Exhibit 99.1
Atlantic Power Corporation Releases Second Quarter 2017 Results
Second Quarter 2017 Financial Highlights
· Results included Cdn$32.8 million (US$24.7 million) of revenues from Global Adjustment settlement in Ontario
· Net loss of $(21.9) million in Q2 2017 vs. $(18.5) million in Q2 2016
· Project loss of $(12.1) million in Q2 2017 vs. project income of $25.2 million in Q2 2016
· Net loss and Project loss included $57.7 million of non-cash impairments for Chambers and Selkirk (equity-owned projects) in Q2 2017
· Project Adjusted EBITDA of $85.4 million in Q2 2017 vs. $46.2 million in Q2 2016
· Cash provided by operating activities of $50.9 million in Q2 2017 vs. $24.3 million in Q2 2016
· Repaid $29.5 million of term loan and project debt during Q2 2017; for full year 2017, expect to repay a total of $150 million or more, including $40 million of discretionary debt repayment
· Liquidity at June 30 of $227.2 million, including $104.4 million of unrestricted cash
Recent Developments
· Announced new seven-year tolling agreements with San Diego Gas & Electric for two projects in San Diego, Naval Station and North Island, subject to regulatory approval and retaining control of the two sites
DEDHAM, MASSACHUSETTS — August 3, 2017 — Atlantic Power Corporation (NYSE: AT) (TSX: ATP) (“Atlantic Power” or the “Company”) today reported its financial results for the three and six months ended June 30, 2017. Net loss attributable to Atlantic Power Corporation of $(21.9) million for the three months ended June 30, 2017 increased slightly from $(18.5) million in the year-ago period primarily because of non-cash impairment expense recorded at the Company’s equity-owned Chambers and Selkirk projects. Project Adjusted EBITDA, which does not include impairment expense, increased to $85.4 million from $46.2 million in the year-ago period, reflecting revenues received under the Global Adjustment settlement and the positive impact of the enhanced dispatch agreements and the expiration of an unfavorable fuel contract at North Bay and Kapuskasing (as discussed on page 2).
“This quarter’s results keep us on track to meet our 2017 guidance for Project Adjusted EBITDA and our expectation for Operating Cash Flow,” said James J. Moore, Jr., President and CEO of Atlantic Power. “The restructuring we began two and a half years ago has resulted in debt reduction of approximately one billion dollars and reduced corporate overhead and interest expense of $91 million annually. Our efforts to strengthen the balance sheet have resulted in significantly lower leverage and an improved debt maturity profile. We also have greater liquidity, which at June 30 totaled $227 million, including $104 million of unrestricted cash, of which $69 million is available for capital allocation, as compared to an enterprise value of approximately $1.3 billion and a market capitalization of approximately $270 million. We will continue to allocate available capital to debt reduction, common and preferred share repurchases and internal and external growth investments, based on price-to-value estimates both on an absolute and a relative basis.”
Mr. Moore continued, “We recently announced new offtake agreements for our Naval Station and North Island projects in San Diego. Although these contracts are subject to a couple of significant conditions, including approval of the California Public Utilities Commission and site control with the U.S. Navy, we were pleased to achieve this important milestone. We continue to work on arranging new contracts for other projects for which Power Purchase Agreements are expiring in 2018, and we hope to have more to report in the coming quarters.”
Atlantic Power Corporation
Table 1 — Summary of Financial Results
(in millions of U.S. dollars, except as otherwise stated)
Unaudited
|
|
|
Three months ended |
|
Six months ended |
| ||||||||
|
|
|
2017 |
|
2016 |
|
2017 |
|
2016 |
| ||||
|
Financial Highlights |
|
|
|
|
|
|
|
|
| ||||
|
Project revenue |
|
$ |
124.0 |
|
$ |
98.2 |
|
$ |
222.4 |
|
$ |
204.6 |
|
|
Project income |
|
(12.1 |
) |
25.2 |
|
13.2 |
|
53.9 |
| ||||
|
Net loss attributable to Atlantic Power Corporation |
|
(21.9 |
) |
(18.5 |
) |
(24.6 |
) |
(33.5 |
) | ||||
|
Cash provided by operating activities |
|
50.9 |
|
24.3 |
|
85.0 |
|
53.7 |
| ||||
|
Project Adjusted EBITDA |
|
85.4 |
|
46.2 |
|
149.3 |
|
108.7 |
| ||||
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 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.
Financial Results
Results for the second quarter of 2017 were significantly affected by changes to the operational and contractual status of the Kapuskasing, North Bay and Nipigon plants in Ontario, which commenced in January 2017, and the settlement of the Global Adjustment dispute with the Ontario Electricity Financial Corporation in April 2017 (the “OEFC Settlement”). In addition, the Company recorded significant impairments on two of its equity-owned projects in the second quarter, which affected project income and net income, although not cash flow or Project Adjusted EBITDA. These developments are discussed below.
Enhanced Dispatch Contracts
As previously reported, since the beginning of 2017, the Kapuskasing, North Bay and Nipigon plants have been under enhanced dispatch contracts that provide fixed monthly payments but do not require the plants to generate power. As a result, they have been in a non-operational state, which has resulted in operating and fuel cost savings relative to 2016, when the plants were operating and Kapuskasing and North Bay were purchasing gas under an above-market contract that expired at year-end 2016. The revenues received under these contracts were $6.5 million and $12.4 million lower in the three and six months ended June 30, 2017, respectively, than in the comparable year-ago periods, but this was more than offset by lower maintenance and fuel expenses.
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 was $3.9 million and $8.0 million for the three and six months ended June 30, 2017, respectively.
OEFC Settlement
As discussed in the Company’s May 4, 2017 press release, in April 2017 the OEFC agreed to pay the Company a total of approximately Cdn$36 million in settlement of the Global Adjustment dispute, which was related to power sold to the OEFC under the Power Purchase Agreements (“PPAs”) for the Kapuskasing, North Bay and Tunis projects. The Company received Cdn$11.0 million of this amount in the first quarter of 2017, consisting of Cdn$8.7 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. During the second quarter of 2017, the Company received another Cdn$21.8 million, consisting of Cdn$20.3 million for power sold by the three plants in April 2013 through year-end 2015 and another Cdn$1.4 million under the enhanced dispatch contracts for Kapuskasing and North Bay for the second quarter of 2017. The remaining Cdn$3.6 million will be received as earned under the enhanced dispatch contracts for the Kapuskasing and North Bay projects over the balance of 2017.
The Cdn$11.0 million received in the first quarter of 2017 was recorded as deferred revenue and therefore did not benefit net income or Project Adjusted EBITDA for the quarter. In the second quarter of 2017, the Company reversed this deferral and included the amount in revenues. Thus, the total amount associated with the OEFC settlement included in revenues in the second quarter was Cdn$32.8 million, which resulted in a US$24.7 million benefit to Project Adjusted EBITDA for the second quarter of 2017.
Impairment of Selkirk and Chambers
The Company owns a 17.7% limited partner interest in Selkirk, which has been operating as a merchant facility since its PPA expired in August 2014. During that time the Company has not received any distributions from the project. Based on the project’s history of making no cash distributions while operating as a merchant facility, the short-term and long-term operational forecast, as well as the likelihood that further investment will be required to operate the facility, the Company determined that its investment in Selkirk is impaired and the decline in value is other than temporary. Accordingly, during the second quarter of 2017, the Company recorded a $10.6 million full impairment of its investment.
The Company owns a 40% limited partner interest in Chambers, which is a coal-fired project operating under a PPA that expires in March 2024. During the second quarter of 2017, the Company performed an analysis of the value of the project on the assumption that it operated as a merchant facility after the PPA expires. Although declining power prices have been observed for several years, in the Company’s most recent long-term forecast, it identified a significant decrease in the long-term outlook for power, gas and coal prices for the region in which the project operates, which had a significant negative impact on the estimated discounted cash flows of Chambers post-PPA. These discounted cash flows represent a significant component of the overall value of the project compared to its carrying value. Accordingly, during the second quarter of 2017, the Company recorded a $47.1 million impairment of its $124.3 million investment in Chambers, reducing the carrying value to $77.2 million.
Total impairment expense of $57.7 million for the three and six months ended June 30, 2017 was recorded in earnings from unconsolidated affiliates and reduced both Project income and Net income, but did not affect cash from operating activities or Project Adjusted EBITDA.
Three Months Ended June 30, 2017
Net loss attributable to Atlantic Power Corporation for the second quarter of 2017 was $(21.9) million as compared to $(18.5) million in the second quarter of 2016. Results benefited from increased revenues of $25.8 million (primarily the result of the OEFC settlement and improved hydrology at Curtis Palmer), lower fuel and operations and maintenance expenses totaling $17.8 million (primarily the result of the enhanced dispatch contracts and the expiration of an above-market gas supply contract in Ontario), and lower interest expense of $33.0 million (due to a $31.4 million write-off of deferred financing costs in the second quarter of 2016 and lower debt levels). These positive factors were more than offset by the impairment expense of $57.7 million, increased depreciation expense of $4.0 million and a $14.9 million negative change in the fair value of derivative instruments (non-cash).
Project loss for the second quarter of 2017 was $(12.1) million as compared to project income in the year-ago period of $25.2 million. The $37.3 million reduction was primarily attributable to the $57.7 million impairment expense, $(14.9) million change in fair value of derivative instruments and increased depreciation expense, partially offset by increased revenues and lower fuel and operations and maintenance expense as discussed previously.
Project Adjusted EBITDA for the second quarter of 2017 was $85.4 million, an increase of $39.2 million from $46.2 million in the year-ago period. Primary drivers were the OEFC settlement discussed previously ($24.7 million), the favorable impact on margins of the enhanced dispatch contracts and the expiration of an above-market gas contract in Ontario (totaling $10.8 million), improved hydrology at Curtis Palmer ($6.5 million), and more modest increases at Williams Lake and Piedmont (each $1.3 million). These positive factors were partially offset by decreases at Frederickson (-$2.7 million), due to expenses associated with a major maintenance outage, Mamquam (-$1.7 million), due to a forced outage and lower water flows, and Calstock (-$1.2 million), due to lower waste heat and higher fuel costs. During the quarter, the Canadian dollar declined modestly relative to year-ago period, which had a non-cash translation impact on Project Adjusted EBITDA of approximately $(2.0) million.
Cash provided by operating activities for the second quarter of 2017 of $50.9 million increased $26.6 million from the $24.3 million a year ago. The 2017 period included approximately $16.4 million of cash collected under the OEFC settlement (the other $8 million was received in the first quarter). Other factors that positively affected cash flow included the benefit to gross margin from the revised contractual, operating and fuel supply arrangements for Kapuskasing, North Bay and Nipigon, as previously discussed, improved hydrology at Curtis Palmer and a $4.2 million reduction in cash interest payments due to lower debt balances and a reduced spread on the term loan (effective April 2017). These positive factors were partially offset by decreases at Frederickson and Mamquam, for reasons previously discussed.
Significant uses of cash provided by operating activities during the second quarter of 2017 included $27.1 million of term loan amortization, $2.4 million of project debt amortization and $2.2 million of preferred dividend payments. The Company also used $2.2 million of cash for capital expenditures.
Six Months Ended June 30, 2017
Net loss attributable to Atlantic Power Corporation for the six months ended June 30, 2017 was $(24.6) million as compared to $(33.5) million in the six months ended June 30, 2016. The $8.9 million reduction in loss was the result of several positive factors, including increased revenues of $17.8 million (primarily the result of the OEFC settlement and improved hydrology at Curtis Palmer, partially offset by lower revenues under the enhanced dispatch contracts), lower fuel and operations and maintenance expenses totaling $28.7 million (primarily the result of the enhanced dispatch contracts and expiration of an above-market gas supply contract in Ontario), and lower interest expense of $32.2 million (due to a $31.4 million write-off of deferred financing costs in the second quarter of 2016 and lower debt levels). These positive factors were more than offset by the $57.7 million impairment expense, increased depreciation of $8.7 million, a $14.9 million negative change in the fair value of derivative instruments (non-cash) and a $14.2 million reduction in foreign exchange loss. The reduction in foreign exchange loss was primarily due to a $14.7 million decrease in unrealized loss in the revaluation of instruments denominated in Canadian dollars, stemming from the repurchase and cancellation of Cdn$152.1 million Canadian dollar-denominated convertible debentures in the second quarter of 2016.
Project income for the six months ended June 30, 2017 declined to $13.2 million from $53.9 million in the year-ago period. The $40.7 million reduction was primarily attributable to the $57.7 million impairment expense, $(7.1) million change in fair value of derivative instruments and increased depreciation expense, partially offset by increased revenues and lower fuel and operations and maintenance expense as discussed previously.
Project Adjusted EBITDA for the six months ended June 30, 2017 was $149.3 million, an increase of $40.6 million from $108.7 million in the year-ago period. Primary drivers were the OEFC settlement ($24.7 million), the favorable impact on margins of the enhanced dispatch contracts and the expiration of an above-market gas contract in Ontario (totaling $17.6 million), improved hydrology at Curtis Palmer ($6.5 million), and more modest increases at Piedmont ($1.9 million) and Orlando ($1.7 million). These positive factors were partially offset by decreases at Morris (-$5.0 million), primarily due to higher fuel prices, lower energy and capacity prices and the non-recurrence of a return on a construction project in the first quarter of 2016; Mamquam (-$3.6 million), due to a forced outage in the second quarter of 2017 and lower water flows as compared to a record year in 2016; Calstock (-$2.5 million), due to lower waste heat and higher fuel prices; and Frederickson (-$2.3 million), due to a major maintenance outage in the second quarter of 2017. During the first six months of 2017, the Canadian dollar appreciated slightly relative to the year-ago period but the impact on Project Adjusted EBITDA was immaterial.
Cash provided by operating activities for the six months ended June 30, 2017 of $85.0 million increased $31.3 million from the $53.7 million a year ago. The 2017 period included approximately $24.7 million of cash collected under the OEFC settlement. Other factors that positively affected cash flow included the benefit to gross margin from the revised contractual, operating and fuel supply arrangements for Kapuskasing, North Bay and Nipigon, as previously discussed, improved hydrology at Curtis Palmer and a $1.3 million reduction in cash interest payments due to lower debt balances and a reduced spread on the term loan (effective April 2017). These positive factors were partially offset by decreases at Morris, Frederickson, Mamquam and Calstock, for reasons previously discussed.
Significant uses of cash provided by operating activities during the six months ended June 30, 2017 included $52.1 million of term loan amortization, $4.7 million of project debt amortization and $4.3 million of preferred dividend payments. The Company also used $4.2 million of cash for capital expenditures, primarily for the upgrade of the third and final combustion turbine at Morris.
Liquidity and Balance Sheet
Liquidity
As shown in Table 2, the Company’s liquidity at June 30, 2017 was $227.2 million, an increase of approximately $13 million from the March 31, 2017 level. The increase was attributable to an increase in unrestricted cash, to $104.4 million from $91.5 million in the previous period. The unrestricted cash of $104.4 million includes $78.6 million at the parent, of which the Company considers approximately $69 million to be discretionary cash available for general corporate purposes.
Atlantic Power Corporation
Table 2 — Liquidity (in millions of U.S. dollars)
Unaudited
|
|
|
June 30, |
|
March 31, |
| ||
|
Cash and cash equivalents, parent |
|
$ |
78.6 |
|
$ |
65.6 |
|
|
Cash and cash equivalents, projects |
|
25.8 |
|
25.9 |
| ||
|
Total cash and cash equivalents |
|
104.4 |
|
91.5 |
| ||
|
|
|
|
|
|
| ||
|
Revolving credit facility |
|
200.0 |
|
91.5 |
| ||
|
Letters of credit outstanding |
|
(77.2 |
) |
(77.5 |
) | ||
|
Availability under revolving credit facility |
|
122.8 |
|
122.5 |
| ||
|
Total liquidity |
|
$ |
227.2 |
|
$ |
214.0 |
|
Note: Liquidity numbers presented do not include restricted cash of $14.1 million at June 30, 2017 and $10.0 million at March 31, 2017.
Balance Sheet
Debt Repayment
During the second quarter of 2017, the Company repaid $27.1 million of the APLP Holdings term loan and amortized $2.4 million of project-level debt. For the first six months of 2017, the Company repaid a total of $52.1 million of the term loan and amortized $4.7 million of project-level debt. At June 30, 2017, the Company’s consolidated debt was $947 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 4.4 times at June 30, 2017. The improvement in the leverage ratio from 5.4 times at March 31, 2017 was primarily attributable to the positive impacts on EBITDA of the OEFC settlement payments (recorded in the second quarter) and the enhanced dispatch contracts (for the past two quarters) combined with the continued reduction in debt.
For the full year 2017, the Company expects to repay $100 million of its APLP Holdings term loan (including the $52.1 million repaid in the first half of the year) and $11.8 million of project-level debt (including the $4.7 million amortized in the first half). 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). This would put total debt repayment for the year at $150 million or more.
Debt Maturity Profile
The Company has no bullet maturities in 2017. In 2018, the Company has a project debt maturity at Piedmont totaling $54.2 million at its August 2018 maturity date. The remaining $42.5 million of Series C convertible debentures mature in June 2019 and became callable at par in June 2017. The $62.4 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
As reported in the Company’s April 17, 2017 press release, the Company executed a repricing of the APLP Holdings term loan and revolving credit facility, reducing the interest rate margin on the term loan and revolver by 75 basis points, to LIBOR plus 425 basis points. Transaction costs associated with the repricing of $1.1 million were included in interest expense in the second quarter of 2017.
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 (in January 2017) and no common shares under this NCIB. In July 2017, the Company repurchased and cancelled 171,612 shares of the 4.85% Cumulative Redeemable Preferred (Series I issue) at Cdn$15.5 per share for a total payment of Cdn$2.7 million.
Reaffirming 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 not changed its 2017 guidance for Project Adjusted EBITDA of $250 to $265 million. 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
|
2017 Project Adjusted EBITDA Guidance(1) |
|
$250 - $265 |
|
|
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 |
|
$155 - $170 |
|
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 on May 4, 2017.
(2) For equity method projects, represents difference between Project Adjusted EBITDA and cash distribution from equity method projects.
Other Financial Updates
Update on San Diego PPAs
As previously disclosed, the Company has three projects in San Diego that sell power to San Diego Gas & Electric (“SDG&E”) under PPAs that are scheduled to expire in December 2019. The Company also supplies steam from these projects to the U.S. Navy under agreements that provide the Company with the right to use the property at the respective sites on which each project is located. Those agreements are scheduled to expire in February 2018.
As discussed in the Company’s August 1, 2017 press release, the Company has executed new seven-year Power Purchase Tolling Agreements (“PPTAs”) with SDG&E for its Naval Station and North Island projects. The PPTAs are subject to significant conditions precedent, including the approval of the California Public Utilities Commission (“CPUC”), which could take approximately four months or longer, and the Company’s ability to continue using the property at the respective sites. The Company has submitted a detailed proposal in a solicitation by the U.S. Navy for energy security and resiliency at these two sites, but the timeframe for resolution of this process is uncertain. If successful in the solicitation, the Company would retain the right to use the property. Subject to meeting the conditions precedent, deliveries under the PPTAs would commence as early as February 2018. The Project Adjusted EBITDA of the two projects under the PPTAs is estimated to be approximately $6 million annually on a combined basis as compared to approximately $16 million under the existing PPAs in 2017.
The Company continues to pursue contractual arrangements for its Naval Training Center (“NTC”) project in San Diego, which also would be subject to retaining control of the respective site and regulatory approval. NTC is expected to generate approximately $4 million of Project Adjusted EBITDA in 2017.
Maintenance and Capex
For 2017, including its share of equity-owned projects, the Company expects to incur maintenance expenses of approximately $41 million (modestly lower than the 2016 level), which includes an estimate of the cost to prepare Tunis for a return to service in 2018 under its PPA. Approximately $17.8 million of maintenance expense was incurred in the first six months of 2017. The Company’s estimate of capital expenditures for 2017 is approximately $5.5 million (slightly lower than the 2016 level). Approximately $4.8 million was incurred in the first six months of 2017, most of it related to the recently completed upgrade of the third and final combustion turbine at Morris.
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 13 of this release.
Investor Conference Call and Webcast
Atlantic Power’s management team will host a telephone conference call on Friday, August 4, 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, August 4, 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 10110155 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 September 4, 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.
|
************************************************************************************************************************ |
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 with respect to progress on PPAs expiring in 2018;
· the Company’s expectation that it will receive another Cdn$3.6 million of Global Adjustment revenues under the OEFC settlement over the remainder of 2017;
· the Company’s estimate of discretionary cash ($69 million) and its plans to allocate approximately $40 million or more to discretionary debt repayment in 2017;
· the Company’s estimate of an enterprise value ($1.3 billion);
· the Company’s expectation to allocate available capital to debt reduction, common and preferred share repurchases (and internal and external growth investments), based on price-to-value estimates both on an absolute and relative basis;
· the Company’s expectation that it will repay $100 million of its APLP Holdings term loan and $11.8 million of project-level debt for the full year 2017;
· the Company’s expectation that it will repay $150 million or more of debt 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 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;
· the Company’s ability to satisfy certain conditions relating to the PPTAs, including obtaining the approval of the CPUC and retaining site control at Naval Station and North Island;
· the expected timeline for obtaining CPUC approval;
· the Company’s expectations with respect to the level of Project Adjusted EBITDA that Naval Station, North Island and NTC will generate in 2017;
· the Company’s expectations with respect to the level of Project Adjusted EBITDA that Naval Station and North Island may generate under the PPTAs;
· the Company’s expectation that in 2017, including its share of equity-owned projects, capital expenditures will total approximately $5.5 million and maintenance expense will total approximately $41 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)
Unaudited
|
|
|
June 30, |
|
December 31, |
| ||
|
|
|
2017 |
|
2016 |
| ||
|
Assets |
|
|
|
|
| ||
|
Current assets: |
|
|
|
|
| ||
|
Cash and cash equivalents |
|
$ |
104.4 |
|
$ |
85.6 |
|
|
Restricted cash |
|
14.1 |
|
13.3 |
| ||
|
Accounts receivable |
|
42.3 |
|
37.3 |
| ||
|
Current portion of derivative instruments asset |
|
2.8 |
|
4.0 |
| ||
|
Inventory |
|
19.5 |
|
16.0 |
| ||
|
Prepayments |
|
7.2 |
|
5.9 |
| ||
|
Income taxes receivable |
|
0.5 |
|
— |
| ||
|
Other current assets |
|
2.9 |
|
2.8 |
| ||
|
Total current assets |
|
193.7 |
|
164.9 |
| ||
|
|
|
|
|
|
| ||
|
Property, plant and equipment, net |
|
705.8 |
|
733.2 |
| ||
|
Equity investments in unconsolidated affiliates |
|
204.2 |
|
266.8 |
| ||
|
Power purchase agreements and intangible assets, net |
|
227.4 |
|
246.2 |
| ||
|
Goodwill |
|
36.0 |
|
36.0 |
| ||
|
Derivative instruments asset |
|
2.8 |
|
4.6 |
| ||
|
Other assets |
|
4.2 |
|
5.1 |
| ||
|
Total assets |
|
$ |
1,374.1 |
|
$ |
1,456.8 |
|
|
|
|
|
|
|
| ||
|
Liabilities |
|
|
|
|
| ||
|
Current liabilities: |
|
|
|
|
| ||
|
Accounts payable |
|
$ |
3.3 |
|
$ |
4.5 |
|
|
Accrued interest |
|
2.0 |
|
0.7 |
| ||
|
Other accrued liabilities |
|
23.9 |
|
24.4 |
| ||
|
Current portion of long-term debt |
|
106.9 |
|
111.9 |
| ||
|
Current portion of derivative instruments liability |
|
6.3 |
|
7.6 |
| ||
|
Other current liabilities |
|
3.0 |
|
1.8 |
| ||
|
Total current liabilities |
|
145.4 |
|
150.9 |
| ||
|
|
|
|
|
|
| ||
|
Long-term debt (1) |
|
707.6 |
|
749.2 |
| ||
|
Convertible debentures (2) |
|
102.8 |
|
100.4 |
| ||
|
Derivative instruments liability |
|
24.4 |
|
21.3 |
| ||
|
Deferred income taxes |
|
43.6 |
|
68.3 |
| ||
|
Power purchase and fuel supply agreement liabilities, net |
|
24.7 |
|
25.3 |
| ||
|
Other long-term liabilities |
|
56.3 |
|
55.5 |
| ||
|
Total liabilities |
|
$ |
1,104.8 |
|
$ |
1,170.9 |
|
|
|
|
|
|
|
| ||
|
Equity |
|
|
|
|
| ||
|
Common shares, no par value, unlimited authorized shares; 115,280,908 and 114,649,888 issued and outstanding at June 30, 2017 and December 31, 2016, respectively |
|
1,274.0 |
|
1,272.9 |
| ||
|
Accumulated other comprehensive loss |
|
(141.6 |
) |
(148.5 |
) | ||
|
Retained deficit |
|
(1,084.4 |
) |
(1,059.8 |
) | ||
|
Total Atlantic Power Corporation shareholders’ equity |
|
48.0 |
|
64.6 |
| ||
|
Preferred shares issued by a subsidiary company |
|
221.3 |
|
221.3 |
| ||
|
Total equity |
|
269.3 |
|
285.9 |
| ||
|
Total liabilities and equity |
|
$ |
1,374.1 |
|
$ |
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 |
|
Six months ended |
| ||||||||
|
|
|
2017 |
|
2016 |
|
2017 |
|
2016 |
| ||||
|
Project revenue: |
|
|
|
|
|
|
|
|
| ||||
|
Energy sales |
|
$ |
40.0 |
|
$ |
45.1 |
|
$ |
77.1 |
|
$ |
97.6 |
|
|
Energy capacity revenue |
|
28.3 |
|
37.3 |
|
47.8 |
|
69.2 |
| ||||
|
Other |
|
55.7 |
|
15.8 |
|
97.5 |
|
22.0 |
| ||||
|
|
|
124.0 |
|
98.2 |
|
222.4 |
|
204.6 |
| ||||
|
Project expenses: |
|
|
|
|
|
|
|
|
| ||||
|
Fuel |
|
24.0 |
|
35.1 |
|
52.9 |
|
74.0 |
| ||||
|
Operations and maintenance |
|
23.3 |
|
30.0 |
|
43.6 |
|
51.2 |
| ||||
|
Depreciation and amortization |
|
29.5 |
|
25.5 |
|
59.0 |
|
50.3 |
| ||||
|
|
|
76.8 |
|
90.6 |
|
155.5 |
|
175.5 |
| ||||
|
Project other income: |
|
|
|
|
|
|
|
|
| ||||
|
Change in fair value of derivative instruments |
|
(2.7 |
) |
12.2 |
|
(3.9 |
) |
11.0 |
| ||||
|
Equity in (loss) earnings of unconsolidated affiliates |
|
(54.4 |
) |
7.6 |
|
(45.4 |
) |
18.3 |
| ||||
|
Interest expense, net |
|
(2.2 |
) |
(2.4 |
) |
(4.4 |
) |
(4.5 |
) | ||||
|
Other income, net |
|
— |
|
0.2 |
|
— |
|
— |
| ||||
|
|
|
(59.3 |
) |
17.6 |
|
(53.7 |
) |
24.8 |
| ||||
|
Project (loss) income |
|
(12.1 |
) |
25.2 |
|
13.2 |
|
53.9 |
| ||||
|
Administrative and other expenses: |
|
|
|
|
|
|
|
|
| ||||
|
Administration |
|
5.7 |
|
5.8 |
|
12.1 |
|
11.9 |
| ||||
|
Interest expense, net |
|
18.4 |
|
51.2 |
|
35.7 |
|
67.8 |
| ||||
|
Foreign exchange loss |
|
5.9 |
|
2.6 |
|
8.3 |
|
22.5 |
| ||||
|
Other income (expense), net |
|
— |
|
0.3 |
|
— |
|
(2.2 |
) | ||||
|
|
|
30.0 |
|
59.9 |
|
56.1 |
|
100.0 |
| ||||
|
Loss from operations before income taxes |
|
(42.1 |
) |
(34.7 |
) |
(42.9 |
) |
(46.1 |
) | ||||
|
Income tax benefit |
|
(22.3 |
) |
(18.4 |
) |
(22.6 |
) |
16.8 |
| ||||
|
Net loss |
|
(19.8 |
) |
(16.3 |
) |
(20.3 |
) |
(29.3 |
) | ||||
|
Net income attributable to preferred share dividends of a subsidiary company |
|
2.1 |
|
2.2 |
|
4.3 |
|
4.2 |
| ||||
|
Net loss attributable to Atlantic Power Corporation |
|
$ |
(21.9 |
) |
$ |
(18.5 |
) |
$ |
(24.6 |
) |
$ |
(33.5 |
) |
|
Net loss per share attributable to Atlantic Power Corporation shareholders: |
|
|
|
|
|
|
|
|
| ||||
|
Basic |
|
$ |
(0.19 |
) |
$ |
(0.15 |
) |
$ |
(0.21 |
) |
$ |
(0.28 |
) |
|
Diluted |
|
(0.19 |
) |
(0.15 |
) |
(0.21 |
) |
(0.28 |
) | ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Weighted average number of common shares outstanding: |
|
|
|
|
|
|
|
|
| ||||
|
Basic |
|
115.2 |
|
121.6 |
|
115.0 |
|
121.8 |
| ||||
|
Diluted |
|
115.2 |
|
121.6 |
|
115.0 |
|
121.8 |
| ||||
Atlantic Power Corporation
Table 6 — Consolidated Statements of Cash Flows (in millions of U.S. dollars)
Unaudited
|
|
|
Six months ended June 30, |
| ||||
|
|
|
2017 |
|
2016 |
| ||
|
Cash provided by operating activities: |
|
|
|
|
| ||
|
Net loss |
|
$ |
(20.3 |
) |
$ |
(29.3 |
) |
|
Adjustments to reconcile net loss to net cash provided by operating activities: |
|
|
|
|
| ||
|
Depreciation and amortization |
|
59.0 |
|
50.3 |
| ||
|
Gain on purchase and cancellation of convertible debentures |
|
— |
|
(2.5 |
) | ||
|
Loss on sale of assets |
|
— |
|
0.2 |
| ||
|
Stock-based compensation expense |
|
1.1 |
|
0.8 |
| ||
|
Equity in loss (earnings) from unconsolidated affiliates |
|
45.4 |
|
(18.3 |
) | ||
|
Distributions from unconsolidated affiliates |
|
17.2 |
|
23.5 |
| ||
|
Unrealized foreign exchange loss |
|
8.3 |
|
22.5 |
| ||
|
Change in fair value of derivative instruments |
|
3.9 |
|
(11.0 |
) | ||
|
Amortization of debt discount and deferred financing costs |
|
5.2 |
|
37.5 |
| ||
|
Change in deferred income taxes |
|
(24.9 |
) |
(18.6 |
) | ||
|
Change in other operating balances |
|
|
|
|
| ||
|
Accounts receivable |
|
(5.0 |
) |
(3.3 |
) | ||
|
Inventory |
|
(3.4 |
) |
(0.4 |
) | ||
|
Prepayments and other assets |
|
(0.3 |
) |
1.7 |
| ||
|
Accounts payable |
|
(1.4 |
) |
3.5 |
| ||
|
Accruals and other liabilities |
|
0.2 |
|
(2.9 |
) | ||
|
Cash provided by operating activities |
|
85.0 |
|
53.7 |
| ||
|
|
|
|
|
|
| ||
|
Cash (used in) provided by investing activities: |
|
|
|
|
| ||
|
Change in restricted cash |
|
(0.8 |
) |
0.9 |
| ||
|
Reimbursement of costs for third-party construction project |
|
— |
|
4.7 |
| ||
|
Purchase of property, plant and equipment |
|
(4.2 |
) |
(2.0 |
) | ||
|
Cash (used in) provided by investing activities |
|
(5.0 |
) |
3.6 |
| ||
|
|
|
|
|
|
| ||
|
Cash (used in) provided by financing activities: |
|
|
|
|
| ||
|
Proceeds from term loan facility, net of discount |
|
— |
|
679.0 |
| ||
|
Common share repurchases |
|
— |
|
(4.7 |
) | ||
|
Repayment of corporate and project-level debt |
|
(56.9 |
) |
(502.7 |
) | ||
|
Repayment of convertible debentures |
|
— |
|
(127.0 |
) | ||
|
Deferred financing costs |
|
— |
|
(15.9 |
) | ||
|
Dividends paid to preferred shareholders |
|
(4.3 |
) |
(4.2 |
) | ||
|
Cash (used in) provided by financing activities |
|
(61.2 |
) |
24.5 |
| ||
|
|
|
|
|
|
| ||
|
Net increase in cash and cash equivalents |
|
18.8 |
|
81.8 |
| ||
|
Cash and cash equivalents at beginning of period |
|
85.6 |
|
72.4 |
| ||
|
Cash and cash equivalents at end of period |
|
$ |
104.4 |
|
$ |
154.2 |
|
|
|
|
|
|
|
| ||
|
Supplemental cash flow information |
|
|
|
|
| ||
|
Interest paid |
|
$ |
33.4 |
|
$ |
34.7 |
|
|
Income taxes paid, net |
|
$ |
2.2 |
|
$ |
1.9 |
|
|
Accruals for construction in progress |
|
$ |
1.3 |
|
$ |
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 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 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 second quarter 2017 presentation on the Company’s website.
Project income (loss) and Project Adjusted EBITDA by project also can be found in the second 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 |
|
Six months ended |
| ||||||||
|
|
|
2017 |
|
2016 |
|
2017 |
|
2016 |
| ||||
|
Net loss attributable to Atlantic Power Corporation |
|
$ |
(21.9 |
) |
$ |
(18.5 |
) |
$ |
(24.6 |
) |
$ |
(33.5 |
) |
|
Net income attributable to preferred share dividends of a subsidiary company |
|
2.1 |
|
2.2 |
|
4.3 |
|
4.2 |
| ||||
|
Net loss from operations |
|
$ |
(19.8 |
) |
$ |
(16.3 |
) |
$ |
(20.3 |
) |
$ |
(29.3 |
) |
|
Income tax benefit |
|
(22.3 |
) |
(18.4 |
) |
(22.6 |
) |
(16.8 |
) | ||||
|
Loss from operations before income taxes |
|
(42.1 |
) |
(34.7 |
) |
(42.9 |
) |
(46.1 |
) | ||||
|
Administration |
|
5.7 |
|
5.8 |
|
12.1 |
|
11.9 |
| ||||
|
Interest expense, net |
|
18.4 |
|
51.2 |
|
35.7 |
|
67.8 |
| ||||
|
Foreign exchange loss |
|
5.9 |
|
2.6 |
|
8.3 |
|
22.5 |
| ||||
|
Other expense (income), net |
|
— |
|
0.3 |
|
— |
|
(2.2 |
) | ||||
|
Project (loss) income |
|
$ |
(12.1 |
) |
$ |
25.2 |
|
$ |
13.2 |
|
$ |
53.9 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
Reconciliation to Project Adjusted EBITDA |
|
|
|
|
|
|
|
|
| ||||
|
Depreciation and amortization |
|
$ |
34.7 |
|
$ |
30.4 |
|
$ |
69.3 |
|
$ |
60.3 |
|
|
Interest expense, net |
|
2.5 |
|
2.9 |
|
5.3 |
|
5.4 |
| ||||
|
Change in the fair value of derivative instruments |
|
2.6 |
|
(12.2 |
) |
3.8 |
|
(11.0 |
) | ||||
|
Other (income) expense |
|
— |
|
(0.1 |
) |
— |
|
0.1 |
| ||||
|
Impairment |
|
57.7 |
|
— |
|
57.7 |
|
— |
| ||||
|
Project Adjusted EBITDA |
|
$ |
85.4 |
|
$ |
46.2 |
|
$ |
149.3 |
|
$ |
108.7 |
|