 million
Net loss of $(122.4) million vs. $(62.4) million; both years included significant impairment charges
Project income of $10.1 million vs. project loss of $(41.4) million
Project Adjusted EBITDA of $202.2 million vs. $208.9 million; results were below the Company's guidance of $205 to $215 million due to lower water flows at Curtis Palmer, lower waste heat and severance costs at three Ontario projects
Other Highlights
Achieved net reduction in debt in 2016 of $22 million, despite upsizing term loan in April; now have significantly improved debt maturity profile
Repurchased 8.1 million common shares at an average price of $2.42 since December 2015
Reduced total overhead costs by 28% to $23 million in 2016 from $32 million in 2015
Initiated 2017 Project Adjusted EBITDA guidance (see page 4 of this release)
Expect to repay another $150 million or more of debt in 2017
"During 2016, we refinanced our existing term loan and revolver with a larger $700 million term loan and a $200 million revolver, both with extended maturity dates. We also paid down $288 million of debt, ending the year with a reduction in consolidated debt of approximately $22 million, net of the term loan upsizing. Since year end 2013, we have reduced consolidated debt by more than $800 million and improved our maturity profile considerably. We also made further progress in reducing our interest payments and corporate overhead costs, which are now $60 million and $31 million lower than 2013 levels, respectively," said James J. Moore, Jr., President and CEO of Atlantic Power. "In addition, we have lowered our share count by 6.6% since December 2015 by repurchasing and canceling approximately 8.1 million common shares at an average price of $2.42 per share."
"By strengthening our balance sheet, addressing our near-term maturities and reducing our fixed costs, we believe that we have positioned the Company to take a disciplined approach on renewals of PPAs and withstand an extended downturn in a very cyclical business," said Mr. Moore. "We are enthusiastic about our strengthened financial position, expected 2017 operating cash flow and the uses of capital that we have available which are consistent with our objective of increasing intrinsic value per share."
Mr. Moore continued, "After two years of dramatic change, the Company is now in a position to pay down an additional $150 million or more of debt in 2017; continue to repurchase shares when they trade at a significant discount to our estimates of intrinsic value per share, as they do today; work toward PPA renewals without financial pressure to transact quickly in a down market, and begin to implement a growth strategy, with efforts currently focused on industrial customers."
Atlantic Power Corporation
Table 1 – Selected Financial Results
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
Three months
ended December 31,
Twelve months
ended December 31,
2016
2015
2016
2015
Financial Results
Project revenue
$93.4
$98.4
$399.2
$420.2
Project income (loss)
13.3
(104.3)
10.1
(41.4)
Net loss attributable to Atlantic Power Corporation
(6.6)
(88.6)
(122.4)
(62.4)
Cash provided by operating activities
19.9
19.7
111.8
87.4
Project Adjusted EBITDA
42.3
50.4
202.2
208.9
All amounts are in U.S. dollars and are approximate unless otherwise indicated. Project Adjusted EBITDA is not a recognized measure under generally accepted accounting principles in the United States ("GAAP") and does not have a standardized meaning prescribed by GAAP; therefore, this measure may not be comparable to similar measures presented by other companies. Please refer to "Non-GAAP Disclosures" beginning on page 13 of this news release for an explanation and a reconciliation of "Project Adjusted EBITDA" as used in this news release to project income (loss), the most directly comparable measure on a GAAP basis, and Net loss.
The Wind Projects were sold in June 2015 and are included in discontinued operations for the three months and year ended December 31, 2015. Results of the Wind Projects are excluded from Project revenue, Project income (loss) and Project Adjusted EBITDA as shown in Table 1 and as discussed below but are included in Net loss attributable to Atlantic Power Corporation and Cash provided by operating activities as shown in Table 1. Please see page 13 for a summary of results of discontinued operations. The Wind Projects consisted 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).
Financial Results
Three Months Ended December 31, 2016
The primary operational factors that affected the Company's results for the fourth quarter of 2016 included lower water flows at Curtis Palmer, lower waste heat at the Company's Ontario plants, a scheduled maintenance outage at Oxnard, turbine maintenance expense at Kapuskasing and North Bay and severance cost at Kapuskasing, North Bay and Nipigon. These negative drivers were partially offset by higher water flows at Mamquam.
Net loss attributable to Atlantic Power Corporation for the fourth quarter of 2016 of $(6.6) million included a $1.2 million non-cash impairment of the remaining goodwill at Moresby Lake and a $12.7 million charge for the non-cash accelerated amortization of intangible assets related to the PPAs at Kapuskasing and North Bay, which were terminated early as described in the Company's January 9, 2017 press release. Net loss for the fourth quarter of 2015 of $(88.6) million included a $127.8 million non-cash impairment of long-lived assets and goodwill, primarily at Williams Lake. The $82.0 million reduction in net loss in 2016 was primarily attributable to the reduction in impairment expense and an increase in the fair value of derivative instruments, partially offset by higher amortization expense, a reduction in largely unrealized foreign exchange gain, lower income tax benefit and the operational factors described previously.
Project income for the fourth quarter of 2016 was $13.3 million versus project loss for the year-ago period of $(104.3) million. The $117.6 million improvement from project loss in 2015 to project income in 2016 was primarily attributable to lower impairment expense and an increase in the fair value of derivative instruments as described previously, partially offset by higher amortization expense and the operational factors described previously.
Project Adjusted EBITDA for the fourth quarter of 2016 was $42.3 million, a decline of $8.1 million from $50.4 million in the year-ago period. Primary contributors to the decline were a $3.3 million reduction at Curtis Palmer due to lower water flows; a $5.0 million decrease at Kapuskasing and North Bay due to lower waste heat, turbine maintenance expense, and severance expense; and a $2.2 million decrease at Oxnard due to the scheduled maintenance outage. Results for Kapuskasing, Nipigon and North Bay included $1.1 million of severance expense related to the revised operational status of and contractual arrangements for these plants announced in the Company's January 9, 2017 press release. These decreases were partially offset by a $2.2 million increase at Mamquam due to favorable water flows and lower maintenance expense.
Cash provided by operating activities of $19.9 million was in line with the $19.7 million reported for the year-ago period. Significant uses of cash provided by operating activities during the fourth quarter of 2016 included $15.0 million of term loan amortization, $3.0 million of project debt amortization and $2.1 million of preferred dividend payments.
Year Ended December 31, 2016
The primary operational factors that affected the Company's results for the year ended December 31, 2016 included an extended planned outage at Morris in the third quarter, lower water flows at Curtis Palmer, lower waste heat and fuel price escalation at some of the Company's Ontario plants, a contractual price adjustment at Calstock, and a scheduled maintenance outage at Oxnard. These negative drivers were partially offset by the absence of an outage at Manchief (compared to 2015) and higher water flows at Mamquam.
Net loss attributable to Atlantic Power Corporation of $(122.4) million for the year ended December 31, 2016 increased $60.0 million from a net loss of $(62.4) million in 2015. The increased net loss was the result of a $32.8 million non-cash write-off of deferred financing costs in the second quarter attributable to the Company's refinancing activities (included in interest expense), $12.7 million of accelerated amortization expense in the fourth quarter related to the Kapuskasing and North Bay PPAs, a $13.9 million largely unrealized foreign exchange loss as compared to a $60.3 million unrealized foreign exchange gain in 2015, and the absence of income from the discontinued Wind business ($19.5 million in 2015). The operational factors described previously had a net negative impact. These negative factors affecting the 2016 net loss were partially offset by reduced impairment expense ($85.9 million in 2016, mostly in the third quarter, as compared to $127.8 million in 2015) and a $22.5 million positive variance in the fair value of derivatives. Another positive factor was that corporate general and administrative costs declined $6.8 million in 2016 from 2015.
Project income of $10.1 million for the year compared favorably to project loss of $(41.4) million for 2015. The 2016 result benefited from lower impairment expense as previously described, a favorable change in the fair value of derivative instruments, higher project income at Manchief, which had a scheduled maintenance overhaul in the second quarter of 2015, partially offset by lower project income at Morris, which had an extended planned outage in the third quarter of 2016, lower project income at Curtis Palmer due to lower water flows, a contractual price adjustment at Calstock, a scheduled maintenance outage at Oxnard and increased amortization expense.
Project Adjusted EBITDA of $202.2 million for the year decreased $6.7 million from $208.9 million for 2015. Primary contributors to the decline were a $10.1 million reduction at Morris due to lower revenues and higher maintenance expense resulting from the extended outage in 2016, a $3.3 million decrease at Curtis Palmer due to lower water flows, and a decrease of $7.6 million at the Ontario projects due to lower waste heat, fuel escalators and a contractual price adjustment at Calstock. The stronger U.S. dollar had a negative non-cash translation impact of approximately $2.9 million, almost all of which was in the first quarter. These negative factors were partially offset by a $7.2 million increase at Manchief, which had a major gas turbine outage in 2015, and a $6.7 million increase at Mamquam due to higher water flows.
Cash provided by operating activities of $111.8 million increased $24.4 million from the 2015 level of $87.4 million. The increase was primarily attributable to a $29.3 million reduction in cash interest payments due to debt repayment in 2015 and 2016 and the absence of make-whole premiums associated with the redemption of the 9.0% Senior Unsecured Notes in 2015, a $6.8 million reduction in corporate G&A expense and a positive variance in changes in working capital. These positive drivers were partially offset by the loss of $21.9 million of operating cash flow from the Wind businesses, which were included in the 2015 result. The $6.7 million decrease in Project Adjusted EBITDA described previously also had a negative impact on operating cash flow in 2016. In 2016, the Company used its $111.8 million of cash provided by operating activities to amortize $96.5 million of term loan and project debt, make capital expenditures of $7.2 million and pay preferred dividends of $8.5 million.
2017 Guidance
The Company has not provided guidance for Project income or Net income because of the difficulty of making accurate forecasts and projections without unreasonable efforts with respect to certain highly variable components of these comparable GAAP metrics, including changes in the fair value of derivative instruments and foreign exchange gains or losses. These factors, which generally do not affect cash flow, are not included in Project Adjusted EBITDA.
The Company has initiated guidance for 2017 Project Adjusted EBITDA in the range of $225 to $240 million. The increase from the 2016 level of $202.2 million is primarily attributable to the expiration on December 31, 2016 of an above-market gas supply contract for two of the Company's Ontario projects. Other positive factors include an expected full year cash return on completed optimization investments; an expected return to average water flows, particularly at Curtis Palmer and Mamquam; and revised operational and contractual arrangements for Kapuskasing and North Bay as described in the Company's January 9, 2017 press release, net of the cost of putting those plants into a non-operational status. Morris is also expected to have a positive comparison because of the extended outage it underwent in 2016, but this is expected to be more than offset by a planned maintenance outage at Frederickson in 2017 and expenses associated with preparing Tunis for a return to service in 2018 under the new PPA.
Table 2 provides a bridge of the Company's 2017 Project Adjusted EBITDA guidance to Cash provided by operating activities. For purposes of providing this bridge to a cash flow measure, the impact of changes in working capital is assumed to be nil.
Atlantic Power Corporation
Table 2 – Bridge of 2017 Project Adjusted EBITDA Guidance to Cash Provided by Operating Activities
(in millions of U.S. dollars)
Unaudited
2017 Project Adjusted EBITDA Guidance(1)
$225 - $240
Adjustment for equity method projects(2)
(1)
Corporate G&A expense
(22)
Cash interest payments
(67)
Cash taxes
(4)
Other
-
Cash provided by operating activities
$130 - $145
Note: For the purpose of providing a bridge of Project Adjusted EBITDA guidance to a cash flow measure, the impact of changes in working capital on Cash provided by operating activities is assumed to be nil.
(1) Initially provided March 2, 2017.
(2) For equity method projects, represents difference between Project Adjusted EBITDA and cash distribution from equity method projects.
Liquidity and Balance Sheet
Liquidity
As shown in Table 3, the Company's liquidity at December 31, 2016 was $204.1 million, essentially unchanged from $205.1 million at September 30, 2016. An $8.2 million reduction in the unrestricted cash balance was mostly offset by a $7.2 million increase in borrowing capacity resulting from a reduction in letters of credit outstanding. The unrestricted cash of $85.6 million includes approximately $60 million at the parent, of which the Company considers approximately $50 million to be discretionary cash available for general corporate purposes.
Atlantic Power Corporation
Table 3 – Liquidity (in millions of U.S. dollars)
Unaudited
December 31,
2016
September 30,
2016
Revolver capacity
$200.0
$200.0
Letters of credit outstanding
(81.5)
(88.7)
Unused borrowing capacity
118.5
111.3
Unrestricted cash
85.6
93.8
Total Liquidity
$204.1
$205.1
Note: Liquidity numbers presented do not include restricted cash of $12.6 million at September 30, 2016 and $13.3 million at December 31, 2016.
Balance Sheet
Repayment of Term Loan and Project Debt
During the fourth quarter of 2016, the Company amortized $15.0 million of the APLP Holdings term loan and $3.0 million of project-level debt. For the full year, the Company amortized $85.5 million of term loan debt, including $25.3 million in the first quarter related to the previous term loan, and $11.1 million of project-level debt.
Redemptions and Repurchases of Convertible Debentures
There were no redemptions or repurchases of convertible debentures in the fourth quarter of 2016. For the year, the Company redeemed or repurchased a total of $191.5 million principal amount of convertible debentures. This was done under the normal course issuer bid (NCIB) in the first quarter ($18.8 million), through the redemption at par of both 2017 issues in the second quarter ($110.1 million) using proceeds from the term loan refinancing, and under a substantial issuer bid in the third quarter ($62.7 million), also using proceeds from the refinancing.
Debt Balance and Leverage at December 31, 2016
Although the refinancing of the Company's previous term loan in April 2016 resulted in a net increase in debt of $252 million, the allocation of a majority of the net cash proceeds from the refinancing to debt redemptions and repurchases in the second and third quarters of this year, together with ongoing amortization of the new term loan and project debt, as described previously, offset all but $10 million of this increase. At December 31, 2016, the Company's consolidated debt was $996.5 million, excluding unamortized discounts and deferred financing costs, as compared to $1,018.7 million at year end 2015. The Company's consolidated leverage ratio (consolidated gross debt to trailing 12-month consolidated Adjusted EBITDA) was 5.6 times at December 31, 2016.
Debt Maturity Profile
As a result of refinancing and discretionary repurchases to date, the Company has no bullet maturities at the corporate level prior to June 2019, when the remaining $42.6 million of Series C convertible debentures will mature. In addition, the Company has $60.3 million (U.S. dollar equivalent) of Series D convertible debentures maturing in December 2019. The reshaping of the Company's maturity profile is further improved by the later maturity dates for the new term loan (2023 versus 2021 previously) and the new revolver (2021 versus 2018 previously). The Company also has one project debt bullet maturity during this period – the term loan at its Piedmont project totaling $54 million at its maturity date of August 2018. In addition to these bullet maturities, the Company has amortizing debt at various projects through 2025 and required amortization of the APLP Holdings term loan per a targeted debt schedule through the 2023 maturity date.
2017 Debt Repayment Plans
The Company expects to amortize $100 million of its APLP Holdings term loan and $11.8 million of project debt in 2017 using cash flow. In addition, the Company plans to allocate $40 million or more of its discretionary cash to additional debt reduction (which could include convertible debentures, further paydown of term loan and project debt maturities). Thus, in total, the Company expects to repay approximately $150 million or more of debt in 2017.
Normal Course Issuer Bid (discretionary repurchases of debt and equity)
The NCIB implemented by the Company in December 2015 expired on December 28, 2016. Under this program, the Company repurchased $18.8 million principal amount of convertible debentures, all in the first quarter of 2016. The Company also repurchased a total of slightly less than 8.1 million common shares, including 8.0 million in 2016, at a total cost including commissions of approximately $19.6 million (average price of $2.42 per share). Share repurchases in the fourth quarter of 2016 totaled 2.4 million at a total cost of $5.8 million (average price of $2.44 per share).
The Company implemented a new NCIB on December 29, 2016. Under this NCIB, the Company may purchase up to 10% of the public float of the Company's outstanding common shares and convertible debentures and up to 5% of the amount issued and outstanding of Atlantic Power Preferred Equity Ltd.'s preferred shares. Details of the program can be found in the Company's December 20, 2016 press release.
Other Financial Updates
PPA Expirations and Negotiations
The Company has PPAs or other contractual arrangements scheduled to expire for nine of its projects in the next five years. Together these represent 25% of the Company's capacity and 30% of 2016 Project Adjusted EBITDA. In January 2017, the Company put the Kapuskasing, North Bay and Nipigon projects in Ontario into a non-operational state, under arrangements that provide a fixed monthly payment to the projects until December 2017 for Kapuskasing and North Bay and October 2018 for Nipigon. Another Ontario project, Tunis, has not been operating since the expiration of its previous PPA in December 2014, but has a 15-year PPA that will commence between November 2017 and June 2019, at the Company's option. The Company plans to return Tunis to service under the new PPA in 2018. In San Diego, the Company's three plants (Naval Station, North Island and Naval Training Center) have expiring PPAs in December 2019, but these PPAs are dependent on the Company's right to use the underlying sites under agreements with the Navy that expire in February 2018. The Company is currently considering negotiating, extending or entering into new agreements or arrangements for certain of the Ontario, San Diego and other projects for which the PPAs expire during this period. For information on the status of these negotiations or arrangements, please consult the Company's 2016 Annual Report on Form 10-K.
Optimization Investments
The Company made approximately $3.4 million of optimization-related investments in its projects in 2016, with the majority of those for upgrades to a boiler and two combustion turbines at Morris and a spillway upgrade project at Curtis Palmer, all of which were completed in 2016. The Company expects to complete the upgrade of the third combustion turbine at Morris during an outage in the spring of this year. Although the Company will continue to evaluate the potential for additional such investments, they are expected to be relatively modest. The Company has begun an evaluation of its operation and maintenance costs and expects that to be a major focus in 2017.
The Company realized a cash flow benefit of approximately $8 million in 2016 from optimization investments made in 2013 through 2016 totaling approximately $25 million, which was below the original expectation primarily because high levels of waste heat at Nipigon reduced the need for the duct burners and booster pump that were installed as optimization projects in 2014 and 2015, respectively. In addition, lower water flows at Curtis Palmer in 2016 reduced the contribution from the turbine upgrades completed in 2013 and 2014. The Company expects to realize a cash flow benefit of approximately $12 million in 2017 from these investments and those made in 2017, assuming average water conditions.
Maintenance and Capex
In 2016, for its consolidated projects only, the Company incurred $37.9 million of maintenance expense versus $36.2 million in 2015. In addition to maintenance expensed in the period, the Company made $7.2 million of capital expenditures versus $11.3 million in 2015. Including the Company's share of projects in which it has an equity ownership interest, maintenance expense was $46.2 million in 2016 versus $55.6 million in 2015, and capital expenditures were $7.5 million versus $11.6 million in 2015. For 2017, including its share of equity-owned projects, the Company expects to incur maintenance expenses of approximately $45 million (in line with the 2016 level) and make capital investments of between $5 million and $6 million (slightly lower than the 2016 level). The maintenance expenditures in 2017 include an estimate of the cost to prepare Tunis for a return to service in 2018 under the new PPA.
Material Weakness Remediated
As previously disclosed in the Company's 2015 Annual Report on Form 10-K, the Company had identified a material weakness in its internal controls over financial reporting because its internal controls over its long-lived asset and goodwill impairment tests where not designed effectively. During 2016, management developed and implemented new control procedures to remediate this material weakness. Upon completion of the testing of the design and operating effectiveness of these new control procedures in the annual goodwill impairment analysis it conducted in the fourth quarter of 2016, management concluded that as of December 31, 2016, it had remediated the previously identified material weakness.
Subsequent Event
As disclosed in the Company's 2016 Annual Report on Form 10-K, on February 27, 2017, the Company received notice from the Ontario Electricity Financial Corporation (OEFC) that the Company will be receiving a payment of approximately Cdn$8.4 million for its Kapuskasing and North Bay plants representing the application of the price escalator calculation under their respective PPAs for power sold to OEFC in 2016. This payment stems from the Global Adjustment litigation brought by a group of Non-Utility Generators against the OEFC, which was decided in favor of the plaintiffs by the Superior Court of Canada. The OEFC was denied leave to appeal this ruling by the Supreme Court of Canada in January 2017.
The Company was not a party to the litigation, but did enter into a standstill agreement with the OEFC in 2015, with respect to its Kapuskasing, North Bay and Tunis projects. Under the standstill the Company reserved its right to bring claims against the OEFC with respect to the calculation of the price escalator provision in the PPAs for these three plants.
The OEFC payment of Cdn$8.4 million is for Kapuskasing and North Bay only during 2016 and does not cover any prior period. The Company has notified the OEFC that it reserves its right to contest the payment amount. The amount will be included in the Company's revenue only when the matter is settled and all contingencies have been resolved. The Company's 2017 financial guidance does not include any current or retroactive payments with respect to this matter.
Supplementary Financial Information
Results for project income and Project Adjusted EBITDA exclude discontinued operations, which consist primarily of the Wind businesses that were sold in June 2015. Results of discontinued operations are summarized on page 13 of this release.
A discussion of non-GAAP disclosures and schedules reconciling Project Adjusted EBITDA, a non-GAAP measure, to the comparable GAAP measure, can be found on pages 13 to 14 of this release.
Investor Conference Call and Webcast
Atlantic Power's management team will host a telephone conference call on Friday, March 3, 2017 at 8:30 AM ET. Management's prepared remarks and an accompanying presentation will be available on the Conference Calls page of the Company's website prior to the call.
Conference Call / Webcast Information:
Date: Friday, March 3, 2017
Start Time: 8:30 AM ET
Phone Number: U.S. (Toll Free) 1-855-239-3193; Canada (Toll Free) 1-855-669-9657; International (Toll) 1-412-542-4129.
Conference Access: Please request access to the Atlantic Power conference call.
Webcast: The call will be broadcast over Atlantic Power's website at www.atlanticpower.com.
Replay/Archive Information:
Replay: Access conference call number 10100699 at the following telephone numbers: U.S. (Toll Free) 1-877-344-7529; Canada (Toll Free) 1-855-669-9658; International (Toll) 1-412-317-0088. The replay will be available one hour after the end of the conference call through April 2, 2017 at 11:59 PM ET.
Webcast archive: The conference call will be archived on Atlantic Power's website at www.atlanticpower.com for a period of 12 months.
About Atlantic Power
Atlantic Power owns and operates a diverse fleet of twenty-three power generation assets across nine states in the United States and two provinces in Canada. The Company's power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices. The aggregate gross electric generation capacity of this portfolio is approximately 2,138 megawatts (MW), and the Company's aggregate net ownership interest is approximately 1,500 MW. Nineteen of the projects are currently operational, totaling 1,975 MW on a gross capacity basis and 1,337 MW on a net ownership basis. The remaining four projects, all in Ontario, are not operational, three due to revised contractual arrangements with the offtaker and the other, Tunis, has a forward-starting 15-year contractual agreement that will commence between November 2017 and June 2019.
Atlantic Power's shares trade on the New York Stock Exchange under the symbol AT and on the Toronto Stock Exchange under the symbol ATP. For more information, please visit the Company's website at www.atlanticpower.com or contact:
Atlantic Power Corporation
Investor Relations
(617) 977-2700
info@atlanticpower.com
Copies of the Company's financial data and other publicly filed documents are available on SEDAR at www.sedar.com or on EDGAR at www.sec.gov/edgar.shtml under "Atlantic Power Corporation" or on the Company's website.
************************************************************************************************************************
Cautionary Note Regarding Forward-Looking Statements
To the extent any statements made in this news release contain information that is not historical, these statements are forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended, and under Canadian securities law (collectively, "forward-looking statements").
Certain statements in this news release may constitute "forward-looking statements", which reflect the expectations of management regarding the future growth, results of operations, performance and business prospects and opportunities of the Company and its projects. These statements, which are based on certain assumptions and describe the Company's future plans, strategies and expectations, can generally be identified by the use of the words "may," "will," "project," "continue," "believe," "intend," "anticipate," "expect" or similar expressions that are predictions of or indicate future events or trends and which do not relate solely to present or historical matters. Examples of such statements in this press release include, but are not limited, to statements with respect to the following:
the Company's views of its debt maturity profile;
the Company's views of its ability to take a disciplined approach on PPA expirations and to withstand an extended downturn in the business;
the Company's view of the uses of capital available to it; the Company's expectation that it will repay $150 million or more of debt in 2017;
the Company's view that its shares trade at a significant discount to its estimates of intrinsic value per share;
the Company's view of its ability to implement a growth strategy;
the Company's estimation that 2017 Project Adjusted EBITDA will be in the range of $225 to $240 million, and its expectations with respect to the drivers of 2017 Project Adjusted EBITDA;
the Company's estimation that 2017 cash flows provided by operating activities will be in the range of $130 to $145 million, assuming for this purpose that working capital changes are nil;
the Company's estimate of discretionary cash (approximately $50 million), and its plans to allocate approximately $40 million or more to discretionary debt repayment in 2017;
the Company's expectation that it will realize a cash flow benefit of approximately $12 million in 2017 from discretionary investments made in 2013 through 2016 totaling approximately $25 million;
the Company's expectation that in 2017, including its share of equity-owned projects, capital expenditures will total approximately $5 to $6 million and maintenance expense will total approximately $45 million; and
the results of operations and performance of the Company's projects, business prospects, opportunities and future growth of the Company will be as described herein.
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. Please refer to the factors discussed under "Risk Factors" and "Forward-Looking Information" in the Company's periodic reports as filed with the Securities and Exchange Commission from time to time for a detailed discussion of the risks and uncertainties affecting the Company, including, without limitation, the outcome or impact of the Company's business strategy to increase the intrinsic value of the Company on a per-share basis through disciplined management of its balance sheet and cost structure and investment of its discretionary cash in a combination of organic and external growth projects, acquisitions, and repurchases of debt and equity securities; the Company's ability to enter into new PPAs on favorable terms or at all after the expiration of existing agreements, and the outcome or impact on the Company's business of any such actions. Although the forward-looking statements contained in this news release 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. These forward-looking statements are made as of the date of this news release and, except as expressly required by applicable law, the Company assumes no obligation to update or revise them to reflect new events or circumstances. The Company's ability to achieve its longer-term goals, including those described in this news release, is based on significant assumptions relating to and including, among other things, the general conditions of the markets in which it operates, revenues, internal and external growth opportunities, its ability to sell assets at favorable prices or at all and general financial market and interest rate conditions. The Company's actual results may differ, possibly materially and adversely, from these goals.
Atlantic Power Corporation
Table 4 – Consolidated Balance Sheet (in millions of U.S. dollars)
December 31,
December 31,
2016
2015
Assets
Current assets:
Cash and cash equivalents
$85.6
$72.4
Restricted cash
13.3
15.2
Accounts receivable
37.3
39.6
Current portion of derivative instruments asset
4.0
-
Inventory
16.0
16.9
Prepayments
5.9
8.3
Other current assets
2.8
4.5
Total current assets
164.9
156.9
Property, plant and equipment, net
733.2
777.7
Equity investments in unconsolidated affiliates
266.8
286.2
Power purchase agreements and intangible assets, net
246.2
308.9
Goodwill
36.0
134.5
Derivative instruments asset
4.6
0.3
Other assets
5.1
6.7
Total assets
$1,456.8
$1,671.2
Liabilities
Current liabilities:
Accounts payable
$4.5
$6.9
Accrued interest
0.7
1.6
Other accrued liabilities
24.4
25.4
Current portion of long-term debt
111.9
15.8
Current portion of derivative instruments liability
7.6
36.7
Other current liabilities
1.8
2.5
Total current liabilities
150.9
88.9
Long-term debt (1)
749.2
682.7
Convertible debentures (2)
100.4
277.7
Derivative instruments liability
21.3
20.8
Deferred income taxes
68.3
85.7
Power purchase and fuel supply agreement liabilities, net
25.3
27.0
Other long-term liabilities
55.5
53.2
Total liabilities
$1,170.9
$1,236.0
Equity
Common shares, no par value, unlimited authorized shares; 114,649,888 and 122,153,082 issued and outstanding at December 31, 2016 and December 31, 2015, respectively
1,272.9
1,290.6
Accumulated other comprehensive loss
(148.5)
(139.3)
Retained deficit
(1,059.8)
(937.4)
Total Atlantic Power Corporation shareholders' equity
64.6
213.9
Preferred shares issued by a subsidiary company
221.3
221.3
Total equity
285.9
435.2
Total liabilities and equity
$1,456.8
$1,671.2
(1) Net of unamortized discount and deferred financing costs
(2) Net of unamortized deferred financing costs
Atlantic Power Corporation
Table 5 – Consolidated Statements of Operations
(in millions of U.S. dollars, except per share amounts)
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
Project revenue:
Energy sales
$45.8
$46.6
$184.2
$191.5
Energy capacity revenue
28.7
31.9
141.9
149.3
Other
18.9
19.9
73.1
79.4
93.4
98.4
399.2
420.2
Project expenses:
Fuel
38.7
39.8
149.5
165.1
Operations and maintenance
25.8
21.9
105.2
103.5
Development
-
-
-
1.1
Depreciation and amortization
37.9
26.2
113.5
110.0
102.4
87.9
368.2
379.7
Project other income (expense):
Change in fair value of derivative instruments
17.8
6.7
37.9
15.4
Equity in earnings of unconsolidated affiliates
8.0
8.4
35.9
36.7
Gain on sale of equity investments
-
-
-
-
Interest, net
(2.3)
(2.0)
(9.2)
(8.2)
Impairment
(1.2)
(127.8)
(85.9)
(127.8)
Other income, net
-
(0.1)
0.4
2.0
22.3
(114.8)
(20.9)
(81.9)
Project income (loss)
13.3
(104.3)
10.1
(41.4)
Administrative and other expenses:
Administration
5.0
6.4
22.6
29.4
Interest, net
18.2
15.8
106.0
107.1
Foreign exchange loss (gain)
(5.1)
(11.2)
13.9
(60.3)
Other income, net
-
-
(3.9)
(3.1)
18.1
11.0
138.6
73.1
Loss from continuing operations before income taxes
(4.8)
(115.3)
(128.5)
(114.5)
Income tax benefit
(0.4)
(29.9)
(14.6)
(30.4)
Loss from continuing operations
(4.4)
(85.4)
(113.9)
(84.1)
Net (loss) income from discontinued operations, net of tax (1)
-
(1.3)
-
19.5
Net loss
(4.4)
(86.7)
(113.9)
(64.6)
Net loss attributable to noncontrolling interests
-
-
-
(11.0)
Net income attributable to preferred share dividends of a subsidiary company
2.2
1.9
8.5
8.8
Net loss attributable to Atlantic Power Corporation
($6.6)
($88.6)
($122.4)
($62.4)
Basic and diluted (loss) income per share:
Loss from continuing operations attributable to Atlantic Power Corporation
($0.06)
($0.71)
($1.02)
($0.76)
(Loss) income from discontinued operations, net of tax
-
(0.01)
-
0.25
Net loss attributable to Atlantic Power Corporation
($0.06)
($0.72)
($1.02)
($0.51)
Weighted average number of common shares outstanding:
Basic
115.5
122.1
119.5
121.9
Diluted
115.5
122.1
119.5
121.9
Dividends per common share:
$-
$0.02
$-
$0.09
(1) Includes contributions from the Wind Projects, which are components of discontinued operations.
Atlantic Power Corporation
Table 6 – Consolidated Statements of Cash Flows (in millions of U.S. dollars)
Twelve months ended December 31,
2016
2015
Cash provided by operating activities:
Net loss
($113.9)
($64.6)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization
113.5
120.3
Gain on sale of assets
0.2
(48.7)
Gain on purchase and cancellation of convertible debentures
(3.7)
(3.1)
Write off of deferred financing costs
32.8
9.0
Stock-based compensation expense
1.8
2.3
Long-lived assets and goodwill impairment charges
85.9
127.8
Equity in earnings from unconsolidated affiliates
(35.9)
(36.2)
Distributions from unconsolidated affiliates
55.3
58.5
Unrealized foreign exchange loss (gain)
13.8
(60.5)
Change in fair value of derivative instruments
(37.9)
(14.7)
Change in deferred income taxes
(17.5)
(3.5)
Change in other operating balances
Accounts receivable
2.3
5.7
Inventory
0.9
2.4
Prepayments and other assets
17.0
11.9
Accounts payable
(0.2)
(8.9)
Accruals and other liabilities
(2.6)
(10.3)
Cash provided by operating activities
111.8
87.4
Cash (used in) provided by investing activities:
Change in restricted cash
1.9
7.3
Proceeds from sale of assets and equity investments, net
-
326.3
Contribution to unconsolidated affiliate
-
(0.6)
Capitalized development costs
-
(0.8)
Reimbursement of costs for third-party construction project
4.8
-
Purchase of property, plant and equipment
(7.2)
(11.3)
Cash (used in) provided by investing activities
(0.5)
320.9
Cash used in financing activities:
Proceeds from New Term Loan facility, net of discount
679.0
-
Common share repurchases
(19.5)
-
Repayment of corporate and project-level debt
(544.4)
(403.3)
Repayment of convertible debentures
(188.5)
(18.9)
Deferred financing costs
(16.2)
-
Dividends paid to common shareholders
-
(11.1)
Dividends paid to noncontrolling interests
-
(3.7)
Dividends paid to preferred shareholders
(8.5)
(8.8)
Cash used in financing activities
(98.1)
(445.8)
Net increase (decrease) in cash and cash equivalents
13.2
(37.5)
Cash and cash equivalents at beginning of period at discontinued operations
-
3.9
Cash and cash equivalents at beginning of period
72.4
106.0
Cash and cash equivalents at end of period
$85.6
$72.4
Supplemental cash flow information
Interest paid
$70.7
$100.0
Income taxes paid, net
3.5
10.2
Accruals for construction in progress
1.2
0.6
Results of Discontinued Operations
The Wind projects, which were sold in June 2015, had no impact on financial results in 2016. For the year ended December 31, 2015, the Wind projects had Project income of $52.6 million and cash provided by operating activities of $21.9 million, as shown in Table 7.
Atlantic Power Corporation
Table 7 – Discontinued Operations
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
Project revenue
$-
$-
$-
$34.8
Project (loss) income
-
(0.6)
-
52.6
Net (loss) income
-
(1.1)
-
19.5
Cash provided by operating activities
-
-
-
21.9
Cash used in investing activities
-
-
-
(12.8)
Non-GAAP Disclosures
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. Investors are cautioned that the Company may calculate this non-GAAP measure in a manner that is different from other companies. The most directly comparable GAAP measure is Project income (loss). Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in the fair value of derivative instruments. Management uses Project Adjusted EBITDA at the project level to provide comparative information about project performance and believes such information is helpful to investors. A reconciliation of Project Adjusted EBITDA to Project income (loss) and to Net loss on a consolidated basis is provided in Table 8 on page 14 of this release.
Cash Distributions from Projects is the amount of cash distributed by the projects to the Company out of available project cash flow after all project-level operating costs, interest payments, principal repayment, capital expenditures and working capital requirements. A bridge of Project Adjusted EBITDA to Cash Distributions from Projects, previously included in this release, can be found in the fourth quarter and year end 2016 presentation on the Company's website.
Project income (loss) and Project Adjusted EBITDA by project, previously included in this release, can be found in the fourth quarter and year end 2016 presentation on the Company's website.
Atlantic Power Corporation
Table 8 – Reconciliation of Net loss to Project Adjusted EBITDA
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
Three months ended
December 31
Twelve months ended
December 31
2016
2015
2016
2015
Net loss attributable to Atlantic Power Corporation
($6.6)
($88.6)
($122.4)
($62.4)
Net income attributable to preferred share dividends of a subsidiary company
2.2
1.9
8.5
8.8
Net loss attributable to noncontrolling interests
-
-
-
(11.0)
Net loss
($4.4)
($86.7)
($113.9)
($64.6)
Net (loss) income from discontinued operations, net of tax
-
1.3
-
(19.5)
Net loss from continuing operations
(4.4)
(85.4)
(113.9)
(84.1)
Income tax benefit
(0.4)
(29.9)
(14.6)
(30.4)
Loss from continuing operations before income taxes
(4.8)
(115.3)
(128.5)
(114.5)
Administration
5.0
6.4
22.6
29.4
Interest expense, net
18.2
15.8
106.0
107.1
Foreign exchange loss (gain)
(5.1)
(11.2)
13.9
(60.3)
Other income, net
-
-
(3.9)
(3.1)
Project income (loss)
$13.3
($104.3)
$10.1
($41.4)
Reconciliation to Project Adjusted EBITDA
Depreciation and amortization
$42.7
$31.2
$133.5
$130.1
Interest expense, net
2.7
2.1
10.9
9.8
Change in the fair value of derivative instruments
(17.8)
(6.7)
(37.9)
(15.4)
Impairment
1.2
127.8
85.9
127.8
Other (income) expense
0.2
0.3
(0.3)
(2.0)
Total Project Adjusted EBITDA
$42.3
$50.4
$202.2
$208.9
To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/atlantic-power-corporation-releases-fourth-quarter-and-year-end-2016-results-300417393.html
SOURCE Atlantic Power Corporation
Copyright 2017 Canada NewsWire
Easy1
8 years ago
Atlantic Power Corporation Releases Third Quarter 2016 Results and Narrows 2016 Guidance Range
Source: PR Newswire (Canada)
DEDHAM, Mass., Nov. 7, 2016 /CNW/ -- Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the "Company") today reported cash provided by operating activities of $38.2 million for the third quarter of 2016, an increase of $23.9 million from the year-ago period primarily due to lower cash interest payments (resulting from debt repayment) and favorable changes in working capital.
Third Quarter 2016 Financial Results (and Comparison to Third Quarter 2015)
Cash provided by operating activities of $38.2 million vs. $14.3 million
Net loss of $(82.4) million, including $84.7 million non-cash impairment charge, vs. $(6.0) million
Project loss of $(57.1) million including impairment charge vs. project income of $24.2 million
Project Adjusted EBITDA of $51.3 million vs. $56.0 million
Other Highlights
Repaid $20 million of term loan ($45.1 million year to date, plus $25.3 million on previous term loan in first quarter)
Amortized $3.7 million of project debt ($8.0 million year to date)
Repurchased 3.7 million common shares (7.1 million in total under normal course issuer bid; total investment $17.3 million at an average price of $2.44)
Reduced 2016 estimated total overhead costs to $24 million from previous estimate of $27 million
The Company reported a net loss for the third quarter of 2016 of $(82.4) million, which included a non-cash impairment charge of $84.7 million, versus a net loss for the third quarter of 2015 of $(6.0) million. The increased net loss was primarily attributable to the impairment charge and a reduction in foreign exchange gain, partially offset by lower interest expense. Project loss for the third quarter of 2016 was $(57.1) million including the impairment charge versus project income for the year-ago period of $24.2 million. In addition to the impairment charge, the result also reflected a reduction in foreign exchange gain, partially offset by lower interest expense.
Project Adjusted EBITDA for the third quarter of 2016 was $51.3 million, a decline of $4.7 million from the year-ago period. The primary drivers were an extended planned outage at Morris and lower water flows at Curtis Palmer, partially offset by higher water flows at Mamquam and lower maintenance expense at Kapuskasing and North Bay.
"During the third quarter we continued to make significant progress in strengthening our balance sheet and improving our debt maturity profile, repaying nearly $24 million of term loan and project debt and repurchasing approximately $63 million of our June 2019 convertible debentures. Continued debt repayment should improve our leverage ratio of 5.8 times by more than a turn by the end of next year," said James J. Moore, Jr., President and CEO of Atlantic Power. "In addition, during the quarter we repurchased nearly 3.7 million common shares, for a total of 7.1 million repurchased under the normal course issuer bid implemented last December. The average repurchase price of $2.44 per share represents a significant discount to our estimate of intrinsic value. We currently have approximately $60 million of discretionary cash available for further debt and equity repurchases and internal or external growth investments, which we will continue to allocate to the highest-return uses."
"We continue to focus on cost and debt reduction as an important contributor to improved cash flow. Over the next four years we expect to amortize more than $400 million of our term loan and project debt, which will drive interest expense and leverage lower," continued Mr. Moore. "In addition, we now expect our overhead costs for 2016 to be approximately $24 million, more than 10% lower than our previous estimate, which was already 50% below the level of 2013. We plan to aggressively seek further cost reduction opportunities, with a major focus on operating costs in 2017."
Atlantic Power Corporation
Table 1 – Selected Results
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
Three months ended
September 30,
Nine months ended
September 30,
2016
2015
2016
2015
Financial Results
Project revenue
$101.2
$107.5
$305.8
$321.8
Project (loss) income
(57.1)
24.2
(3.3)
63.0
Net (loss) income attributable to Atlantic Power Corporation
(82.4)
(6.0)
(116.2)
26.1
Cash provided by operating activities
38.2
14.3
91.9
67.7
Project Adjusted EBITDA
51.3
56.0
159.9
158.5
Cash Distributions from Projects
50.4
51.5
140.6
138.8
Operating Results
Aggregate power generation (thousands of Net MWh)
1,540.2
1,666.7
4,565.8
4,707.1
Weighted average availability
91.1%
96.2%
93.5%
94.9%
All amounts are in U.S. dollars and are approximate unless otherwise indicated. Project Adjusted EBITDA is not a recognized measure under generally accepted accounting principles in the United States ("GAAP") and does not have a standardized meaning prescribed by GAAP; therefore, this measure may not be comparable to similar measures presented by other companies. Please refer to "Non-GAAP Disclosures" beginning on page 15 of this news release for an explanation and a reconciliation of "Project Adjusted EBITDA" as used in this news release to project income (loss), the most directly comparable measure on a GAAP basis, and net income (loss). Cash Distributions from Projects is the amount of cash distributed by the projects to the Company out of available project cash flow after all project-level operating costs, interest payments, principal repayment, capital expenditures and working capital requirements. It is not a non-GAAP measure. Project Adjusted EBITDA, a non-GAAP measure, is the most comparable measure, but it is before debt service, capital expenditures and working capital requirements. The Company has included a bridge of Project Adjusted EBITDA to Cash Distributions from Projects in the "Non-GAAP Disclosures" section of this release.
The Wind Projects consisted 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). The Wind Projects were sold in June 2015 and are included in discontinued operations for the three and nine months ended September 30, 2015. Results of the Wind Projects are excluded from Operating Results in Table 1 and as discussed below. Results of the Wind Projects are excluded from Project revenue, Project (loss) income, Project Adjusted EBITDA and Cash Distributions from Projects as shown in Table 1 and as discussed below but are included in Net (loss) income attributable to Atlantic Power Corporation and Cash provided by operating activities as shown in Table 1.
Operating Results
Three Months ended September 30, 2016
Project availability was 91.1% in the third quarter of 2016, a decrease from 96.2% in the year-ago period. Morris underwent an extensive overhaul in the third quarter and Calstock deferred its spring outage to the fall. The impact of these outages was partially offset by higher availability at Piedmont, which had fewer outages in the third quarter, and Mamquam, which had a planned outage in the third quarter of 2015.
Generation decreased 7.6% in the third quarter of 2016 from the year-ago period, primarily due to the Morris overhaul; Frederickson, which had lower dispatch, and lower generation at Curtis Palmer due to lower water flows. These decreases were partially offset by higher generation at Mamquam due to higher water flows in 2016 and a maintenance outage in the third quarter of 2015.
Nine Months ended September 30, 2016
Project availability was 93.5% in the first nine months of 2016, a decrease from 94.9% in the year-ago period. The Morris overhaul was the primary driver of the reduced availability. This was partially offset by higher availability at Mamquam, which had a planned outage in the third quarter of 2015, and Manchief, which had a major outage in the second quarter of 2015.
Generation decreased by 3.0% in the first nine months of 2016 from the year-ago period, primarily due to lower dispatch at Manchief and Selkirk and maintenance outages at Morris and Chambers. These decreases were partially offset by higher generation at Mamquam due to higher water flows in 2016 and a maintenance outage in the comparable 2015 period.
Income and Project Adjusted EBITDA
Three Months Ended September 30, 2016
Impairment
In the third quarter of 2016, as discussed in further detail in its report on Form 10-Q, the Company recorded a non-cash impairment charge of $84.7 million. Of the total, $78.8 million was for an impairment of goodwill at its Mamquam, Curtis Palmer, North Bay and Kapuskasing projects and the remainder was for an impairment of the carrying value of long-lived assets at its North Bay and Kapuskasing projects. As a result of these impairments, goodwill was reduced to $37.6 million at September 30, 2016.
The impairment resulted from an event-driven goodwill impairment test, which was undertaken because of a significant decline during the quarter in the long-term power price outlook provided by a third party and used by the Company in this analysis. Estimated future cash flows (beyond the expiration of the Power Purchase Agreement or PPA) are sensitive to forward power prices. Additionally, the approaching expiration dates of the North Bay and Kapuskasing PPAs were a factor in the impairment analysis.
Because the third-quarter test was event-driven, the Company is still required to conduct an annual impairment test, which it will do in the fourth quarter of 2016. As previously disclosed, the Company identified a material weakness with respect to its controls over impairment testing at the time the previous annual test was conducted. Management is actively engaged in remediating this weakness, and has re-designed certain controls and implemented new controls as part of this process. The Company expects to remediate this weakness by the time its year end 2016 financial statements are filed on Form 10-K.
Net income (loss)
The Company reported a net loss of $(82.4) million versus a net loss of $(6.0) million in the third quarter of 2015. The year-over-year decrease was mostly attributable to an $84.7 million impairment charge recorded in the 2016 period as described above and an $18.3 million decrease in a largely unrealized foreign exchange gain relative to 2015. These negative factors were partially offset by lower interest expense in 2016, which was attributable to debt repayment in 2015 and 2016 and to the non-recurrence of $19.5 million of interest and redemption costs associated with the July 2015 redemption of the Company's 9.0% Senior Unsecured Notes (the "9.0% Notes").
Project income (loss) and Project Adjusted EBITDA
Table 2 provides a breakdown of Project income and Project Adjusted EBITDA by segment for the three and nine months ended September 30, 2016 as compared to the same periods in 2015. An explanation of these two metrics can be found in the Note to Table 2. Results for project income and Project Adjusted EBITDA exclude discontinued operations; accordingly, results of the Wind Projects, which were sold in June 2015, are not included in either metric for the periods shown in Table 2.
Project loss for the third quarter of 2016 was $(57.1) million versus project income of $24.2 million for the year-ago period. The primary reason for the change from project income to project loss was the $84.7 million impairment recorded in the third quarter of 2016. Another factor was the reduction in foreign exchange gain from $21.7 million in 2015 to $3.4 million in 2016. These negative factors were partially offset by increased income attributable to the fair value of derivatives and lower interest expense, in part because of the costs associated with the redemption of the 9.0% Notes in the third quarter of 2015.
Project Adjusted EBITDA decreased $4.7 million to $51.3 million for the third quarter of 2016. Morris had an $8.5 million reduction in Project Adjusted EBITDA, primarily attributable to higher maintenance expense and reduced gross margin due to a planned extended outage. Lower water flows at Curtis Palmer and expiration of a rate adder at Calstock also contributed to the decrease. These factors were partially offset by higher water flows at Mamquam, lower maintenance expense at Kapuskasing and North Bay, and increases at other projects.
Atlantic Power Corporation
Table 2 – Segment Results
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
Three months ended September 30,
Nine months ended September 30,
2016
2015
2016
2015
Project income (loss)
East U.S.
($8.6)
$12.4
$16.9
$40.0
West U.S.
11.4
11.5
13.8
7.3
Canada
(62.4)
1.9
(33.1)
17.9
Un-allocated Corporate
2.5
(1.6)
(0.9)
(2.2)
Total
($57.1)
$24.2
($3.3)
$63.0
Project Adjusted EBITDA
East U.S.
$19.4
$27.4
$70.5
$81.0
West U.S.
21.3
21.4
43.4
37.1
Canada
10.7
7.6
46.2
43.0
Un-allocated Corporate
(0.1)
(0.4)
(0.2)
(2.6)
Total
$51.3
$56.0
$159.9
$158.5
Note: The results of the Wind Projects are included in discontinued operations and are excluded from Project income and Project Adjusted EBITDA as presented in Table 2.
Project income (loss) is a GAAP measure that can fluctuate significantly due to non-cash adjustments to "mark-to-market" the fair value of derivatives. Non-cash impairment charges and gains or losses on the sale of assets are included in project income and can also affect year-over-year comparisons.
Project Adjusted EBITDA is a non-GAAP measure. Management believes that Project Adjusted EBITDA, which includes the proportional share of Project Adjusted EBITDA from the Company's equity method projects, is a more useful measure of financial results at its projects because it excludes non-cash impairment charges, gains or losses on the sale of assets and non-cash mark-to-market adjustments, all of which can affect year-to-year comparisons. Project Adjusted EBITDA is before corporate overhead expense. The most directly comparable GAAP measure to Project Adjusted EBITDA is Project income; Tables 10A through 10D of this release provide a reconciliation of Net income to Project income and to Project Adjusted EBITDA by segment and on a consolidated basis for the three- and nine-month periods ended September 30, 2016 and September 30, 2015.
Corporate-level general and administrative (G&A) expense (shown as "Administration" on the Consolidated Statements of Operations) decreased $1.2 million in the third quarter of 2016 to $5.7 million. The improvement was primarily due to decreases in professional services expenses, compensation costs and rent expenses.
Nine Months Ended September 30, 2016
Net income (loss)
The Company had a net loss of $(116.2) million for the first nine months of 2016 versus net income of $26.1 million for the comparable 2015 period. The 2016 result included the $84.7 million impairment charge recorded in the third quarter and a $31.5 million non-cash write-off of deferred financing costs in the second quarter. The 2015 result included $20.6 million of net income from discontinued operations (Wind business) and an $11.0 million loss attributable to noncontrolling interests (Wind). The benefit of lower corporate G&A and lower interest expense in 2016 was more than offset by a largely unrealized foreign exchange loss of $19.1 million versus a foreign exchange gain in 2015.
Project income (loss) and Project Adjusted EBITDA
Project loss of $3.3 million for the first nine months of 2016 compared unfavorably to project income of $63.0 million for the 2015 period. The 2016 result included the impairment charge previously described. Excluding the impairment charge, project income increased $18.4 million from the year-ago period, primarily due to a favorable change in the fair value of derivative instruments, lower depreciation expense following an impairment of long-lived assets in the fourth quarter of 2015, and higher project income at Manchief, which had a scheduled maintenance overhaul in the second quarter of 2015, partially offset by lower project income at Morris, which had an extended planned outage in the third quarter of 2016.
Project Adjusted EBITDA of $159.9 million for the first nine months of 2016 increased $1.4 million from $158.5 million for the 2015 period. Lower maintenance expense and higher revenue at Manchief, which had an outage in 2015, and higher water flows at Mamquam were partially offset by higher maintenance expense and lower revenues at Morris due to the extended outage in 2016 and by gas turbine maintenance expense and lower steam demand at Kenilworth.
Corporate-level G&A expense of $17.6 million for the first nine months of 2016 was $5.4 million lower than the year-ago period primarily due to a $2.3 million reduction in employee compensation expense, a $1.6 million decrease in professional services costs and a $1.4 million decrease in rent expense.
Cash Flow
Table 3 presents cash flow results for the Company for the three and nine months ended September 30, 2016 as compared to the same periods in 2015.
Atlantic Power Corporation
Table 3 – Cash Flow Results
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
Three months ended September 30,
Nine months ended September 30,
2016
2015
2016
2015
Cash Provided by Operating Activities
$38.2
$14.3
$91.9
$67.7
Amount attributable to Discontinued Operations (Wind Projects) included above
-
-
-
21.9
Cash Distributions from Projects (excludes
Discontinued Operations) (1)
50.4
51.5
140.6
138.8
(1) There were no cash distributions from the Wind Projects for the three months ended September 30, 2016 and 2015. Excludes cash distributions from the Wind Projects of $0 and $9.3 million for the nine months ended September 30, 2016 and 2015, respectively.
Three Months Ended September 30, 2016
Cash provided by operating activities (a GAAP measure) increased $23.9 million to $38.2 million from $14.3 million in the third quarter of 2015. The increase was primarily attributable to a $20.6 million reduction in cash interest payments due to debt repayment in 2016 and 2015 and make-whole payments associated with the redemption of the 9.0% Notes in 2015.
Changes in other operating balances (such as receivables, payables and certain other assets and liabilities) were a positive $17.5 million versus $7.6 million in the year-ago period, or a $9.9 million benefit to cash flow in 2016 as compared to 2015. The positive impact of lower cash interest payments and the favorable change in other operating balances was partially offset by lower Project Adjusted EBITDA ($4.7 million).
During the quarter, the Company used operating cash flow to repay term loan debt of $20 million and project debt of $3.7 million, make capital expenditures of $4.5 million and pay preferred dividends of $2.2 million. In the third quarter of 2015, repayment of the term loan was $9.7 million, project debt repayment was $4.4 million, capital expenditures were $4.4 million and preferred dividends were $2.1 million.
Cash Distributions from Projects is the amount of cash distributed by the projects to the Company out of available project cash flow after all project-level operating costs, interest payments, principal repayment, capital expenditures and working capital requirements. In the third quarter of 2016, Cash Distributions from Projects decreased $1.1 million to $50.4 million from $51.5 million for the same period in 2015. The decrease was primarily due to Curtis Palmer, which experienced lower water flows, and Morris, which underwent an extensive overhaul in the third quarter of 2016. These decreases were partially offset by increases at Manchief, Kapuskasing and Nipigon because of major maintenance/optimization events in the third quarter of 2015 that did not recur in the third quarter of 2016.
Nine Months Ended September 30, 2016
Cash provided by operating activities increased $24.2 million in the first nine months of 2016 to $91.9 million from $67.7 million in the year-ago period. The 2015 result included $21.9 million of operating cash flow from the Wind business. Excluding this discontinued operation, operating cash flow increased approximately $46 million. The increase was primarily attributable to a reduction of $32.2 million in cash interest payments (of which $1.5 million was attributable to the Wind business) due to debt repayment in 2015 and 2016 and the absence of make-whole premiums associated with the redemption of the 9.0% Notes in 2015. Lower corporate G&A expense of $5.4 million was also a positive factor.
Changes in other operating balances in the first nine months of 2016 were $53.6 million versus $24.4 million in the comparable period in 2015. The 2016 result included $31.5 million for the write-off of deferred financing costs in the second quarter, which was included in net income (loss) but did not affect cash flow, and the 2015 figure included $3.2 million related to the Wind business. Excluding these items, changes in other operating balances were approximately $22 million in 2016 and $21 million in 2015, or a $1 million benefit to cash flow in 2016 as compared to 2015.
In the first nine months of 2016, the Company used operating cash flow to repay term loan debt of $70.5 million (including $25.3 million related to the previous term loan in the first quarter) and project debt of $8.0 million, make capital expenditures of $6.5 million and pay preferred dividends of $6.4 million. In the first nine months of 2015, repayment of the term loan was $56.5 million, project debt repayments totaled $10.8 million, capital expenditures were $9.4 million and preferred dividends were $6.7 million.
Cash Distributions from Projects increased $1.8 million to $140.6 million for the first nine months of 2016 from $138.8 million for the same period in 2015. The increase was due to Manchief, which underwent a gas turbine major overhaul last year; Morris, which received a reimbursement for a customer-owned construction project this year; and Mamquam, which benefited from higher water flows. These increases were partially offset by Chambers, which under the new project debt agreement in 2014 made a nine-month distribution in January 2015 versus a six-month distribution in January 2016.
Results of Discontinued Operations
The Wind projects, which were sold in June 2015, had no impact on financial results in 2016. For the first nine months of 2015, the Wind projects had Project income of $53.2 million, Cash provided by operating activities of $21.9 million and Cash Distributions of $9.3 million, as shown in Table 4.
Atlantic Power Corporation
Table 4 – Discontinued Operations
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
Three months ended September 30,
Nine months ended September 30,
2016
2015
2016
2015
Project revenue
$-
$-
$-
$34.8
Project income (loss)
-
(0.2)
-
53.2
Net (loss) income
-
(0.5)
-
20.6
Cash provided by operating activities
-
-
-
21.9
Cash Distributions from Projects
-
-
-
9.3
Liquidity and Recent Balance Sheet Initiatives
Balance Sheet
Substantial Issuer Bid for 2019 Convertible Debentures
As previously reported, in July 2016, the Company repurchased and canceled $62.7 million of its Series C Convertible Debentures under a substantial issuer bid. The price was $965 per $1,000 of principal amount, plus accrued and unpaid interest. At September 30, 2016, there were approximately $42.6 million of Series C Convertible Debentures outstanding.
Mandatory Debt Repayment
During the third quarter of 2016, the Company amortized $20 million of the APLP Holdings term loan and $3.7 million of project-level debt. Year to date, the Company has amortized $70.5 million of term loan debt, including $25.3 million in the first quarter related to the previous term loan, and $8.0 million of project-level debt. The Company expects to repay another $15 million of term loan and $2.9 million of project-level debt in the fourth quarter of 2016.
Normal Course Issuer Bid (Discretionary repurchases)
Convertible debentures: In the first quarter of 2016, the Company repurchased $18.8 million principal amount of convertible debentures under the normal course issuer bid (NCIB). The remaining 2017 convertible debentures were redeemed in May using net proceeds from the term loan refinancing. The Company did not make any additional repurchases of convertible debentures under the NCIB in the second or third quarters of 2016 because it had already reached the maximum amounts of repurchases of 2019 convertible debentures allowable under the NCIB ($11.7 million for the Series C and Cdn$9.0 million for the Series D).
Common shares: The Company repurchased slightly less than 3.7 million common shares in the third quarter at a cost of approximately $9.1 million. During the fourth quarter to date, the Company has repurchased another 1.4 million common shares. Since the NCIB was implemented in December, the Company has repurchased a total of 7.1 million common shares at a total cost of approximately $17.3 million (average price of $2.44 per share).
The NCIB is scheduled to expire on December 28, 2016.
Debt Balance and Leverage at September 30, 2016
Although the refinancing of the previous term loan in April 2016 resulted in a net increase in debt of $252 million, the allocation of a majority of the net cash proceeds from the refinancing to debt redemptions and repurchases in the second and third quarters of this year, together with ongoing amortization of the new term loan and project debt, have offset the majority of this increase. At September 30, 2016, the Company's consolidated debt was $1.02 billion, excluding unamortized discounts and deferred financing costs, as compared to $993 million prior to the refinancing. The Company's leverage ratio (consolidated gross debt to trailing 12-month consolidated Adjusted EBITDA) was 5.8 times at September 30, 2016. The Company expects this ratio to decline to 5.6 times by the end of 2016.
Debt Maturity Profile
As a result of refinancing and discretionary repurchases to date, the Company has no bullet maturities at the corporate level prior to June 2019, when the remaining $42.6 million of Series C convertible debentures will mature. In addition, the Company has $61.7 million (U.S. dollar equivalent) of Series D convertible debentures maturing in December 2019. The reshaping of the Company's maturity profile is further improved by the later maturity dates for the new term loan (2023 versus 2021 previously) and the new revolver (2021 versus 2018 previously). The Company also has one project debt bullet maturity during this period – the term loan at its Piedmont project totaling $54 million at its maturity date of August 2018. In addition to these bullet maturities, the Company has amortizing debt at various projects through 2025 and required amortization of the APLP Holdings term loan per a targeted debt schedule through the 2023 maturity date.
Liquidity
As shown in Table 5, the Company's liquidity at September 30, 2016 was $205.1 million, including $93.8 million of unrestricted cash and $111.3 million of borrowing capacity under its corporate revolver. Liquidity at June 30, 2016 was $251.4 million, including $154.2 million of unrestricted cash and $97.2 million of borrowing capacity. Borrowing capacity increased $13.9 million because of a reduction in letters of credit outstanding. The cash balance decreased approximately $60 million during the quarter, as the Company used $61 million of cash to repurchase $62.7 million of its Series C Convertible Debentures at a price of 96.5%. The Company also repurchased $9.1 million of common shares. Operating cash flow exceeded debt repayment, capital expenditures and preferred dividend payments for the quarter by approximately $8 million.
Atlantic Power Corporation
Table 5 – Liquidity (in millions of U.S. dollars)
Unaudited
June 30, 2016
September 30,
2016
Revolver capacity
$200.0
$200.0
Letters of credit outstanding
(102.8)
(88.7)
Unused borrowing capacity
97.2
111.3
Unrestricted cash
154.2
93.8
Total Liquidity
$251.4
$205.1
Note: Liquidity numbers presented do not include restricted cash of $14.3 million at June 30, 2016 and $12.6 million at September 30, 2016.
Other Financial Updates
2016 Guidance
The Company has not provided guidance for Project income or Net income because of the difficulty of making accurate forecasts and projections without unreasonable efforts with respect to certain highly variable components of these comparable GAAP metrics, including changes in the fair value of derivative instruments and foreign exchange gains or losses. These factors, which generally do not affect cash flow, are not included in Project Adjusted EBITDA.
Based on the results of the nine months ended September 30, 2016 and the outlook for the fourth quarter of 2016, the Company is narrowing its range for 2016 Project Adjusted EBITDA guidance to between $205 and $215 million, from the previous range of $200 to $220 million.
Table 6 provides a bridge of the Company's 2016 Project Adjusted EBITDA guidance to Cash provided by operating activities. For purposes of providing this bridge to a cash flow measure, the impact of changes in working capital is assumed to be nil.
Atlantic Power Corporation
Table 6 – Bridge of 2016 Project Adjusted EBITDA Guidance to Cash Provided by Operating Activities
(in millions of U.S. dollars)
Unaudited
2016 Project Adjusted EBITDA Guidance(1)
$205 - $215
Adjustment for equity method projects(2)
(2)
Corporate G&A expense
(23)
Cash interest payments
(73)
Cash taxes
(4)
Other
-
Cash provided by operating activities
$100 - $115
Note: For the purpose of providing a bridge of Project Adjusted EBITDA guidance to a cash flow measure, the impact of changes in working capital on Cash provided by operating activities is assumed to be nil.
(1) Initially provided March 7, 2016 and revised November 7, 2016.
(2) For equity method projects, represents difference between Project Adjusted EBITDA and cash distribution from equity method projects.
Optimization Investments
The Company expects to make approximately $3.5 million of optimization-related investments in its projects in 2016, with the majority of those for upgrades to a boiler and two combustion turbines at Morris and a spillway upgrade project at Curtis Palmer. The Morris turbine upgrades were completed in September during the extended outage. Work on the boiler upgrade has been completed and final testing is expected to be completed by the end of November. The Curtis Palmer project was completed in November.
The Company expects to realize a cash flow benefit of approximately $8 million in 2016 from investments made in 2013 through 2016 totaling approximately $25 million. This is lower than the original expectation primarily because higher levels of waste heat at Nipigon have reduced the need for the duct burners and booster pump that were installed as optimization projects in 2014 and 2015, respectively. The cash flow benefit of additional waste heat has more than offset the lower return from optimization. In addition, low water flows at Curtis Palmer this year have reduced the contribution from the turbine upgrades completed in 2013 and 2014.
Maintenance and Capex
Through the first nine months of 2016, the Company has made $6.5 million of capital expenditures and incurred $36.8 million of maintenance expense. For the full year, the Company expects to make capital expenditures of $8 million (including $3.5 million for optimization projects) and incur maintenance expense in 2016 of approximately $47 million. Both the capex and maintenance expenditures forecasts include the Company's share of projects in which it has an equity ownership interest.
The capital expenditure forecast does not include any outlays for converting Tunis to simple cycle operation (in conjunction with the new Power Purchase Agreement), as there has not yet been a decision with respect to the start date for the new PPA, or for a new fuel shredder at Williams Lake, which would accommodate rail ties as part of the project's fuel supply. In September, the Company received an amended air permit for Williams Lake that would allow increased use of rail ties, but the permit has been appealed. Investment in the shredder is contingent on resolution of the appeal as well as on an agreement with BC Hydro on a long-term extension of the existing PPA, which is scheduled to expire in March 2018.
Supplementary Financial Information
For a discussion of non-GAAP disclosures and schedules reconciling the Company's non-GAAP measure to the comparable GAAP measure, please refer to pages 15-21 of this release. Included in this section is a summary of Project income and Project Adjusted EBITDA by project for the three and nine months ended September 30, 2016 and 2015 (Tables 12 and 13, respectively).
Investor Conference Call and Webcast
Atlantic Power's management team will host a telephone conference call on Tuesday, November 8, 2016 at 8:30 AM ET. An accompanying slide presentation will be available on the Company's website prior to the call.
Conference Call / Webcast Information:
Date: Tuesday, November 8, 2016
Start Time: 8:30 AM ET
Phone Number: U.S. (Toll Free) 1-855-239-3193; Canada (Toll Free) 1-855-669-9657; International (Toll) 1-412-542-4129
Conference Access: Please request access to the Atlantic Power conference call.
Webcast: The call will be broadcast over Atlantic Power's website at www.atlanticpower.com.
Replay/Archive Information:
Replay: Access conference call number 10094170 at the following telephone numbers: U.S. (Toll Free) 1-877-344-7529; Canada (Toll Free) 1-855-669-9658; International (Toll) 1-412-317-0088. The replay will be available one hour after the end of the conference call through December 8, 2016 at 11:59 PM ET.
Webcast archive: The conference call will be archived on Atlantic Power's website at www.atlanticpower.com for a period of 12 months.
About Atlantic Power
Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. The Company's power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices. Atlantic Power's power generation projects in operation have an aggregate gross electric generation capacity of approximately 2,138 megawatts ("MW") in which its aggregate ownership interest is approximately 1,500 MW. The Company's current portfolio consists of interests in twenty-three operational power generation projects across nine states in the United States and two provinces in Canada.
Atlantic Power's shares trade on the New York Stock Exchange under the symbol AT and on the Toronto Stock Exchange under the symbol ATP. For more information, please visit the Company's website at www.atlanticpower.com or contact:
Atlantic Power Corporation
Investor Relations
(617) 977-2700
info@atlanticpower.com
Copies of the Company's financial data and other publicly filed documents are available on SEDAR at www.sedar.com or on EDGAR at www.sec.gov/edgar.shtml under "Atlantic Power Corporation" or on the Company's website.
************************************************************************************************************************
Cautionary Note Regarding Forward-Looking Statements
To the extent any statements made in this news release contain information that is not historical, these statements are forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended, and under Canadian securities law (collectively, "forward-looking statements").
Certain statements in this news release may constitute "forward-looking statements", which reflect the expectations of management regarding the future growth, results of operations, performance and business prospects and opportunities of the Company and its projects. These statements, which are based on certain assumptions and describe the Company's future plans, strategies and expectations, can generally be identified by the use of the words "may," "will," "project," "continue," "believe," "intend," "anticipate," "expect" or similar expressions that are predictions of or indicate future events or trends and which do not relate solely to present or historical matters. Examples of such statements in this press release include, but are not limited, to statements with respect to the following:
The Company's expectation that its leverage ratio will decline from 5.8 times currently to 5.6 times by year end 2016;
the Company's expectation that it will improve its leverage ratio of 5.8 times currently by more than a turn by year end 2017;
the Company's belief that the average repurchase price of $2.44 per share represents a compelling discount to the Company's estimate of intrinsic value;
the Company's estimate of discretionary cash (approximately $60 million) and its ability to allocate that cash to the highest-return uses;
the Company's estimate that it will amortize more than $400 million of term loan and project debt over the next four years;
the Company's estimate that overhead costs will total approximately $24 million in 2016, down from the previous expectation of approximately $27 million;
the Company's plan to seek further cost reductions in 2017, with a focus on plant operating costs;
the Company's estimates of factors affecting its goodwill impairment analysis;
the Company's views that it will remediate the material weakness in its financial controls (with respect to impairment) by the time it files its 2016 report on Form 10-K;
the Company's expectation that it will repay $15 million of term loan debt and $2.9 million of project debt in the fourth quarter of 2016;
the Company's views of its debt maturity profile;
the Company's expectation that discretionary optimization investments in its fleet will be approximately $3.5 million in 2016, and that the majority of those investments will be made at the Morris and Curtis Palmer projects;
the timing of the completion of upgrades at the Morris and Curtis Palmer projects;
the Company's expectation that it will realize a cash flow benefit of approximately $8 million in 2016 from discretionary investments made in 2013 through 2016 totaling approximately $25 million;
the Company's expectation that in 2016, capital expenditures will total approximately $8 million and maintenance expense will total approximately $47 million;
timing of capital expenditures for a new fuel shredder at Williams Lake and the timing and probability of resolution of the appeal of an amended air permit and contract extension with BC Hydro;
the Company's estimation that 2016 Project Adjusted EBITDA will be in the range of $205 to $215 million; and
the results of operations and performance of the Company's projects, business prospects, opportunities and future growth of the Company will be as described herein.
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. Please refer to the factors discussed under "Risk Factors" and "Forward-Looking Information" in the Company's periodic reports as filed with the Securities and Exchange Commission from time to time for a detailed discussion of the risks and uncertainties affecting the Company, including, without limitation, the outcome or impact of the Company's business plan, including the objective of enhancing the value of its existing assets through optimization investments and commercial activities, delevering its balance sheet to improve its cost of capital and ability to compete for new investments, and utilizing its core competencies to create proprietary investment opportunities, and the Company's ability to raise additional capital for growth and/or debt reduction, and the outcome or impact on the Company's business of any such actions. Although the forward-looking statements contained in this news release 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. These forward-looking statements are made as of the date of this news release and, except as expressly required by applicable law, the Company assumes no obligation to update or revise them to reflect new events or circumstances. The Company's ability to achieve its longer-term goals, including those described in this news release, is based on significant assumptions relating to and including, among other things, the general conditions of the markets in which it operates, revenues, internal and external growth opportunities, its ability to sell assets at favorable prices or at all and general financial market and interest rate conditions. The Company's actual results may differ, possibly materially and adversely, from these goals.
Table 7 – Consolidated Balance Sheet (in millions of U.S. dollars)
(Unaudited)
September 30,
December 31,
2016
2015
Assets
Current assets:
Cash and cash equivalents
$93.8
$72.4
Restricted cash
12.6
15.2
Accounts receivable
39.5
39.6
Inventory
1.6
-
Prepayments and other current assets
15.9
16.9
Assets held for sale
10.1
8.3
Other current assets
2.5
4.5
Total current assets
176.0
156.9
Property, plant and equipment, net
749.8
777.7
Equity investments in unconsolidated affiliates
277.6
286.2
Power purchase agreements and intangible assets, net
273.0
308.9
Goodwill
37.6
134.5
Derivative instruments asset
1.3
0.3
Deferred income tax
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
101.4
15.8
Current portion of derivative instruments liability
15.2
36.7
Other current liabilities
4.1
2.5
Total current liabilities
159.6
88.9
Long-term debt
778.9
682.7
Convertible debentures
101.4
277.7
Derivative instruments liability
27.3
20.8
Deferred income taxes
69.8
85.7
Power purchase and fuel supply agreement liabilities, net
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
1,278.1
1,290.6
Accumulated other comprehensive loss
(142.0)
(139.3)
Retained deficit
(1,053.6)
(937.4)
Total Atlantic Power Corporation shareholders' equity
82.5
213.9
Preferred shares issued by a subsidiary company
221.3
221.3
Total equity
303.8
435.2
Total liabilities and equity
$1,521.9
$1,671.2
Atlantic Power Corporation
Table 8 – 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 (expense):
Change in fair value of derivative instruments
9.0
3.6
20.0
8.7
Equity in earnings of unconsolidated affiliates
9.6
8.9
27.9
28.3
Interest, net
(2.4)
(2.1)
(6.9)
(6.2)
Impairment
(84.7)
-
(84.7)
-
Other income, net
0.5
-
0.4
2.2
(68.0)
10.4
(43.3)
33.0
Project 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 loss (gain)
(3.4)
(21.7)
19.1
(49.1)
Other income, net
(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 (benefit) expense
2.6
1.4
(14.2)
(0.3)
(Loss) income from continuing operations
(80.3)
(3.4)
(109.8)
1.2
Net income from discontinued operations, net of tax (1)
-
(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 share 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 earnings per share:
(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:
Basic
119.3
122.1
120.9
121.8
Diluted
119.3
122.2
120.9
121.9
Dividends paid per common share:
$-
$0.02
$-
$0.07
(1) Includes contributions from the Wind Projects, which are components of discontinued operations.
Atlantic Power Corporation
Table 9 – 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 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 assets 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 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 construction cost
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)
Net increase 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
Non-GAAP Disclosures
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. Investors are cautioned that the Company may calculate this non-GAAP measure in a manner that is different from other companies. The most directly comparable GAAP measure is Project income (loss). Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in the fair value of derivative instruments. Management uses Project Adjusted EBITDA at the project level to provide comparative information about project performance and believes such information is helpful to investors. A reconciliation of Project Adjusted EBITDA to Project income (loss) and to Net income (loss) by segment and on a consolidated basis is provided in Tables 10A through 10D on pages 16 and 17 of this news release.
Cash Distributions from Projects is the amount of cash distributed by the projects to the Company out of available project cash flow after all project-level operating costs, interest payments, principal repayment, capital expenditures and working capital requirements. It is not a non-GAAP measure. Project Adjusted EBITDA, a non-GAAP measure, is the most comparable measure, but it is before debt service, capital expenditures and working capital requirements. The Company has provided a bridge of Project Adjusted EBITDA to Cash Distributions from Projects in Tables 11A through 11D on pages 18 and 19 of this release.
Table 12 (page 20) presents Project income (loss) by project for selected projects for the three and nine months ended September 30, 2016 and the comparable periods in 2015. Table 13 (page 21) presents Project Adjusted EBITDA by project for the same projects as shown in Table 12 for the three and nine months ended September 30, 2016 and the comparable periods in 2015. Table 13 also provides a reconciliation of Project Adjusted EBITDA to Net Income (loss) for the three- and nine-month periods ended September 30, 2016 and September 30, 2015.
Atlantic Power Corporation
Table 10A – Reconciliation of Net income (loss) to Project Adjusted EBITDA by Segment and Consolidated (in millions of U.S. dollars)
Three Months Ended September 30, 2016
Unaudited
East
West
Canada
Un-alloc.
Corp
Consol.
Net (loss) income attributable to Atlantic Power Corporation
($8.6)
$11.4
($62.4)
($22.8)
($82.4)
Net income attributable to preferred share dividends of a subsidiary company
-
-
-
2.1
2.1
Net (loss) attributable to noncontrolling interests
-
-
-
-
-
Net (loss) income
(8.6)
11.4
(62.4)
(20.7)
(80.3)
Net income from discontinued operations, net of tax
-
-
-
-
-
Net income (loss) from continuing operations
(8.6)
11.4
(62.4)
(20.7)
(80.3)
Income tax (benefit) expense
-
-
-
2.6
2.6
Income (loss) from continuing operations before income taxes
(8.6)
11.4
(62.4)
(18.1)
(77.7)
Administration
-
-
-
5.7
5.7
Interest, net
-
-
-
20.0
20.0
Foreign exchange loss (gain)
-
-
-
(3.4)
(3.4)
Other income, net
-
-
-
(1.7)
(1.7)
Project income (loss)
(8.6)
11.4
(62.4)
2.5
(57.1)
Change in fair value of derivative instruments
(1.2)
-
(5.6)
(2.2)
(9.0)
Depreciation and amortization
11.0
9.9
9.4
0.1
30.4
Interest, net
2.8
-
-
-
2.8
Impairment
15.4
-
69.3
-
84.7
Other project expense
-
-
-
(0.5)
(0.5)
Project Adjusted EBITDA
$19.4
$21.3
$10.7
($0.1)
$51.3
Atlantic Power Corporation
Table 10B – Reconciliation of Net income (loss) to Project Adjusted EBITDA by Segment and Consolidated (in millions of U.S. dollars)
Three Months Ended September 30, 2015
Unaudited
East
West
Canada
Un-alloc.
Corp
Consol.
Net (loss) income attributable to Atlantic Power Corporation
$12.4
$11.5
$1.9
($31.8)
($6.0)
Net income attributable to preferred share dividends of a subsidiary company
-
-
-
2.1
2.1
Net (loss) attributable to noncontrolling interests
-
-
-
-
-
Net (loss) income
12.4
11.5
1.9
(29.7)
(3.9)
Net income from discontinued operations, net of tax
-
-
-
0.5
0.5
Net income (loss) from continuing operations
12.4
11.5
1.9
(29.2)
(3.4)
Income tax (benefit) expense
-
-
-
1.4
1.4
Income (loss) from continuing operations before income taxes
12.4
11.5
1.9
(27.8)
(2.0)
Administration
-
-
-
6.9
6.9
Interest, net
-
-
-
41.0
41.0
Foreign exchange loss (gain)
-
-
-
(21.7)
(21.7)
Other income, net
-
-
-
-
-
Project income (loss)
12.4
11.5
1.9
(1.6)
24.2
Change in fair value of derivative instruments
1.9
-
(6.1)
0.6
(3.6)
Depreciation and amortization
10.7
9.9
11.7
0.5
32.8
Interest, net
2.4
-
0.1
-
2.5
Other project expense
-
-
-
0.1
0.1
Project Adjusted EBITDA
$27.4
$21.4
$7.6
($0.4)
$56.0
Atlantic Power Corporation
Table 10C – Reconciliation of Net income (loss) to Project Adjusted EBITDA by Segment and Consolidated (in millions of U.S. dollars)
Nine Months Ended September 30, 2016
Unaudited
East
West
Canada
Un-alloc.
Corp
Consol.
Net (loss) income attributable to Atlantic Power Corporation
$16.9
$13.8
($33.1)
($113.8)
($116.2)
Net income attributable to preferred share dividends of a subsidiary company
-
-
-
6.4
6.4
Net (loss) attributable to noncontrolling interests
-
-
-
-
-
Net (loss) income
16.9
13.8
(33.1)
(107.4)
(109.8)
Net income from discontinued operations, net of tax
-
-
-
-
-
Net income (loss) from continuing operations
16.9
13.8
(33.1)
(107.4)
(109.8)
Income tax (benefit) expense
-
-
-
(14.2)
(14.2)
Income (loss) from continuing operations before income taxes
16.9
13.8
(33.1)
(121.6)
(124.0)
Administration
-
-
-
17.6
17.6
Interest, net
-
-
-
87.9
87.9
Foreign exchange loss (gain)
-
-
-
19.1
19.1
Other income, net
-
-
-
(3.9)
(3.9)
Project income (loss)
16.9
13.8
(33.1)
(0.9)
(3.3)
Change in fair value of derivative instruments
(3.0)
-
(17.7)
0.6
(20.1)
Depreciation and amortization
33.0
29.6
27.7
0.5
90.8
Interest, net
8.2
-
-
-
8.2
Impairment
15.4
-
69.3
-
84.7
Other project expense
-
-
-
(0.4)
(0.4)
Project Adjusted EBITDA
$70.5
$43.4
$46.2
($0.2)
$159.9
Atlantic Power Corporation
Table 10D – Reconciliation of Net income (loss) to Project Adjusted EBITDA by Segment and Consolidated (in millions of U.S. dollars)
Nine Months Ended September 30, 2015
Unaudited
East
West
Canada
Un-alloc.
Corp
Consol.
Net (loss) income attributable to Atlantic Power Corporation
$40.0
$7.3
$17.9
($39.1)
$26.1
Net income attributable to preferred share dividends of a subsidiary company
-
-
-
6.7
6.7
Net (loss) attributable to noncontrolling interests
-
-
-
(11.0)
(11.0)
Net (loss) income
40.0
7.3
17.9
(43.4)
21.8
Net income from discontinued operations, net of tax
-
-
-
(20.6)
(20.6)
Net income (loss) from continuing operations
40.0
7.3
17.9
(64.0)
1.2
Income tax (benefit) expense
-
-
-
(0.3)
(0.3)
Income (loss) from continuing operations before income taxes
40.0
7.3
17.9
(64.3)
0.9
Administration
-
-
-
23.0
23.0
Interest, net
-
-
-
91.3
91.3
Foreign exchange loss (gain)
-
-
-
(49.1)
(49.1)
Other income, net
-
-
-
(3.1)
(3.1)
Project income (loss)
40.0
7.3
17.9
(2.2)
63.0
Change in fair value of derivative instruments
1.6
-
(11.6)
1.3
(8.7)
Depreciation and amortization
31.8
29.7
36.5
0.9
98.9
Interest, net
7.6
-
0.1
-
7.7
Other project expense
-
0.1
0.1
(2.6)
(2.4)
Project Adjusted EBITDA
$81.0
$37.1
$43.0
($2.6)
$158.5
Atlantic Power Corporation
Table 11A – Cash Distributions from Projects (by Segment, in millions of U.S. dollars)
Three months ended September 30, 2016
Unaudited
Segment
Project
Adjusted
EBITDA
Repayment
of long-
term debt
Interest
expense,
net
Capital
expenditures
Other, including
changes in
working capital
Cash
Distributions
from Projects
East U.S.
Consolidated
$8.2
($3.7)
($2.0)
($3.6)
$2.8
$1.7
Equity method
11.2
-
(0.4)
(0.1)
2.8
13.5
Total
19.4
(3.7)
(2.4)
(3.7)
5.6
15.2
West U.S.
Consolidated
18.1
-
-
-
(2.2)
15.9
Equity method
3.2
-
-
-
0.8
4.0
Total
21.3
-
-
-
(1.4)
19.9
Canada
Consolidated
10.7
(0.0)
(0.0)
(0.2)
4.9
15.4
Equity method
-
-
-
-
-
-
Total
10.7
(0.0)
(0.0)
(0.2)
4.9
15.4
Total consolidated
37.0
(3.7)
(2.0)
(3.7)
5.4
33.0
Total equity method
14.4
-
(0.4)
(0.1)
3.6
17.5
Un-allocated
corporate
(0.1)
-
-
(0.0)
0.1
(0.1)
Total
$51.3
($3.7)
($2.4)
($3.9)
$9.1
$50.4
Atlantic Power Corporation
Table 11B – Cash Distributions from Projects (by Segment, in millions of U.S. dollars)
Three months ended September 30, 2015
Unaudited
Segment
Project
Adjusted
EBITDA
Repayment
of long-
term debt
Interest
expense,
net
Capital
expenditures
Other, including
changes in
working capital
Cash
Distributions
from Projects
East U.S.
Consolidated
$17.8
($4.3)
($1.7)
($3.2)
($1.6)
$7.0
Equity method
9.6
-
(0.5)
(0.1)
5.1
14.1
Total
27.4
(4.3)
(2.1)
(3.3)
3.4
21.1
West U.S.
Consolidated
18.1
-
-
(0.6)
(3.3)
14.2
Equity method
3.3
-
-
-
0.7
4.0
Total
21.4
-
-
(0.6)
(2.6)
18.2
Canada
Consolidated
7.6
(0.1)
(0.0)
(1.6)
6.2
12.1
Equity method
-
-
-
-
-
-
Total
7.6
(0.1)
(0.0)
(1.6)
6.2
12.1
Total consolidated
43.5
(4.4)
(1.7)
(5.4)
1.3
33.3
Total equity method
12.9
-
(0.5)
(0.1)
5.8
18.1
Un-allocated corporate
(0.4)
-
-
0.3
0.2
0.1
Total
$56.0
($4.4)
($2.1)
($5.2)
$7.3
$51.5
Atlantic Power Corporation
Table 11C – Cash Distributions from Projects (by Segment, in millions of U.S. dollars)
Nine months ended September 30, 2016
Unaudited
Segment
Project
Adjusted
EBITDA
Repayment
of long-
term debt
Interest
expense,
net
Capital
expenditures
Other, including
changes in
working capital
Cash
Distributions
from Projects
East U.S.
Consolidated
$39.8
($7.9)
($5.4)
($0.7)
$2.2
$27.9
Equity method
30.8
-
(1.2)
(0.2)
(2.0)
27.4
Total
70.5
(7.9)
(6.7)
(0.9)
0.3
55.3
West U.S.
Consolidated
33.8
-
-
0.0
(5.2)
28.7
Equity method
9.6
-
-
-
1.4
11.0
Total
43.4
-
-
0.0
(3.8)
39.6
Canada
Consolidated
46.2
(0.1)
(0.0)
(0.7)
0.3
45.7
Equity method
-
-
-
-
-
-
Total
46.2
(0.1)
(0.0)
(0.7)
0.3
45.7
Total consolidated
119.8
(8.0)
(5.5)
(1.4)
(2.6)
102.2
Total equity method
40.4
-
(1.2)
(0.2)
(0.6)
38.4
Un-allocated corporate
(0.2)
-
-
0.3
(0.0)
(0.0)
Total
$159.9
($8.0)
($6.7)
($1.4)
($3.3)
$140.6
Atlantic Power Corporation
Table 11D – Cash Distributions from Projects (by Segment, in millions of U.S. dollars)
Nine months ended September 30, 2015
Unaudited
Segment
Project
Adjusted
EBITDA
Repayment
of long-
term debt
Interest
expense,
net
Capital
expenditures
Other, including
changes in
working capital
Cash
Distributions
from Projects
East U.S.
Consolidated
$50.4
($10.6)
($5.0)
($7.2)
($1.8)
$25.7
Equity method
30.6
-
(1.4)
(0.2)
3.6
32.7
Total
81.0
(10.6)
(6.4)
(7.4)
1.8
58.4
West U.S.
Consolidated
27.3
-
-
(0.6)
(4.0)
22.7
Equity method
9.7
-
-
-
0.9
10.6
Total
37.1
-
-
(0.6)
(3.2)
33.3
Canada
Consolidated
43.0
(0.2)
(0.0)
(2.5)
6.9
47.2
Equity method
-
-
-
-
-
-
Total
43.0
(0.2)
(0.0)
(2.5)
6.9
47.2
Total consolidated
120.8
(10.8)
(5.1)
(10.4)
1.0
95.6
Total equity method
40.3
-
(1.4)
(0.2)
4.5
43.2
Un-allocated corporate
(2.6)
-
-
0.2
2.3
(0.1)
Total
$158.5
($10.8)
($6.5)
($10.3)
$7.8
$138.8
Atlantic Power Corporation
Table 12 – Project Income by Project (for Selected Projects)
(in millions of U.S. dollars)
Unaudited
Three months ended
September 30,
Nine months ended
September 30,
Segment / Project
Accounting
2016
2015
2016
2015
East U.S.
Cadillac
Consolidated
$0.9
$0.2
$2.5
$1.8
Curtis Palmer
Consolidated
(16.0)
1.4
(6.3)
9.2
Morris
Consolidated
(5.1)
3.6
(0.7)
10.4
Piedmont
Consolidated
3.0
0.5
(5.4)
(4.3)
Kenilworth
Consolidated
0.3
0.1
(0.7)
0.5
Chambers
Equity method
1.4
1.4
4.6
5.2
Orlando
Equity method
6.4
5.0
23.0
16.9
Selkirk
Equity method
0.5
0.2
(0.1)
0.3
Total
(8.6)
12.4
16.9
40.0
West U.S.
Manchief
Consolidated
0.6
1.0
1.6
(5.9)
Naval Station
Consolidated
3.0
2.7
3.5
4.1
North Island
Consolidated
2.3
2.3
3.6
3.7
Naval Training Center
Consolidated
1.4
1.4
1.8
1.9
Oxnard
Consolidated
3.4
3.4
1.4
1.5
Frederickson
Equity method
0.9
0.7
1.4
1.8
Koma Kulshan
Equity method
(0.2)
-
0.5
0.2
Total
11.4
11.5
13.8
7.3
Canada
Calstock
Consolidated
0.7
1.7
4.7
5.3
Kapuskasing
Consolidated
(6.5)
0.5
(0.6)
5.2
Mamquam
Consolidated
(50.1)
(1.3)
(44.2)
1.5
Nipigon
Consolidated
0.4
1.6
4.5
3.6
North Bay
Consolidated
(9.0)
(0.3)
(2.3)
4.7
Williams Lake
Consolidated
2.8
0.4
5.6
(1.6)
Other (Tunis and Moresby Lake)
Consolidated
(0.7)
(0.7)
(0.8)
(0.8)
Total
(62.4)
1.9
(33.1)
17.9
Totals
Consolidated projects
(68.6)
18.5
(31.8)
40.8
Equity method projects
9.0
7.3
29.4
24.4
Un-allocated corporate
2.5
(1.6)
(0.9)
(2.2)
Total Project Income
($57.1)
$24.2
($3.3)
$63.0
Atlantic Power Corporation
Table 13 – Project Adjusted EBITDA by Project (for Selected Projects) (in millions of U.S. dollars), Unaudited
Three months ended
September 30,
Nine months ended
September 30,
Segment / Project
Accounting
2016
2015
2016
2015
East U.S.
Cadillac
Consolidated
$2.3
$1.6
$6.7
$6.1
Curtis Palmer
Consolidated
3.3
5.4
20.7
20.9
Morris
Consolidated
(4.0)
4.5
3.9
13.3
Piedmont
Consolidated
5.7
5.6
7.3
7.8
Kenilworth
Consolidated
0.9
0.8
1.2
2.4
Chambers
Equity method
4.1
4.0
13.0
13.6
Orlando
Equity method
6.6
5.4
17.8
16.7
Selkirk
Equity method
0.5
0.2
(0.1)
0.3
Total
19.4
27.4
70.5
81.0
West U.S.
Manchief
Consolidated
3.4
3.8
10.0
2.4
Naval Station
Consolidated
4.6
4.3
8.3
8.9
North Island
Consolidated
3.4
3.3
6.8
7.0
Naval Training Center
Consolidated
2.2
2.2
4.2
4.3
Oxnard
Consolidated
4.5
4.5
4.6
4.8
Frederickson
Equity method
3.3
3.2
8.8
9.2
Koma Kulshan
Equity method
(0.1)
0.1
0.8
0.5
Total
21.3
21.4
43.4
37.1
Canada
Calstock
Consolidated
1.1
2.3
6.2
7.0
Kapuskasing
Consolidated
1.0
(0.3)
4.1
4.1
Mamquam
Consolidated
0.6
(0.9)
7.2
2.7
Nipigon
Consolidated
3.6
3.3
13.2
13.2
North Bay
Consolidated
(0.2)
(1.2)
3.7
3.6
Williams Lake
Consolidated
5.0
4.9
11.9
12.5
Other (Tunis and Moresby Lake)
Consolidated
(0.4)
(0.5)
(0.1)
(0.1)
Total
10.7
7.6
46.2
43.0
Totals
Consolidated projects
37.0
43.5
119.8
120.8
Equity method projects
14.4
12.9
40.4
40.3
Un-allocated corporate
(0.1)
(0.4)
(0.2)
(2.6)
Total Project Adjusted EBITDA
$51.3
$56.0
$159.9
$158.5
Other project expense
($0.5)
$0.1
($0.4)
($2.4)
Impairment
84.7
-
84.7
-
Interest, net
2.8
2.5
8.2
7.7
Depreciation and amortization
30.4
32.8
90.8
98.9
Change in fair value of derivative instruments
(9.0)
(3.6)
(20.1)
(8.7)
Project income
($57.1)
$24.2
($3.3)
$63.0
Other income, net
(1.7)
-
(3.9)
(3.1)
Foreign exchange loss (gain)
(3.4)
(21.7)
19.1
(49.1)
Interest, net
20.0
41.0
87.9
91.3
Administration
5.7
6.9
17.6
23.0
(Loss) from continuing operations before income taxes
(77.7)
(2.0)
(124.0)
0.9
Income tax (benefit) expense
2.6
1.4
(14.2)
(0.3)
Net (loss) income from continuing operations
(80.3)
(3.4)
(109.8)
1.2
Net income from discontinued operations, net of tax
-
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 share 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
To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/atlantic-power-corporation-releases-third-quarter-2016-results-and-narrows-2016-guidance-range-300358711.html
SOURCE Atlantic Power Corporation
Copyright 2016 Canada NewsWire
Easy1
9 years ago
Atlantic Power Corporation Releases Fourth Quarter and Year End 2015 Results
Source: PR Newswire (Canada)
DEDHAM, Mass., March 7, 2016 /CNW/ – Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the "Company") today released its results for the three and twelve months ended December 31, 2015.
Progress on Key Initiatives
Reduced debt by a total of $833 million in the past two years as a result of asset sales, debt amortization and discretionary debt repurchases; lowered annual interest expense by more than $65 million
Reduced overhead costs from $54 million in 2013 to $32 million in 2015; expect further reduction to $27 million in 2016 (cumulative expected reduction of 50% from 2013)
Invested a total of $22 million in attractive optimization projects from 2013 to 2015; realized cash flow benefit of approximately $6 million in 2015; expect $10 million benefit in 2016
In December, announced modification of the Morris energy services agreement and 11-year extension to December 2034; changes expected to be modestly accretive to Project Adjusted EBITDA
Recent Developments
Implemented normal course issuer bid (NCIB) for up to 10% of each of the Company's convertible debentures and common shares and up to 5% of Atlantic Power Preferred Equity Ltd.'s preferred shares, subject to limitations described in the Company's December 22, 2015 press release
Shareholder litigation in United States and Ontario dismissed without payments by the Company (December 2015); proposed action in Quebec expected to be resolved in a similar manner
In February 2016, Standard & Poor's upgraded the Company's corporate credit rating to B+ from B; Moody's had upgraded to B1 from B2 in October 2015; both agencies have "stable" outlooks for the credit
Common dividend eliminated as part of changes to overall capital allocation strategy (February 2016)
Management and directors purchased approximately 493,000 shares in Q4 2015 at an average price of US$1.77 per share; for the year, management and director purchases totaled approximately 1.05 million shares at an average price of US$2.31
Full Year 2015 Financial Results
Reported project loss of $(41) million vs. project loss of $(39) million in 2014; 2015 results include $128 million impairment of long-lived assets and goodwill (results for both years exclude the Wind Projects, which are included in discontinued operations)
Achieved Project Adjusted EBITDA of $209 million vs. $229 million in 2014, in the upper half of the Company's 2015 guidance range of $200 to $215 million (results exclude Wind Projects)
Reported (GAAP) Cash flows provided by operating activities of $87 million vs. $65 million in 2014 (results include cash flows from the Wind Projects)
Generated Adjusted Cash Flows from Operating Activities of $105 million vs. $92 million in 2014, at the upper end of the Company's 2015 guidance range of $95 to $105 million (results exclude Wind Projects and debt redemption costs)
Achieved Adjusted Free Cash Flow of $2 million vs. approximately zero in 2014, in the lower end of the Company's 2015 guidance range of $0 to $10 million because of a delay in a $6 million reimbursement for a customer-owned construction project that was received in February 2016 (results exclude Wind Projects and debt redemption costs)
Q4 2015 Financial Results
Recorded $128 million non-cash impairment of long-lived assets and goodwill, primarily at Williams Lake
Project loss of $(104) million vs. project income of $2 million in Q4 2014; loss for the fourth quarter of 2015 is attributable to the $128 million impairment charge (results for both years exclude the Wind Projects)
Project Adjusted EBITDA of $50 million vs. $57 million in Q4 2014 (results exclude Wind Projects)
Reported (GAAP) Cash flows provided by operating activities of $20 million vs. $19 million in Q4 2014 (results include Wind Projects)
Adjusted Cash flows from Operating Activities of $29 million vs. $18 million in Q4 2014 (excludes Wind)
Adjusted Free Cash Flow of $9 million vs. $(1) million in Q4 2014 (results exclude Wind projects)
2016 Guidance
Project Adjusted EBITDA of $200 to $220 million
Atlantic Power Limited Partnership (APLP) Project Adjusted EBITDA of $145 to $155 million
Adjusted Cash Flows from Operating Activities of $110 to $130 million
Adjusted Free Cash Flow of $20 to $40 million
"In 2015, we made further progress in strengthening our financial position and reducing our risk profile. Over the past two years, we have reduced our debt by $833 million, lowered our cash interest and overhead costs by approximately half, and improved our debt maturity profile. In the past five months, our credit ratings have been upgraded by both Moody's and Standard & Poor's. In December, the proposed shareholder actions in both the United States and Ontario were dismissed by the courts without any payments by us," said James J. Moore, Jr., President & CEO of Atlantic Power.
Mr. Moore continued, "We had success on other fronts as well. Our projects performed well in 2015 and earned substantially all of their capacity payments. We achieved Project Adjusted EBITDA and cash flow in line with our guidance. We continued to make attractive investments in our own fleet, which are yielding cash returns of more than 20%. We announced an 11-year extension of our energy services agreement with the customer at our Morris project, and we continue to make progress on other contract extensions."
"Looking ahead, we remain focused on growing the intrinsic value per share of the Company. The amount of our discretionary cash flow after debt repayment is growing, and we see ample opportunities to put this to work at good returns. As we announced earlier this month, we have prioritized repurchases of our debt and equity, which are currently trading at compelling price-to-value levels. In addition, we see the potential for additional attractive investments in our fleet, some of which are linked to possible contract extensions," said Mr. Moore. "We believe that both these uses of cash have considerably higher risk-adjusted returns than those available externally at present. Although primarily focused on organic growth initiatives, management has considerable experience building other IPP businesses and will continue to evaluate potential external investments in a disciplined and opportunistic manner."
All amounts are in U.S. dollars and are approximate unless otherwise indicated. Adjusted Cash Flows from Operating Activities, Free Cash Flow, Adjusted Free Cash Flow, Cash Distributions from Projects, Project Adjusted EBITDA and APLP Project Adjusted EBITDA are not recognized measures under generally accepted accounting principles in the United States ("GAAP") and do not have standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies. Please see "Regulation G Disclosures" on page 18 of this news release for an explanation and the GAAP reconciliation of "Adjusted Cash Flows from Operating Activities", "Free Cash Flow", "Adjusted Free Cash Flow", "Cash Distributions from Projects" and "Project Adjusted EBITDA" as used in this news release. The Company has not reconciled non-GAAP financial measures relating to individual projects or the projects in discontinued operations or the APLP projects to the directly comparable GAAP measures due to the difficulty in making the relevant adjustments on an individual project basis. The Company has not provided a reconciliation of forward-looking non-GAAP measures, due primarily to variability and difficulty in making accurate forecasts and projections, as not all of the information necessary for a quantitative reconciliation is available to the Company without unreasonable efforts.
Atlantic Power Corporation
Table 1 – Selected Results
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
Three months ended December 31
Twelve months ended December 31
2015
2014
2015
2014
Excluding results from discontinued operations(1)
Project revenue
$98.4
$119.9
$420.2
$489.9
Project income (loss)
(104.3)
2.1
(41.4)
(38.9)
Project Adjusted EBITDA
50.4
56.9
208.9
229.4
Cash Distributions from Projects
46.0
57.6
192.3
209.1
Adjusted Cash Flows from Operating Activities
29.3
17.9
105.3
92.4
Adjusted Free Cash Flow
9.2
(1.4)
1.8
(0.3)
Aggregate power generation (thousands of Net MWh)
1,646.4
1,592.1
6,353.3
6,398.9
Weighted average availability
96.0%
93.6%
95.2%
93.0%
Including results from discontinued operations (1)
Cash flows from operating activities
$19.7
$19.1
$87.4
$65.0
Free Cash Flow
(0.4)
(7.2)
(19.8)
(55.6)
Results of discontinued operations
Project Adjusted EBITDA
$-
$20.7
$28.1
$69.8
Cash Distributions from Projects
-
4.8
7.3
39.4
Cash flows from operating activities (as reported)
-
11.3
21.9
48.3
Cash flows from operating activities (as adjusted) (2)
(5.0)
11.3
15.7
48.3
(1) Canadian Hills, Meadow Creek, Goshen North, Idaho Wind and Rockland (the "Wind Projects") were sold in June 2015 and are designated as discontinued operations for the twelve months ended December 31, 2015 and 2014. Greeley was sold in March 2014 and is included as a component of discontinued operations for the twelve months ended December 31, 2014. The results of discontinued operations are excluded from Project revenue, Project income, Project Adjusted EBITDA, Cash Distributions from Projects, Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow as presented in Table 1. The results for discontinued operations have also been excluded from the aggregate power generation and weighted average availability statistics shown in Table 1. Under GAAP, the cash flows attributable to the Wind Projects and Greeley are included in cash flows from operating activities as shown on the Company's Consolidated Statement of Cash Flows; therefore, the Company's calculation of Free Cash Flow shown on Table 1 also includes cash flows from the Wind Projects and Greeley. However, the inclusion of Greeley in 2014 had no impact on cash flows from operating activities or Free Cash Flow. Results of discontinued operations shown above are for the Wind Projects, as Greeley had no impact on Project Adjusted EBITDA, Cash Distributions from Projects or cash flows from operating activities for the 2014 period in which it was included in discontinued operations.
(2) Adjusted for cash tax payments associated with the sale of the Wind Projects of $5.0M in the fourth quarter of 2015 and $6.3M for the Full Year 2015.
Note: Project Adjusted EBITDA, Cash Distributions from Projects, Adjusted Cash Flows from Operating Activities, Adjusted Free Cash Flow and Free Cash Flow are not recognized measures under GAAP and do not have any standardized meaning prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies. Please refer to Tables 8 and 10 through 12 for reconciliations of these non-GAAP measures to GAAP measures.
Operating Results
The discussion of operating results excludes the Wind Projects, which were sold in June 2015 and are included in discontinued operations.
Three Months Ended December 31, 2015
Project availability was 96.0% in the fourth quarter of 2015, an increase from 93.6% in the year-ago period. Increased availability at Koma Kulshan and Selkirk, both of which had maintenance outages in the comparable 2014 period, was partially offset by lower availability at Mamquam, which had a scheduled maintenance outage that extended into the fourth quarter of 2015. (The 2015 availability figure excludes Tunis, which has been mothballed since February 2015 following the expiration of its Power Purchase Agreement, or PPA, in December 2014.)
Generation increased 3.4% in the fourth quarter of 2015 from the year-ago period, primarily due to Frederickson, which had increased dispatch due to stronger demand and lower fuel gas pricing as compared to 2014; Selkirk, which had a hedging agreement in place for November 2015; Morris, which experienced favorable PJM pricing as well as higher merchant demand in the fourth quarter of 2015, and Naval Station, due to a forced outage in the year-ago period. These increases were partially offset by decreases at Tunis, due to the expiration of its PPA; Manchief, due to reduced dispatch, and Mamquam, which had a scheduled maintenance outage that extended into the fourth quarter of 2015.
Twelve Months Ended December 31, 2015
Project availability increased to 95.2% in 2015 from 93.0% in 2014. Increased availability at Nipigon, Piedmont, Cadillac and Orlando, all of which had maintenance outages in 2014, more than offset decreased availability at Mamquam, Manchief and Naval Training Center, which had scheduled maintenance outages in 2015. (The 2015 availability figure excludes Tunis.)
Generation decreased by 0.7% in 2015 from 2014, primarily due to a PPA expiration at Tunis (December 2014); lower dispatch at Manchief (demand), Chambers (unfavorable pricing), Mamquam (scheduled maintenance outage and lower water flows), and Curtis Palmer (lower water flows). These decreases were partially offset by an increase at Frederickson due to higher dispatch and increases at Nipigon (outage in 2014 and waste heat), Calstock (waste heat) and Morris (favorable PJM pricing/increased merchant demand).
Financial Results
In the second quarter of 2015, the Company revised its reportable business segments as a result of recent significant asset sales and in order to align with changes in management's structure, resource allocation and performance assessment in making decisions regarding the Company's operations. Results of the Company's businesses are now reported in four segments: East U.S., West U.S., Canada and Un-allocated Corporate.
Table 2 provides a breakdown of project income and Project Adjusted EBITDA by segment for the three and twelve months ended December 31, 2015 as compared to the same periods in 2014. The Company's Wind Projects were sold in June 2015 and are included in results of discontinued operations for the three and twelve-month periods ended December 31, 2015 and 2014. Greeley was sold in March 2014 and is included as a component of discontinued operations for the twelve months ended December 31, 2014. Results for project income and Project Adjusted EBITDA exclude discontinued operations. Accordingly, results of the Wind Projects and Greeley are not included in Project income or Project Adjusted EBITDA for either the 2015 or 2014 periods shown in Table 2.
Atlantic Power Corporation
Table 2 – Segment Results
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
Three months ended December 31
Twelve months ended December 31
2015
2014
2015
2014
Project income (loss)
East U.S.
$12.4
$3.9
$52.4
$8.7
West U.S.
0.3
(0.5)
7.6
(27.6)
Canada
(117.3)
1.3
(99.4)
(10.5)
Un-allocated Corporate
0.3
(2.6)
(2.0)
(9.5)
Total
(104.3)
2.1
(41.4)
(38.9)
Project Adjusted EBITDA
East U.S.
$23.8
$24.1
$104.8
$106.4
West U.S.
9.8
9.4
46.9
54.2
Canada
16.7
24.7
59.7
76.3
Un-allocated Corporate
0.1
(1.3)
(2.5)
(7.5)
Total
50.4
56.9
208.9
229.4
The results of the Wind Projects and Greeley, which are components of discontinued operations, are excluded from Project income and Project Adjusted EBITDA as presented in Table 2.
Note: Project Adjusted EBITDA is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP; therefore, this measure may not be comparable to similar measures presented by other companies. Please refer to Tables 8 and 10 through 12 for a reconciliation of this non-GAAP measure to a GAAP measure. The Company has not reconciled this non-GAAP financial measure relating to individual project segments to the directly comparable GAAP measure due to the difficulty in making the relevant adjustments on a segment basis.
Three Months Ended December 31, 2015
Project income (loss) can fluctuate significantly due to non-cash adjustments to "mark-to-market" the fair value of derivatives. Non-cash goodwill impairment charges and gains or losses on the sale of assets are included in project income and can also affect year-over-year comparisons. None of these items are included in Project Adjusted EBITDA.
In the fourth quarter of 2015, the Company reported a project loss of $(104.3) million as compared to project income of $2.1 million in the year-ago period. Results for the fourth quarter of 2015 included a non-cash impairment charge of $127.8 million. Included in this charge were impairments of property, plant and equipment at Williams Lake and Calstock of $74.1 million and $2.5 million, respectively. The Company also recorded full impairments of the remaining goodwill at Williams Lake and Calstock of $35.6 million and $1.9 million, respectively, and a partial goodwill impairment of $13.7 million at Curtis Palmer. No impairment charges were recorded in the fourth quarter of 2014. Results for the fourth quarter of 2015 also included a $23.2 million mark-to-market increase in the fair value of derivatives as compared to the fourth quarter of 2014.
Project Adjusted EBITDA includes the proportional share of Project Adjusted EBITDA from the Company's equity method projects. Project Adjusted EBITDA is a non-GAAP measure. Table 8 of this press release provides a reconciliation of Project Adjusted EBITDA to Project income.
Project Adjusted EBITDA decreased $6.5 million to $50.4 million in the fourth quarter of 2015 from $56.9 million in the fourth quarter of 2014. The most significant drivers of lower EBITDA were the Tunis PPA expiration, lower water flows at Mamquam, lower excess energy margins at Chambers and lower electric revenue at Williams Lake. These factors were partially offset by higher Project Adjusted EBITDA at Curtis Palmer, which benefited from higher water flows, and Selkirk, which realized lower fuel costs. In addition, the Un-allocated Corporate segment improved by $1.4 million in the fourth quarter of 2015 from the year-ago period, primarily due to $1.2 million of lower project-level compensation expense. Currency had an approximate $(3.0) million impact on Project Adjusted EBITDA, with an average U.S. dollar to Canadian dollar exchange rate for the fourth quarter of 2015 of 1.34 versus 1.14 for the year-ago period. However, from an overall cash standpoint, that impact was mostly offset by the benefit of the stronger U.S. dollar on the Company's Canadian-denominated interest and dividend payments.
Corporate-level G&A expense (shown as "Administration" on the Consolidated Statements of Operations) decreased $4.8 million to $6.4 million in the fourth quarter of 2015 from $11.2 million a year ago. The improvement was due primarily to a $1.4 million decrease in legal expenses associated with the U.S. and Canadian shareholder actions, $0.6 million of reduced employee compensation expenses and $0.5 million of lower business development expenses. The 2014 figure also included $0.5 million of certain fees that were not incurred in 2015.
Cash Flow Metrics
Cash flows from operating activities (GAAP) and Free Cash Flow include the cash flows from projects classified as discontinued operations. Free Cash Flow is a non-GAAP measure. Table 10 of this press release provides a reconciliation of Free Cash Flow to cash flows from operating activities.
Cash flows provided by operating activities of $19.7 million in the fourth quarter of 2015 increased $0.6 million from $19.1 million in the fourth quarter of 2014. The increase was primarily attributable to significantly lower interest expense and lower corporate G&A expense, which were partially offset by lower Project Adjusted EBITDA (primarily due to the sale of the Wind projects in 2015) and other factors.
Free Cash Flow, which is after debt repayment, capital expenditures and preferred dividends, was $(0.4) million for the fourth quarter of 2015 compared to $(7.2) million for the fourth quarter of 2014. The increase is primarily due to a decrease in project-level debt repayments and a reduction in distributions to noncontrolling interests, including preferred dividends (which were favorably affected by the exchange rate).
Cash Distributions from Projects and the adjusted cash flow metrics discussed below, all of which are non-GAAP measures, exclude cash flows from projects classified as discontinued operations. Adjusted Cash Flows from Operating Activities, which excludes discontinued operations, changes in working capital, severance, restructuring charges, acquisition and disposition expenses and debt prepayment and redemption costs, is a measure of the cash flow available to the Company to make principal repayments on its debt (primarily through amortization and the cash sweep under the APLP term loan), invest in its fleet through required or discretionary capital expenditures, and make dividend payments to preferred shareholders. Adjusted Free Cash Flow is after debt repayment or amortization, capital expenditures and preferred dividends, but is before any discretionary uses of cash flow, including repurchases of debt and equity securities, external growth investments or additional internal capex projects. Tables 10 and 11 of this press release provide a reconciliation of the Company's non-GAAP cash flow metrics to cash flows from operating activities.
Cash Distributions from Projects decreased $11.6 million to $46.0 million for the fourth quarter of 2015 from $57.6 million for the same period in 2014. The decrease was primarily due to the PPA expiration at Tunis, which had a negative impact of $4.7 million; the Ontario projects, due to the timing of customer payments; Mamquam, which experienced record low water flows in 2015; the Navy projects, which benefited from the timing of gas payments in the 2014 period, and Williams Lake, which experienced an unfavorable foreign exchange rate impact. This net decrease was partially offset by increases at Nipigon, which underwent a major outage to upgrade and replace its steam generator in 2014; Curtis Palmer, which benefited from higher water flows, and Kenilworth, which benefited from the timing of a gas payment.
Adjusted Cash Flows from Operating Activities increased $11.4 million to $29.3 million in the fourth quarter of 2015 from $17.9 million in the year-ago period, primarily because of lower cash interest payments and lower corporate G&A expense, partially offset by lower Project Adjusted EBITDA. The 2015 result excludes $5.0 million of cash tax payments associated with the sale of the Wind Projects; the 2014 result excludes operating cash flows of the Wind Projects of $11.3 million.
Adjusted Free Cash Flow increased to $9.2 million in the fourth quarter of 2015 from $(1.4) million in the fourth quarter of 2014. The $10.6 million increase was primarily attributable to higher Adjusted Cash Flows from Operating Activities and several other less significant factors.
Twelve Months Ended December 31, 2015
Project loss for the full year 2015 was $(41.4) million as compared to ($38.9) million in 2014. The increased loss was attributable to a $21.2 million increase in impairment expense and the absence of an $8.6 million gain on the sale of Delta-Person recorded in 2014, partially offset by an $11.2 million increase in equity earnings of affiliates, a $9.5 million reduction in interest expense and an $8.6 million increase in the change in the fair value of derivatives. Impairment expense in 2015 was as described in the discussion of results for the three months ended December 31, 2015, while in 2014 it included $106.6 million of impairments of long-lived assets and goodwill at Tunis and of goodwill at Kenilworth, Manchief and Williams Lake.
Project Adjusted EBITDA decreased $20.5 million to $208.9 million for the full year 2015 from $229.4 million for 2014. The most significant drivers of the decline were lower results from Tunis, due to its mothballed status; Selkirk, due to the expiration of its PPA and reduced dispatch in an unfavorable market environment; Manchief, which had a gas turbine maintenance outage; lower water flows at Curtis Palmer and Mamquam; higher fuel and maintenance expense at North Bay and Kapuskasing, partially offset by higher waste heat generation; and lower excess energy margins at Chambers. Currency had an approximate $(9.0) million impact on Project Adjusted EBITDA, with an average U.S. dollar to Canadian dollar exchange rate for 2015 of 1.27 versus 1.11 for the year-ago period. These negative factors were partially offset by increases at Orlando, which benefited from higher generation, lower fuel expenses due to lower gas prices and rate escalations under the PPA; Morris, which had lower fuel expense, reduced property taxes, and higher PJM capacity pricing, partially offset by lower merchant pricing than the comparable year-ago period; Nipigon, which had a maintenance outage in the comparable year-ago period and also benefited from rate escalations and high levels of waste heat; North Island, which had a gas turbine overhaul in 2014, and Calstock, which had higher waste heat generation and lower maintenance expense than the year-ago period. In addition, the Un-allocated Corporate segment had a reduced loss of $(2.5) million versus $(7.5) million in the year-ago period, due primarily to a reduction in project-level compensation expense and decreased development and administrative costs.
Corporate-level G&A expense decreased $8.5 million to $29.4 million for the full year 2015 from $37.9 million in 2014. The improvement was primarily attributable to a $3.9 million reduction in legal expenses associated with the U.S. and Canadian shareholder actions, a $1.9 million decrease in business development costs related to divestitures and a $1.9 million decrease in employee severance expense.
Cash Flow Metrics
Cash flows provided by operating activities of $87.4 million for the full year 2015 increased $22.4 million from $65.0 million for the comparable period in 2014. The increase is primarily due to a $27.3 million reduction in financing transaction costs and a $13.6 million reduction in total G&A expense, partially offset by a $21.9 million reduction in operating cash flows from the Wind Projects, which were sold in June 2015.
Free Cash Flow was $(19.8) million for the full year 2015 compared to $(55.6) million for 2014. The increase is primarily due to the $22.4 million increase in operating cash flows described previously, a $7.3 million decrease in distributions to noncontrolling interests related to Canadian Hills and Rockland, a $2.8 million decrease in preferred dividends (driven primarily by the exchange rate) and a $2.1 million reduction in capital expenditures. Repayment of the APLP term loan and amortization of project debt totaled $83.4 million in 2015 versus $84.6 million in 2014, including $6.4 million associated with the Wind Projects and an $8.1 million repayment of Piedmont principal at term loan conversion in February 2014.
Cash Distributions from Projects decreased $16.8 million to $192.3 million for the full year 2015 from $209.1 million for 2014. The decrease was primarily due to PPA expirations at Tunis and Selkirk, an impact of $13.1 million and $9.3 million, respectively; Manchief, due to the gas turbine outage and reduced dispatch, and the Navy projects, which benefited from the timing of gas payments in the 2014 period. This net decrease was partially offset by increases at the following projects: Chambers, due to a change in the timing of distributions; Morris, which benefited from lower gas prices, reduced property taxes and a higher PJM capacity rate; Orlando, which benefited from lower gas prices, higher capacity payments and increased generation; Calstock, which benefited from additional waste heat and lower maintenance expense relative to the year-ago period when it had an outage, and Nipigon, which benefited from improved availability following two outages in 2014, additional waste heat and higher capacity payments due to contract escalation.
Adjusted Cash Flows from Operating Activities of $105.3 million for the full year 2015 increased $12.9 million from $92.4 million in 2014. The 2015 result excludes $6.2 million of cash tax payments in the third and fourth quarters associated with the sale of the Wind Projects as well as the $14.0 million premium and $5.5 million of accrued interest paid at redemption of the 9.0% Senior Unsecured Notes (the "9.0% Notes") in June 2015. The 2014 result excludes $49.4 million of interest expense associated with the debt refinancing and repurchase transactions in the first quarter of 2014. The increase in Adjusted Cash Flows from Operating Activities was primarily attributable to a $26.7 million reduction in cash interest payments and an $8.5 million reduction in corporate G&A expense, partially offset by lower Project Adjusted EBITDA.
Adjusted Free Cash Flow of $1.8 million increased $2.1 million for the full year 2015 from $(0.3) million in 2014. Results for both years exclude interest expense associated with debt refinancing or redemption as described above. The 2014 result also excludes an $8.1 million Piedmont principal repayment at term loan conversion. The increase in Adjusted Free Cash Flow was primarily attributable to the $12.9 million increase in Adjusted Cash Flows from Operating Activities described above and a $2.8 million reduction in preferred dividend payments (driven by a more favorable exchange rate), which were mostly offset by a $13.3 million increase in term loan and project debt amortization. The 2015 Adjusted Free Cash Flow of $1.8 million was at the lower end of the Company's guidance range of $0 to $10 million due to a delay in receipt of a customer reimbursement for a 2015 construction project. The $6 million cash payment was received in February 2016.
Results of Discontinued Operations
The Wind Projects were sold in June 2015 and are a component of discontinued operations for the three and twelve months ended December 31, 2015 and 2014. Greeley was sold in March 2014 and is included as a component of discontinued operations for the twelve months ended December 31, 2014. The results for Greeley were immaterial during that period.
Project Adjusted EBITDA of the Wind Projects was $0.0 million for the fourth quarter of 2015 versus $20.7 million for the comparable year-ago period. Results for the full year 2015 were $28.1 million versus $69.8 million for 2014.
Cash flows from operating activities of the Wind Projects were $0.0 million and $21.9 million for the fourth quarter and full year 2015, respectively. These operating cash flows were reduced by $5.0 million and $6.2 million, respectively, of withholding and alternative minimum tax payments associated with the sale of the Wind Projects. The operating cash flows of the Wind Projects were $11.3 million and $48.3 million, respectively, for the fourth quarter and full year 2014.
Liquidity
As shown in Table 3, the Company's liquidity at December 31, 2015 was $178.4 million, including $72.4 million of unrestricted cash. In February 2016, there were two developments that positively affected the Company's liquidity. The Company received a $6 million reimbursement for construction costs incurred in 2015 at one of its projects on behalf of the project's customer. That reimbursement is subject to the 50% cash sweep of the APLP term loan. Separately, Standard & Poor's upgraded the Company's corporate credit rating to B+ from B, which allowed the Company to reduce an existing letter of credit with one of its counterparties by $10 million. Pro forma for these two adjustments, the Company's liquidity would be approximately $13 million higher than the year end 2015 level.
Atlantic Power Corporation
Table 3 – Liquidity (in millions of U.S. dollars)
Unaudited
September 30, 2015
December 31, 2015
Revolver capacity
$210.0
$210.0
Letters of credit outstanding
(109.2)
(104.0)
Unused borrowing capacity
100.8
106.0
Unrestricted cash (1)
76.4
72.4
Total Liquidity
$177.2
$178.4
(1) Includes project-level cash for working capital needs of $13.0 million at each of September 30, 2015 and December 31, 2015.
Note: Does not include restricted cash of $14.5 million at September 30, 2015 and $15.2 million at December 31, 2015.
Other Financial Updates
Impairment Charge and Finding of Material Weakness
In the fourth quarter of 2015, the Company performed its annual goodwill impairment test and determined that it was necessary to impair the carrying value of long-lived assets at Calstock and Williams Lake and to record a full impairment of remaining goodwill at both projects as well as a partial impairment of goodwill at Curtis Palmer. The primary reason for the impairment was the impact of significantly lower forward power prices, driven by an extended period of lower natural gas and oil prices, on expected cash flows from the projects following the expirations of their respective PPAs. The impairment charge, which is non-cash, totaled $127.8 million. There was no impact on Project Adjusted EBITDA or the Company's adjusted cash flow metrics.
As discussed in the Company's annual report on Form 10-K, management has determined that a material weakness existed in the Company's internal control over financial reporting because its annual goodwill impairment test resulted in an initial finding that no impairment of long-lived assets was required and that goodwill would be impaired by a smaller amount than subsequently determined. Management is in the process of determining and implementing a remediation plan and expects the control weakness to be remediated in the coming year.
Progress on Debt Reduction
In the fourth quarter of 2015, the Company made additional progress in reducing its debt, making $11.7 million of payments on the APLP term loan and amortizing $4.4 million of project-level debt. The Company also repurchased $0.2 million of convertible debentures pursuant to the NCIB.
For the full year 2015, the Company repaid $68.3 million of the APLP term loan through the 1% mandatory annual amortization and the 50% cash sweep, reducing the outstanding balance to $473.2 million, and amortized $15.1 million of project-level debt. Discretionary repurchases of its convertibles pursuant to the NCIB totaled $21.8 million; in addition, the Company repurchased $9.0 million of its 9.0% Notes in the first quarter of 2015. The Company used the proceeds from the sale of its Wind Projects to fund the redemption of the $310.9 million remaining principal amount of the 9.0% Notes in July. Approximately $249 million of debt associated with the Wind Projects was deconsolidated as a result of the sale.
Since year end 2013, the Company has reduced its total debt by $833 million, including its $76 million share of debt at equity-owned projects (mostly for Wind projects). The interest cost savings associated with total debt reduction are more than $65 million on an annualized basis.
Further debt reduction is expected to be achieved through continued amortization of project-level debt and the APLP term loan, which together are expected to average approximately $65 to $70 million annually over the next two years.
The Company also has an improved corporate maturity profile. The remaining corporate debt consists of $285 million (U.S. dollar equivalent) of convertible debentures maturing in 2017 ($103 million) and 2019 ($182 million). The Company continues to explore opportunities to address these maturities.
In February 2016, the Company received a corporate credit rating upgrade from Standard & Poor's to B+ from B. This follows an upgrade by Moody's last October to B1 from B2. Both agencies have "stable" ratings outlooks for the Company.
G&A Expense Targets
For the full year 2015, total G&A expense was $31.9 million, including $2.6 million of development expense and project-level G&A that are included in Project Adjusted EBITDA. The $31.9 million includes $4 million of severance expense and $2 million of restructuring and other charges. The Company expects 2016 total G&A expense of approximately $27 million, which would represent a 50% cumulative reduction from the 2013 level of approximately $54 million.
Optimization Investments
The majority of the Company's capital expenditures are discretionary investments in existing projects designed to increase their output or improve their efficiency in order to enhance the margins of these facilities. The Company considers these investments to be an attractive use of its cash considering the relatively modest capital requirements and potential for strong risk-adjusted returns.
From 2013 to 2015, the Company invested approximately $22 million in such projects, net of a customer reimbursement, the most significant of which were the turbine upgrades at Curtis Palmer completed in 2013 and 2014, the Nipigon Once-Through Steam Generator upgrade and feedwater booster pump installation, completed in 2014 and 2015, respectively, and several projects at Morris. In 2015, the Company realized a cash flow benefit from completed projects of approximately $6 million. This contribution, although reduced by low water flows at Curtis Palmer and high levels of waste heat at Nipigon, was in line with the Company's expectations. The Company expects this contribution to increase to approximately $10 million in 2016, including an initial cash flow contribution from projects expected to be completed by mid-2016. This outlook assumes lower waste heat levels in 2016 than in 2015, though still above typical levels, and average water flows at Curtis Palmer.
The Company expects that optimization-related investments will total approximately $4 million in 2016, mostly for upgrades to a boiler and two gas turbines at Morris and a spillway upgrade project at Curtis Palmer. The Company has other optimization projects under consideration that could require additional expenditures in 2016.
Maintenance and Capex
For the full year 2015, capital expenditures were $11 million, of which approximately $9 million was attributable to discretionary optimization projects. In addition to amounts capitalized, the Company incurs maintenance expense to maintain its projects. Total maintenance expense was approximately $56 million for 2015.
For 2016, the Company expects to have capital expenditures of $16 to $19 million, with the range attributable to potential optimization projects not yet firmly committed to. The most significant budgeted expenditures are for the optimization projects at Morris and Curtis Palmer (approximately $4 million) and for the 2016 portion of costs associated with the repowering of Tunis and a new fuel shredder for Williams Lake (approximately $7 million for the two projects). In addition, the Company expects to incur maintenance expense of approximately $57 million.
Morris Energy Services Agreement (ESA) and Planned Outages
As announced in December, the Company has executed an agreement with the customer at its Morris project to modify and extend the ESA from November 2023 to December 2034. The modifications to the ESA are expected to be modestly accretive to the Project Adjusted EBITDA from Morris on average relative to the original contract terms. As of December 31, 2015, including the impact of the Morris ESA extension, the weighted-average remaining life of the Company's PPAs is 7.5 years (on an EBITDA-weighted basis).
Separately, and not related to the ESA modifications and extension, the Company expects that Morris will undergo an approximately six-week major maintenance outage in the late summer of 2016. During this outage, the Company will continue work on upgrading two of the project's combustion turbines, overhaul the steam turbine and upgrade the plant's Distributed Controls System. Together with an upgrade to one of the project's boilers scheduled to be completed earlier in the year, these upgrades are expected to increase output and fuel efficiency as well as enhance reliability of steam delivery for the customer. Higher maintenance expense and lost margin associated with the extended outage, as well as other less significant factors, are expected to reduce Project Adjusted EBITDA from the Morris project by approximately $9 million in 2016 from a higher-than-average level in 2015.
Normal Course Issuer Bid (NCIB)
As announced in December 2015, the Company has implemented an NCIB for up to 10% of each of its outstanding convertible debentures and its common shares and up to 5% of Atlantic Power Preferred Equity Ltd.'s preferred shares. The NCIB became effective in late December and is scheduled to expire on December 28, 2016. Since late December, the Company has repurchased approximately 575,000 shares under the NCIB at a total cost of approximately US$1.0 million.
Changes to Capital Allocation Strategy
In February 2016, the Company announced changes to its capital allocation strategy designed to create value for shareholders in a tax-efficient manner while improving the Company's financial flexibility and strengthening its balance sheet. These changes included elimination of the common stock dividend (and the related dividend reinvestment plan), effective immediately, and prioritization of its discretionary cash after debt repayment for higher-return purposes, including repurchases of its debt and equity securities under the NCIB at compelling price-to-value levels and attractive investments in internal optimization projects.
2016 Guidance
Atlantic Power Corporation
Table 4 – FY 2015 Actual Results vs. 2016 Guidance
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
FY 2015
FY 2016
Actual
Guidance
Project Adjusted EBITDA
$208.9
$200 - $220
Adjusted Cash Flows from Operating Activities (1)
$105.3
$110 - $130
Adjusted Free Cash Flow (2)
$1.8
$20 - $40
APLP Project Adjusted EBITDA (3)
$155.2
$145 - $155
(1) Adjusted Cash Flows from Operating Activities is used to evaluate cash flows from operating activities without the effects of changes in
working capital balances, acquisition and disposition expenses, litigation expenses, severance and restructuring charges, debt prepayment
and redemption costs and cash provided by or used in discontinued operations. The intent is to reflect normal operations and remove items
that are not reflective of the long-term operations of the business.
(2) Adjusted Free Cash Flow is defined as Free Cash Flow excluding changes in working capital balances, acquisition and disposition expenses, litigation expense, severance and restructuring charges, debt prepayment and redemption costs and cash provided by or used in discontinued operations. Free Cash Flow is defined as cash flows from operating activities less capex; project-level debt repayments, including amortization of the APLP term loan; and distributions to noncontrolling interests, including preferred share dividends.
(3) APLP is a wholly owned subsidiary of the Company. APLP Project Adjusted EBITDA is a summation of Project Adjusted EBITDA at each APLP project, and is calculated in a manner which is consistent with the Company's Project Adjusted EBITDA calculation.
Note: Project Adjusted EBITDA, Adjusted Cash Flows from Operating Activities, Adjusted Free Cash Flow and APLP Project Adjusted EBITDA are not recognized measures under GAAP and do not have any standardized meaning prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies. The Company has not provided a reconciliation of forward-looking non-GAAP measures, due primarily to variability and difficulty in making accurate forecasts and projections, as not all of the information necessary for a quantitative reconciliation is available to the Company without unreasonable efforts.
Table 4 shows the Company's full-year 2016 guidance as compared to the actual results for 2015. Key drivers are as follows:
Total Company Project Adjusted EBITDA of $200 to $220 million. Positive drivers in 2016 include an assumed return to average water flows at Mamquam and Curtis Palmer (versus historic lows in 2015), a full-year return on optimization investments and the non-recurrence of the major gas turbine outage at Manchief in 2015. These are mostly offset by the negative impacts of an extended outage at Morris, an unfavorable exchange rate, and an assumed reduction in waste heat from historically high levels in 2015.
APLP Project Adjusted EBITDA of $145 to $155 million. Drivers are consistent with those for Total Company Project Adjusted EBITDA.
Adjusted Cash Flows from Operating Activities of $110 to $130 million. The expected increase in 2016 is largely attributable to lower cash interest payments.
Adjusted Free Cash Flow of $20 to $40 million. The expected increase in 2016 is attributable to the expected increase in Adjusted Cash Flows from Operating Activities, lower debt repayment and a customer reimbursement for 2015 construction costs received in 2016.
Other Recent Developments
Share Purchases by Insiders
In the fourth quarter, two senior executives and one director of the Company purchased a total of approximately 493,000 common shares of the Company at an average price of US$1.77 per share. Including those made in previous quarters, purchases by management and directors this year total approximately 1.05 million common shares. The average purchase price for these purchases was US$2.31 per share. There have been no sales of shares by officers or directors this year, other than those sold automatically for tax withholding purposes upon vesting under the Long-Term Incentive Plan.
Shareholder Litigation
As announced by the Company in December, both the U.S. and Ontario securities class action suits were dismissed by the respective courts, with no payments required by the Company. Following the resolution of the Ontario matter, the petitioner in the Quebec proceedings has agreed in principle with the defendants in the suit to discontinue the proceedings, with each side bearing its own costs. The agreement is subject to the approval of the Superior Court of Quebec.
Supplementary Financial Information
For further information, attached to this news release is a summary of Project Adjusted EBITDA by segment for the three and twelve months ended December 31, 2015 and 2014 (Table 8) with a reconciliation to project income (loss); a bridge from Project Adjusted EBITDA to Cash Distributions from Projects by segment for the year ended December 31, 2015 (Table 9A) and the year ended December 31, 2014 (Table 9B); a reconciliation of Cash Distributions from Projects and Project Adjusted EBITDA to net income (loss) and of various non-GAAP cash flow metrics to cash flows from operating activities for the three and twelve months ended December 31, 2015 and 2014 (Table 10); reconciliations of Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow to cash flows from operating activities for the three and twelve months ended December 31, 2015 and 2014 (Tables 11A and 11B); and a summary of Project Adjusted EBITDA for selected projects (top contributors based on the Company's 2015 budget, representing approximately 90% of total Project Adjusted EBITDA) for the three and twelve months ended December 31, 2015 and 2014 (Table 12).
Investor Conference Call and Webcast
Atlantic Power's management team will host a telephone conference call on Tuesday, March 8, 2016 at 8:30 AM ET. An accompanying slide presentation will be available on the Company's website prior to the call.
Conference Call / Webcast Information:
Date: Tuesday, March 8, 2016
Start Time: 8:30 AM ET
Phone Number: U.S. (Toll Free) 1-877-870-4263; Canada (Toll Free) 1-855-669-9657; International (Toll) 1-412-317-0790
Conference Access: Please request access to the Atlantic Power conference call.
Webcast: The call will be broadcast over Atlantic Power's website at www.atlanticpower.com.
Replay/Archive Information:
Replay: Access conference call number 10079885 at the following telephone numbers: U.S. (Toll Free) 1-877-344-7529; Canada (Toll Free) 1-855-669-9658; International (Toll) 1-412-317-0088. The replay will be available one hour after the end of the conference call through April 6, 2016 at 11:59 PM ET.
Webcast archive: The conference call will be archived on Atlantic Power's website at www.atlanticpower.com for a period of 12 months.
About Atlantic Power
Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. The Company's power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices. Atlantic Power's power generation projects in operation have an aggregate gross electric generation capacity of approximately 2,138 megawatts ("MW") in which its aggregate ownership interest is approximately 1,500 MW. The Company's current portfolio consists of interests in twenty-three operational power generation projects across nine states in the United States and two provinces in Canada.
Atlantic Power trades on the New York Stock Exchange under the symbol AT and on the Toronto Stock Exchange under the symbol ATP. For more information, please visit the Company's website at www.atlanticpower.com or contact:
Atlantic Power Corporation
Investor Relations
(617) 977-2700
info@atlanticpower.com
Copies of certain financial data and other publicly filed documents are filed on SEDAR at www.sedar.com or on EDGAR at www.sec.gov/edgar.shtml under "Atlantic Power Corporation" or on the Company's website.
Cautionary Note Regarding Forward-Looking Statements
To the extent any statements made in this news release contain information that is not historical, these statements are forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended, and under Canadian securities law (collectively, "forward-looking statements").
Certain statements in this news release may constitute "forward-looking statements", which reflect the expectations of management regarding the future growth, results of operations, performance and business prospects and opportunities of the Company and its projects. These statements, which are based on certain assumptions and describe the Company's future plans, strategies and expectations, can generally be identified by the use of the words "may," "will," "project," "continue," "believe," "intend," "anticipate," "expect" or similar expressions that are predictions of or indicate future events or trends and which do not relate solely to present or historical matters. Examples of such statements in this press release include, but are not limited, to statements with respect to the following:
that the Company's discretionary cash flow after debt repayment is growing, and there are ample opportunities to invest the cash at good returns;
the Company's ability to make progress on further extensions of its existing PPAs;
the Company's ability to address its convertible debenture maturities;
the Company expects to further reduce debt through continued amortization of project-level debt and the APLP term loan, which together are expected to average approximately $65 to $70 million annually over the next two years;
the Company expects to have total G&A costs of approximately $27 million in 2016;
the Company expects to realize a cash flow benefit from discretionary investments in its existing projects of approximately $10 million in 2016;
the Company expects that discretionary optimization investments in its fleet will be approximately $4 million in 2016;
the Company expects that in 2016, capital expenditures will total approximately $16 to $19 million, before a $5 million credit for a customer reimbursement, and maintenance expense will total approximately $57 million;
the Company expects a modest increase in Project Adjusted EBITDA from Morris on average relative to the terms of the original ESA;
the Company expects that Morris will undergo an extended maintenance outage in the late summer of 2016;
upgrades of the Morris project's combustion turbines and one of its boilers are expected to enhance the project's output and reliability;
the Company expects an approximate $9 million reduction in 2016 Project Adjusted EBITDA from Morris due to the planned outages and other less significant factors in 2016;
the Company may purchase, through the NCIB, up to 10% of each of its convertible debentures and common shares and Atlantic Power Preferred Equity Ltd. may purchase up to 5% of its preferred shares;
changes to the Company's capital allocation strategy will create value in a tax-efficient manner while improving the Company's financial flexibility and strengthening its balance sheet;
the Company's ability to capture value from repurchases of its equity and debt securities;
the Company's plans to focus on organic growth and to evaluate external opportunities in a disciplined and opportunistic manner;
the Company's ability to realize high returns on its internal growth investments;
2016 Project Adjusted EBITDA will be in the range of $200 to $220 million;
2016 APLP Project Adjusted EBITDA will be in the range of $145 to $155 million;
2016 Adjusted Cash Flows from Operating Activities will be in the range of $110 to $130 million;
2016 Adjusted Free Cash Flow will be in the range of $20 to $40 million;
the nature of any further proceedings in the Quebec securities action;
the Company's ability to remediate the material weakness in its internal controls over financial reporting; and
the results of operations and performance of the Company's projects, business prospects, opportunities and future growth of the Company will be as described herein.
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. Please refer to the factors discussed under "Risk Factors" and "Forward-Looking Information" in the Company's periodic reports as filed with the Securities and Exchange Commission from time to time for a detailed discussion of the risks and uncertainties affecting the Company, including, without limitation, the outcome or impact of the Company's business plan, including the objective of enhancing the value of its existing assets through optimization investments and commercial activities, delevering its balance sheet to improve its cost of capital and ability to compete for new investments, and utilizing its core competencies to create proprietary investment opportunities, and the Company's ability to raise additional capital for growth and/or debt reduction, and the outcome or impact on the Company's business of any such actions. Although the forward-looking statements contained in this news release 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. These forward-looking statements are made as of the date of this news release and, except as expressly required by applicable law, the Company assumes no obligation to update or revise them to reflect new events or circumstances. The Company's ability to achieve its longer-term goals, including those described in this news release, is based on significant assumptions relating to and including, among other things, the general conditions of the markets in which it operates, revenues, internal and external growth opportunities, its ability to sell assets at favorable prices or at all and general financial market and interest rate conditions. The Company's actual results may differ, possibly materially and adversely, from these goals.
Atlantic Power Corporation
Table 5 – Consolidated Balance Sheet (in millions of U.S. dollars)
(Unaudited)
December 31,
December 31,
2015
2014
Assets
Current assets:
Cash and cash equivalents
$72.4
$106.0
Restricted cash
15.2
22.5
Accounts receivable
39.6
46.2
Inventory
16.9
19.3
Prepayments and other current assets
8.3
10.6
Assets held for sale
-
790.4
Income taxes receivable
3.5
0.2
Other current assets
4.4
3.3
Total current assets
160.3
998.5
Property, plant and equipment, net
777.7
962.9
Equity investments in unconsolidated affiliates
286.2
306.9
Power purchase agreements and intangible assets, net
308.9
377.1
Goodwill
134.5
197.2
Derivative instruments asset
0.3
1.1
Deferred financing costs
42.5
62.8
Other assets
6.7
9.5
Total assets
$1,717.1
$2,916.0
Liabilities
Current liabilities:
Accounts payable
$6.9
$9.4
Accrued interest
1.6
5.3
Other accrued liabilities
28.8
30.7
Current portion of long-term debt
15.8
20.0
Current portion of derivative instruments liability
36.7
36.1
Liabilities held for sale
-
271.8
Other current liabilities
2.5
6.8
Total current liabilities
92.3
380.1
Long-term debt
717.5
1,145.9
Convertible debentures
285.4
340.6
Derivative instruments liability
20.8
47.5
Deferred income taxes
85.7
92.4
Power purchase and fuel supply agreement liabilities, net
27.0
33.4
Other long-term liabilities
53.2
59.6
Total liabilities
$1,281.9
$2,099.5
Equity
Common shares, no par value, unlimited authorized shares; 122,153,082 and 121,323,614
issued and outstanding at December 31, 2015 and December 31, 2014, respectively
1,290.6
1,288.4
Accumulated other comprehensive loss
(139.3)
(68.3)
Retained deficit
(937.4)
(863.9)
Total Atlantic Power Corporation shareholders' equity
213.9
356.2
Preferred shares issued by a subsidiary company
221.3
221.3
Noncontrolling interests
-
239.0
Total equity
435.2
816.5
Total liabilities and equity
$1,717.1
$2,916.0
Atlantic Power Corporation
Table 6 – Consolidated Statements of Operations
(in millions of U.S. dollars, except per share amounts)
Unaudited
Three months ended
Twelve months ended
December 31,
December 31,
2015
2014
2015
2014
Project revenue:
Energy sales
$46.6
$59.4
$191.5
$236.9
Energy capacity revenue
31.9
37.3
149.3
161.3
Other
19.9
23.1
79.4
91.7
98.4
119.9
420.2
489.9
Project expenses:
Fuel
39.8
50.9
165.1
210.4
Operations and maintenance
21.9
23.5
103.5
109.0
Development
-
1.0
1.1
3.7
Depreciation and amortization
26.2
30.2
110.0
122.3
87.9
105.6
379.7
445.4
Project other income (expense):
Change in fair value of derivative instruments
6.7
(16.5)
15.4
6.8
Equity in earnings of unconsolidated affiliates
8.4
(2.3)
36.7
25.5
Gain on sale of equity investments
-
8.6
-
8.6
Interest expense, net
(2.0)
(2.0)
(8.2)
(17.7)
Impairment
(127.8)
-
(127.8)
(106.6)
Other income (expense), net
(0.1)
-
2.0
-
(114.8)
(12.2)
(81.9)
(83.4)
Project income (loss)
(104.3)
2.1
(41.4)
(38.9)
Administrative and other expenses (income):
Administration
6.4
11.2
29.4
37.9
Interest, net
15.8
25.9
107.1
146.7
Foreign exchange gain
(11.2)
(17.9)
(60.3)
(38.3)
Other income, net
0.2
(0.6)
(3.1)
(0.6)
11.2
18.6
73.1
145.7
(Loss) income from continuing operations before income taxes
(115.5)
(16.5)
(114.5)
(184.6)
Income tax expense (benefit)
(30.1)
(11.4)
(30.4)
(31.4)
(Loss) income from continuing operations
(85.4)
(5.1)
(84.1)
(153.2)
Net income (loss) from discontinued operations, net of tax (1)
(1.3)
(7.3)
19.5
(29.0)
Net income (loss)
(86.7)
(12.4)
(64.6)
(182.2)
Net income (loss) attributable to noncontrolling interests
-
(4.6)
(11.0)
(16.4)
Net income attributable to preferred share dividends of a subsidiary company
1.9
2.8
8.8
11.6
Net income (loss) attributable to Atlantic Power Corporation
($88.6)
($10.6)
($62.4)
($177.4)
Basic and diluted earnings per share:
Loss from continuing operations attributable to Atlantic Power Corporation
($0.60)
($0.07)
($0.76)
($1.37)
Income (loss) from discontinued operations, net of tax
(0.01)
(0.02)
$0.25
($0.10)
Net income (loss) attributable to Atlantic Power Corporation
($0.61)
($0.09)
($0.51)
($1.47)
Weighted average number of common shares outstanding:
Basic
122.1
121.0
121.9
120.7
Diluted
122.1
121.0
121.9
120.7
Dividends paid per common share:
$0.02
$0.03
$0.09
$0.29
(1) Includes contributions from the Wind Projects and Greeley, which are components of discontinued operations.
Atlantic Power Corporation
Table 7 – Consolidated Statements of Cash Flows (in millions of U.S. dollars)
Unaudited
Twelve months ended December 31,
2015
2014
Cash flows from operating activities:
Net Income (loss)
($64.6)
($182.2)
Adjustments to reconcile to net cash provided by operating activities:
Depreciation and amortization
120.3
162.6
Loss from discontinued operations
-
-
Gain on sale of assets
(48.7)
(2.9)
Gain on sale of equity investments
-
(8.6)
Gain on purchase and cancellation of convertible debentures
(3.1)
-
Stock-based compensation expense
2.3
3.5
Long-lived asset and goodwill impairment charges
127.8
106.6
Equity in earnings from unconsolidated affiliates
(36.2)
(25.8)
Distributions from unconsolidated affiliates
58.5
76.2
Unrealized foreign exchange gain
(60.5)
(38.8)
Change in fair value of derivative instruments
(14.7)
8.7
Change in deferred income taxes
(3.5)
(15.7)
Change in other operating balances
Accounts receivable
5.7
6.9
Inventory
2.4
(3.3)
Prepayments, refundable income taxes and other assets
20.9
21.1
Accounts payable
(8.9)
(4.1)
Accruals and other liabilities
(10.3)
(39.2)
Cash provided by operating activities
87.4
65.0
Cash flows provided by investing activities:
Change in restricted cash
7.3
72.6
Proceeds from sale of assets and equity investments, net
326.3
9.5
Contribution to unconsolidated affiliate
(0.6)
-
Development costs
(0.8)
-
Purchase of property, plant and equipment
(11.3)
(13.4)
Cash provided by investing activities
320.9
68.7
Cash flows used in financing activities:
Proceeds from senior secured term loan facility
-
600.0
Repayment of corporate and project-level debt
(403.3)
(639.8)
Repayment of convertible debentures
(18.9)
(43.0)
Deferred financing costs
-
(39.0)
Dividends paid to common shareholders
(11.1)
(34.9)
Dividends paid to noncontrolling interests
(3.7)
(11.1)
Dividends paid to preferred shareholders
(8.8)
(14.6)
Cash used in financing activities
(445.8)
(182.4)
Net increase (decrease) in cash and cash equivalents
(37.5)
(48.7)
Cash and cash equivalents at beginning of period at discontinued operations
3.9
(3.9)
Cash and cash equivalents at beginning of period
106.0
158.6
Cash and cash equivalents at end of period
$72.4
$106.0
Supplemental cash flow information
Interest paid
$100.0
$168.8
Income taxes paid, net
$10.2
$3.8
Accruals for construction in progress
$0.6
$0.0
Regulation G Disclosures
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. Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in the fair value of derivative instruments. Management uses Project Adjusted EBITDA at the project level to provide comparative information about project performance and believes such information is helpful to investors. A reconciliation of Project Adjusted EBITDA to project income (loss) is provided in Table 8 below. Investors are cautioned that the Company may calculate this measure in a manner that is different from other companies.
Cash Distributions from Projects, Adjusted Cash Flows from Operating Activities, Free Cash Flow and Adjusted Free Cash Flow are not measures recognized under GAAP and do not have standardized meanings prescribed by GAAP, and are therefore unlikely to be comparable to similar measures presented by other companies. Adjusted Cash Flows from Operating Activities is used to evaluate cash flows from operating activities without the effects of changes in working capital balances, acquisition and disposition expenses, litigation expenses, severance and restructuring charges, and cash provided by or used in discontinued operations. The intent is to reflect normal operations and remove items that are not reflective of the long-term operations of the business. Free Cash Flow is defined as cash flows from operating activities less capex; project-level debt repayments, including amortization of the term loan; and distributions to noncontrolling interests, including preferred share dividends.
Adjusted Free Cash Flow is defined as Free Cash Flow excluding changes in working capital balances, acquisition and disposition expenses, litigation expense, severance and restructuring charges, and cash provided by or used in discontinued operations. Management believes that these non-GAAP cash flow measures are relevant supplemental measures of the Company's ability to earn and distribute cash returns to investors. A bridge of Project Adjusted EBITDA to Cash Distributions from Projects is provided in Tables 9A and 9B on page 19. A reconciliation of Free Cash Flow to cash flows from operating activities is provided in Table 10 on page 20 of this release. Reconciliations of Adjusted Free Cash Flow and Adjusted Cash Flows from Operating Activities to cash flows from operating activities are provided in Tables 11A and 11B on pages 21 and 22 of this release. Investors are cautioned that the Company may calculate these measures in a manner that is different from other companies.
Atlantic Power Corporation
Table 8 – Project Adjusted EBITDA by Segment (in millions of U.S. dollars)
Unaudited
Three months ended December 31
Twelve months ended December 31
2015
2014
2015
2014
Project Adjusted EBITDA by segment
East U.S.
$23.8
$24.1
$104.8
$106.4
West U.S. (1)
9.8
9.4
46.9
54.2
Canada
16.7
24.7
59.7
76.3
Un-allocated Corporate
0.1
(1.3)
(2.5)
(7.5)
Total
$50.4
$56.9
$208.9
$229.4
Reconciliation to project income
Depreciation and amortization
$31.2
$35.3
$130.1
$155.9
Interest expense, net
2.1
2.4
9.8
20.5
Change in the fair value of derivative instruments
(6.7)
16.8
(15.4)
(6.2)
Other (income) expense
128.1
0.2
125.8
98.1
Project income (loss)
($104.3)
$2.1
($41.4)
($38.9)
(1) Excludes Greeley, which is a component of discontinued operations.
Notes: Table 8 excludes the Wind Projects, which comprise the entirety of the former Wind segment. The Wind Projects are designated as discontinued operations for the three and twelve months ended December 31, 2015 and 2014.
Table 8 presents Project Adjusted EBITDA, which is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP; therefore, this measure may not be comparable to a similar measure presented by other companies.
Atlantic Power Corporation
Table 9A – Cash Distributions from Projects (by Segment, in millions of U.S. dollars)
Twelve months ended December 31, 2015 (Unaudited)
Unaudited
Project
Adjusted
EBITDA
Repayment of
long-term debt
Interest
expense,
net
Capital
expenditures
Other, including
changes in
working capital
Cash
Distributions
from
Projects
Segment
East U.S.
Consolidated
$65.8
($8.9)
($8.2)
($7.6)
$2.8
$43.9
Equity method
39.0
(6.0)
(1.6)
(0.2)
3.7
34.9
Total
104.8
(14.9)
(9.8)
(7.8)
6.5
78.8
West U.S.
Consolidated
33.6
-
-
(1.7)
4.3
36.1
Equity method
13.3
-
-
(0.1)
0.7
13.9
Total
46.9
-
-
(1.8)
4.9
50.0
Canada
Consolidated
59.7
(0.3)
-
(2.3)
6.2
63.4
Equity method
-
-
-
-
-
-
Total
59.7
(0.3)
-
(2.3)
6.2
63.4
Total consolidated
159.1
(9.1)
(8.2)
(11.6)
13.3
143.5
Total equity method
52.3
(6.0)
(1.6)
(0.3)
4.4
48.8
Un-allocated corporate
(2.5)
-
-
0.3
2.2
(0.0)
Total
$208.9
($15.1)
($9.8)
($11.5)
$19.9
$192.3
Note: Table 9A presents Cash Distributions from Projects and Project Adjusted EBITDA, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies.
Atlantic Power Corporation
Table 9B – Cash Distributions from Projects (by Segment, in millions of U.S. dollars)
Twelve months ended December 31, 2014 (Unaudited)
Project Adjusted EBITDA
Repayment of
long-term debt
Interest
expense,
net
Capital expenditures
Other, including
changes in
working capital
Cash
Distributions
from
Projects
Segment
East U.S.
Consolidated
$62.2
($14.6)
($11.4)
($2.6)
$2.5
$36.0
Equity method
44.2
(5.0)
(2.9)
(0.6)
1.2
36.9
Total
106.4
(19.6)
(14.4)
(3.2)
3.6
72.8
West U.S.
Consolidated
39.8
-
-
-
1.7
41.6
Equity method
14.4
-
-
(0.0)
0.5
14.9
Total
54.2
-
-
(0.0)
2.3
56.4
Canada
Consolidated
76.3
-
(0.0)
(7.8)
5.9
74.4
Equity method
-
-
-
-
-
-
Total
76.3
-
(0.0)
(7.8)
5.9
74.4
Total consolidated
178.4
(14.6)
(11.5)
(10.4)
10.1
151.9
Total equity method
58.6
(5.0)
(2.9)
(0.6)
1.7
51.7
Un-allocated corporate
(7.5)
-
-
(1.6)
14.6
5.5
Total
$229.4
($19.6)
($14.4)
($12.6)
$26.4
$209.1
Note: Table 9B presents Cash Distributions from Projects and Project Adjusted EBITDA, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies.
Atlantic Power Corporation
Table 10 – Free Cash Flow (in millions of U.S. dollars)
Unaudited
Three months ended
December 31,
Twelve months ended
December 31,
2015
2014
2015
2014
Cash Distributions from Projects
$46.0
$57.6
$192.3
$209.1
Repayment of long-term debt
(4.3)
(3.6)
(15.1)
(19.6)
Interest expense, net
(2.3)
(2.5)
(9.8)
(14.4)
Capital expenditures
(1.2)
(3.1)
(11.5)
(12.6)
Other, including changes in working capital
3.5
9.9
19.9
26.4
Project Adjusted EBITDA
$50.4
$56.9
$208.9
$229.4
Depreciation and amortization
31.2
35.3
130.1
155.9
Interest expense, net
2.1
2.4
9.8
20.5
Change in the fair value of derivative instruments
(6.7)
16.8
(15.4)
(6.2)
Other (income) expense
128.1
0.2
125.8
98.1
Project income (loss)
($104.3)
$2.1
($41.4)
($38.9)
Administrative and other expenses (income)
11.2
18.6
73.1
145.7
Income tax expense (benefit)
(30.1)
(11.4)
(30.4)
(31.4)
Net income (loss) from discontinued operations, net of tax
(1.3)
(7.3)
19.5
(29.0)
Net income (loss)
($86.7)
($12.4)
($64.6)
($182.2)
Adjustments to reconcile to net cash provided by operating activities
120.8
56.2
142.2
265.8
Change in other operating balances
(14.5)
(24.8)
9.8
(18.6)
Cash flows from operating activities
$19.7
$19.1
$87.4
$65.0
Term loan facility repayments (1)
(11.7)
(11.3)
(68.3)
(58.4)
Project-level debt repayments
(4.4)
(6.6)
(15.1)
(26.2)
Purchases of property, plant and equipment (2)
(1.9)
(3.4)
(11.3)
(13.4)
Distributions to noncontrolling interests (3)
-
(2.2)
(3.7)
(11.0)
Dividends on preferred shares of a subsidiary company
(2.1)
(2.8)
(8.8)
(11.6)
Free Cash Flow
($0.4)
($7.2)
($19.8)
($55.6)
Additional GAAP cash flow measures:
Cash flows from investing activities
($2.7)
($7.7)
$320.9
$68.7
Cash flows from financing activities
($21.0)
($69.1)
($445.8)
($182.4)
(1) Includes mandatory 1% annual amortization and 50% excess cash flow repayments by the Partnership.
(2) Excludes construction costs related to the Company's Canadian Hills project in 2014.
(3) Distributions to noncontrolling interests include distributions to the tax equity investors at Canadian Hills and to the other 50% owner of Rockland. These projects were sold in June 2015.
Note: This table presents Cash Distributions from Projects, Project Adjusted EBITDA and Free Cash Flow, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies.
Atlantic Power Corporation
Table 11A – Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow (in millions of U.S. dollars)
Three months ended December 31, 2015 and 2014
(Unaudited)
Three months ended
December 31, 2015
Three months ended
December 31, 2014
Continuing
Operations
Discontinued
Operations
Total
Continuing
Operations
Discontinued
Operations
Total
Project Adjusted EBITDA
$50.4
$-
$50.4
$56.9
$20.7
$77.6
Adjustment for equity method projects (1)
6.0
-
6.0
10.5
(2.9)
7.6
Corporate G&A expense
(6.5)
-
(6.5)
(11.2)
-
(11.2)
Cash interest payments
(20.6)
-
(20.6)
(39.4)
(4.8)
(44.2)
Cash taxes
(1.0)
(5.0)
(6.0)
(1.1)
-
(1.1)
Other, including changes in working capital
(3.6)
-
(3.6)
(7.9)
(1.7)
(9.6)
Cash flows from operating
activities
$24.7
($5.0)
$19.7
$7.8
$11.3
$19.1
Changes in other operating balances
3.6
-
3.6
7.9
1.7
9.6
Severance charges
-
-
-
0.9
-
0.9
Restructuring and other charges
-
-
-
0.7
-
0.7
Shareholder litigation expenses
-
-
-
0.6
-
0.6
Refinancing transaction costs (Q1 2014)
1.0
-
1.0
-
-
-
Debt redemption costs (9.0% Notes)
-
-
-
-
-
-
Adjusted Cash Flows from Operating Activities
$29.3
($5.0)
$24.3
$17.9
$13.0
$30.9
Term loan facility repayments (2)
(11.7)
-
(11.7)
(11.3)
-
(11.3)
Project-level debt repayments
(4.4)
-
(4.4)
(3.7)
(2.9)
(6.6)
Purchases of property, plant and equipment (3)
(1.9)
-
(1.9)
(1.5)
(1.9)
(3.4)
Distributions to noncontrolling interests (4)
-
-
-
-
(2.2)
(2.2)
Dividends on preferred shares of a subsidiary company
(2.1)
-
(2.1)
(2.8)
-
(2.8)
Adjusted Free Cash Flow
$9.2
($5.0)
$4.2
($1.4)
$6.0
$4.6
Additional GAAP cash flow measures:
Cash flows from investing activities
(2.7)
-
(2.7)
(5.5)
(2.2)
(7.7)
Cash flows from financing activities
(21.0)
-
(21.0)
(59.8)
(9.3)
(69.1)
(1) Represents difference between Project Adjusted EBITDA and cash distributions from equity method projects.
(2) Includes 1% mandatory annual amortization and 50% excess cash flow repayments by the Partnership.
(3) Excludes construction costs related to the Company's Canadian Hills project in 2014.
(4) Distributions to noncontrolling interests primarily include distributions, if any, to the tax equity investors at Canadian Hills and to the other 50% owner of Rockland. These projects were sold in June 2015.
Note: This table presents Project Adjusted EBITDA, Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies.
Atlantic Power Corporation
Table 11B – Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow (in millions of U.S. dollars)
Twelve months ended December 31, 2015 and 2014 (Unaudited)
Twelve months ended
December 31, 2015
Twelve months ended
December 31, 2014
Continuing Operations
Discontinued Operations
Total
Continuing Operations
Discontinued Operations
Total
Project Adjusted EBITDA
$208.9
$28.1
$237.0
$229.4
$69.8
$299.2
Adjustment for equity method projects (1)
2.2
(2.7)
(0.5)
(0.8)
(6.1)
(6.9)
Corporate G&A expense
(29.4)
-
(29.4)
(37.9)
-
(37.9)
Cash interest payments
(98.3)
(1.5)
(99.8)
(154.9)
(13.8)
(168.7)
Cash taxes
(3.9)
(6.2)
(10.1)
(2.1)
-
(2.1)
Other, including changes in working capital
(7.8)
(2.0)
(9.8)
(17.0)
(1.6)
(18.6)
Cash flows from operating activities
$71.7
$15.7
$87.4
$16.7
$48.3
$65.0
Changes in other operating balances
7.8
2.0
9.8
17.0
1.6
18.6
Severance charges
3.9
-
3.9
6.1
-
6.1
Restructuring and other charges
0.6
-
0.6
1.7
-
1.7
Shareholder litigation expenses
0.6
-
0.6
1.4
-
1.4
Refinancing transaction costs (Q1 2014)
1.1
-
1.1
49.4
-
49.4
Debt redemption costs (9.0% Notes) (Q3 2015)
19.5
-
19.5
-
-
-
Adjusted Cash Flows from Operating
Activities
$105.3
$17.7
$123.0
$92.4
$49.9
$142.3
Term loan facility repayments (2)
(68.3)
-
(68.3)
(58.4)
-
(58.4)
Project-level debt repayments(3)
(15.1)
-
(15.1)
(11.7)
(6.4)
(18.1)
Purchases of property, plant and equipment (4)
(11.3)
-
(11.3)
(11.1)
(2.3)
(13.4)
Distributions to noncontrolling interests (5)
-
(3.7)
(3.7)
-
(11.0)
(11.0)
Dividends on preferred shares of a subsidiary company
(8.8)
-
(8.8)
(11.6)
-
(11.6)
Adjusted Free Cash Flow
$1.8
$14.0
$15.8
($0.3)
$30.2
$29.9
Additional GAAP cash flow measures:
Cash flows from investing activities
$333.7
($12.8)
$320.9
$73.5
($4.8)
$68.7
Cash flows from financing activities
($432.8)
($13.0)
($445.8)
($131.6)
($50.8)
($182.4)
(1) Represents difference between Project Adjusted EBITDA and cash distributions from equity method projects.
(2) Includes 1% mandatory annual amortization and 50% excess cash flow repayments by the Partnership.
(3) Excludes $8.1 million principal repayment at Piedmont on term loan conversion (February 2014).
(4) Excludes construction costs related to the Company's Canadian Hills project in 2014.
(5) Distributions to noncontrolling interests primarily include distributions, if any, to the tax equity investors at Canadian Hills and to the other 50% owner of Rockland. These projects were sold in June 2015.
Note: This table presents Project Adjusted EBITDA, Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies.
Atlantic Power Corporation
Table 12 – Project Adjusted EBITDA by Project (for Selected Projects)
(in millions of U.S. dollars)
Unaudited
Three months ended
December 31,
Twelve months ended
December 31,
2015
2014
2015
2014
East U.S.
Accounting
Cadillac
Consolidated
$2.7
$2.3
$8.8
$7.7
Curtis Palmer
Consolidated
8.9
7.3
29.8
31.5
Morris
Consolidated
3.2
3.1
16.5
12.7
Piedmont
Consolidated
(0.1)
2.5
7.6
6.7
Other (1)
Consolidated
0.8
0.5
3.2
3.7
Chambers
Equity method
3.3
4.5
17.0
18.6
Orlando
Equity method
5.4
5.4
22.0
15.4
Other (2)
Equity method
(0.2)
(1.4)
0.1
10.3
Total
23.8
24.1
104.8
106.4
West U.S.
Manchief
Consolidated
3.4
4.0
5.8
15.0
Naval Station
Consolidated
1.3
1.2
10.2
10.3
North Island
Consolidated
1.4
1.1
8.4
5.4
Other (3)
Consolidated
0.2
(0.6)
9.2
9.1
Frederickson
Equity method
3.3
3.3
12.5
12.2
Other (4)
Equity method
0.2
0.4
0.8
2.2
Total
9.8
9.4
46.9
54.2
Canada
Calstock
Consolidated
2.5
2.9
9.5
6.8
Kapuskasing
Consolidated
3.7
3.1
7.8
9.2
Nipigon
Consolidated
5.2
5.2
18.3
15.3
North Bay
Consolidated
3.6
3.6
7.2
10.5
Williams Lake
Consolidated
1.5
3.2
14.0
15.8
Other (5)
Consolidated
0.2
6.7
2.9
18.7
Total
16.7
24.7
59.7
76.3
Totals
Consolidated projects
38.4
46.0
159.1
178.4
Equity method projects
11.9
12.1
52.3
58.6
Un-allocated corporate
0.1
(1.3)
(2.5)
(7.5)
Total Project Adjusted EBITDA
$50.4
$56.9
$208.9
$229.4
Reconciliation to project income (loss)
Depreciation and amortization
$31.2
$35.3
$130.1
$155.9
Interest expense, net
2.1
2.4
9.8
20.5
Change in the fair value of derivative instruments
(6.7)
16.8
(15.4)
(6.2)
Impairment and other expense
128.1
0.2
125.8
98.1
Project income (loss)
($104.3)
$2.1
($41.4)
($38.9)
(1) Kenilworth
(2) Selkirk
(3) Naval Training Station and Oxnard
(4) Q4 2014: Koma Kulshan; FY 2014: Koma Kulshan and Delta-Person; Q4 and FY 2015: Koma Kulshan
(5) Tunis, Moresby Lake and Mamquam
Notes: Table 12 presents Project Adjusted EBITDA, which is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP; therefore, this measure may not be comparable to a similar measure presented by other companies. The Company has not reconciled non-GAAP financial measures relating to individual projects to the directly comparable GAAP measures due to the difficulty in making the relevant adjustments on an individual project basis.
To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/atlantic-power-corporation-releases-fourth-quarter-and-year-end-2015-results-300232049.html
SOURCE Atlantic Power Corporation
Copyright 2016 Canada NewsWire
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