Atlantic Power Corporation Releases Third Quarter 2015 Results

DEDHAM, Mass., Nov. 5, 2015 /CNW/ -- Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the "Company") today released its results for the three and nine months ended September 30, 2015. 

Third Quarter 2015 Financial Highlights

  • Completed the redemption of $310.9 million outstanding principal amount of 9.0% Senior Unsecured Notes due 2018 (the 9.0% Notes) in July
  • Amortized $14 million of term loan and project debt in third quarter; for the year to date, debt amortization, repurchases and redemptions total approximately $409 million
  • Q3 2015 Project income of $24 million vs. project loss of $(65) million in Q3 2014 (results exclude the wind businesses, which are included in discontinued operations); increase was mostly due to $92 million of asset and goodwill impairment expense in 2014 that did not recur in 2015
  • Q3 2015 Project Adjusted EBITDA of $56 million vs. $58 million in Q3 2014 (results exclude $0 million and $14 million, respectively, from the wind businesses)
  • Q3 2015 Cash flows from operating activities of $14.5 million vs. $40 million in Q3 2014 (including $0 million and $11 million, respectively, from the wind businesses); decrease was primarily attributable to the sale of the wind businesses and $19.5 million of costs associated with the redemption of the 9.0% Notes, both in 2015
  • Q3 2015 Adjusted Cash Flows from Operating Activities, which excludes discontinued operations, changes in working capital, severance and other restructuring charges, and debt prepayment or redemption costs, decreased to $39 million from $44 million in Q3 2014
  • Q3 2015 Adjusted Free Cash Flow of $18 million was after $14 million of term loan and project debt repayment and $4 million of capital expenditures and declined slightly from $20 million in Q3 2014

2015 Guidance

  • No change to Project Adjusted EBITDA guidance of $200 to $215 million
  • Raised lower end of Adjusted Cash Flows from Operating Activities guidance to a range of $95 to $105 million (had been $90 to $105 million), mostly due to lower expected G&A and cash interest payments
  • No change to Adjusted Free Cash Flow guidance of $0 to $10 million
  • Expect 2015 corporate G&A expense of approximately $32 million vs. $35 million previously; on track for $28 million or lower in 2016 (48% reduction from 2013)
  • Optimization initiatives expected to produce approximately $6 million of cash flow benefit in 2015 (in line with previous estimate of $4 to $8 million) and approximately $10 million in 2016

Recent Developments

  • Lead plaintiff in U.S. securities class action suit dropped appeal in late October; both sides jointly stipulated to dismissal of the appeal with prejudice; awaiting court approval
  • Moody's upgraded the Company's corporate family credit rating in mid-October to B1 from B2
  • CEO and directors purchased 185,000 common shares of the Company during the third quarter at an average price of $2.23, following purchases in the second quarter of more than 380,000 shares at an average price of $3.09

"We have made significant progress in strengthening the Company's financial position, including reducing our debt by more than $800 million in the past seven quarters through the sale of our wind businesses at an attractive valuation, the redemption of our highest-cost debt, ongoing amortization of our term loan and project debt as well as discretionary debt repurchases.  As a result, we have reduced our cash interest payments by approximately half.  These actions have improved our credit profile, which was recognized in a recent upgrade of our corporate credit rating," said James J. Moore, President and Chief Executive Officer of Atlantic Power.  "We continue to evaluate opportunities to reshape our remaining US$292 million of corporate debt maturities in 2017 and 2019.  In addition, we have streamlined our organizational structure, reducing our overhead costs by nearly half from 2013 through the expected level for 2016."

"We have been investing in our own fleet at returns superior to those available in the external market and with much lower risk, and already are realizing incremental cash flow from these projects.  Going forward, we see the potential for larger investments in conjunction with possible extensions of existing Power Purchase Agreements (PPAs)," continued Mr. Moore.  "The progress we have made in improving our financial risk profile allows us to move from a primarily defensive strategy to one that is more balanced, including continuing to make attractive investments in our projects while also pursuing capital-efficient, disciplined external growth.  We also see investment opportunities in our own capital structure, although our primary focus will be on additional delevering in order to further improve our credit profile."

 

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,


2015

2014

2015

2014

Excluding results from discontinued operations(1)





Project revenue

$107.5

$121.6

$321.8

$370.0

Project income (loss)

24.2

(65.1)

63.0

(41.0)

Project Adjusted EBITDA

56.0

58.1

158.5

172.6

Cash Distributions from Projects

51.5

40.8

146.3

152.4

Adjusted Cash Flows from Operating Activities

38.7

44.2

77.7

74.6

Adjusted Free Cash Flow

18.1

20.1

(5.7)

1.1

Aggregate power generation (thousands of Net MWh)

1,659.0

1,649.6

4,673.8

4,806.8

Weighted average availability

94.3%

94.3%

93.5%

91.6%

Including results from discontinued operations (1)





Cash flows from operating activities

$14.5

$40.4

$67.7

$45.9

Free Cash Flow

(6.1)

12.6

(19.5)

(48.4)

Results of discontinued operations





Project Adjusted EBITDA

$-

$14.1

$28.3

$49.0

Cash Distributions from Projects

-

10.5

7.3

35.3

Cash flows from operating activities

-

10.8

21.9

36.9

(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 nine months ended September 30, 2015 and 2014.  Greeley was sold in March 2014 and is included as a component of discontinued operations for the nine months ended September 30, 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.   

 

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 9 through 12 for reconciliations of these non-GAAP measures to GAAP measures.








 

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" attached to 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.

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 September 30, 2015

Project availability was 94.3% in the third quarter of 2015, unchanged from the year-ago period.  Increased availability at Nipigon, which had a maintenance outage in the comparable 2014 period, was offset by lower availability at Mamquam, which had a scheduled maintenance outage in the third quarter of 2015.  (The 2015 availability figure excludes Tunis, which has been mothballed since February 2015 following the expiration of its PPA in December 2014.)

Generation increased 0.6% in the third quarter of 2015 from the year-ago period, primarily due to Frederickson, which had increased dispatch as a result of warmer weather and reduced hydro availability in the region as compared to 2014, and Nipigon, which had a maintenance outage in the third quarter of 2014.  These increases were partially offset by decreases at Tunis, due to the expiration of its PPA, and at Mamquam, which had a scheduled maintenance outage in the third quarter of 2015. 

Nine Months Ended September 30, 2015

Project availability increased to 93.5% in the nine months ended Sept. 30, 2015 from 91.6% in the comparable period in 2014.  Increased availability at Chambers, Orlando, Nipigon and North Island, all of which had maintenance outages in 2014, more than offset decreased availability at Manchief and Mamquam, which had scheduled maintenance outages in 2015.  (The 2015 availability figure excludes Tunis.) 

Generation decreased 2.8% in the nine months ended Sept. 30, 2015 from the comparable year-ago period, primarily due to PPA expirations at Selkirk (August 2014) and Tunis (December 2014); lower dispatch at Chambers due to unfavorable pricing; lower water flows at Curtis Palmer and a scheduled maintenance outage at Mamquam.  These decreases were partially offset by an increase at Frederickson due to higher dispatch and increases at Nipigon and Morris, which had outages in 2014. 

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.

 

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,


2015

2014

2015

2014

Project income (loss)





East U.S.

$12.4

$(8.2)

$40.0

$4.8

West U.S.

11.5

(29.9)

7.3

(27.1)

Canada

1.9

(24.5)

17.9

(11.8)

Un-allocated Corporate

(1.6)

(2.5)

(2.2)

(6.9)

Total

24.2

(65.1)

63.0

(41.0)

Project Adjusted EBITDA





East U.S.

$27.4

$27.3

$81.0

$82.4

West U.S.

21.4

21.3

37.1

44.8

Canada

7.6

12.3

43.0

51.6

Un-allocated Corporate

(0.4)

(2.8)

(2.6)

(6.2)

Total

56.0

58.1

158.5

172.6

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 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. 

 

Table 2 provides a breakdown of project income and Project Adjusted EBITDA by segment for the three and nine months ended Sept. 30, 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 nine-month periods ended Sept. 30, 2015 and 2014.  Greeley was sold in March 2014 and is included as a component of discontinued operations for the nine months ended Sept. 30, 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. 

Three Months Ended September 30, 2015

Project income 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.

Project income increased $89.3 million to $24.2 million in the third quarter of 2015 from a project loss of $(65.1) million for the third quarter of 2014.  The 2014 result included a $91.8 million non-cash impairment of goodwill at Kenilworth, Manchief and Williams Lake and an $8.6 million gain from the sale of Delta-Person.     

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 modestly to $56.0 million in the third quarter of 2015 from $58.1 million in the third quarter of 2014.  The most significant drivers of lower EBITDA were the Selkirk PPA expiration, lower water flows at Curtis Palmer and Mamquam and the scheduled maintenance outage at Mamquam, and higher maintenance expense for a turbine repair at North Bay.  These factors were partially offset by higher Project Adjusted EBITDA at Piedmont, which benefited from higher revenue, lower fuel expense and lower maintenance expense, and Nipigon, which had a scheduled maintenance outage in 2014.  In addition, the Un-allocated Corporate segment experienced a reduced loss of $(0.4) million versus $(2.8) million in the year-ago period, primarily due to $1.1 million of lower project-level compensation expense and $1.0 million of reduced development and administrative costs.  Currency had an approximate $(1.4) million impact on Project Adjusted EBITDA, with an average U.S. dollar to Canadian dollar exchange rate for the third quarter of 2015 of 1.31 versus 1.10 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 $2.3 million to $6.9 million in the third quarter of 2015 from $9.2 million a year ago.  The improvement was due primarily to a $2.7 million decrease in employee compensation expense.  The 2014 figure included $4.2 million of severance charges. 

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 from operating activities of $14.5 million in the third quarter of 2015 declined $25.9 million from $40.4 million in the third quarter of 2014.  The reduction was primarily attributable to the $14.0 million premium and $5.5 million of accrued interest paid at redemption of the 9.0% Notes in June 2015 (both of which are included in interest expense) as well as the $10.8 million reduction in operating cash flows from the wind businesses, which were sold in June 2015 (see "Results of Discontinued Operations").   

Free Cash Flow, which is after debt repayment, capital expenditures and preferred dividends, decreased $18.7 million to $(6.1) million for the third quarter of 2015 from $12.6 million for the third quarter of 2014.  The reduction is primarily due to the $25.9 million reduction in operating cash flows, partially offset by a $3.1 million decrease in capital expenditures and a $4.4 million reduction in distributions to noncontrolling interests, including preferred dividends. 

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 and common shareholders, if and when declared by the board of directors.  Adjusted Free Cash Flow is after debt repayment or amortization, capital expenditures and preferred dividends, but is before common dividend payments.  It is thus a key measure in evaluating the amount of cash flow available to the Company to make common dividend payments.  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 increased $10.7 million to $51.5 million for the third quarter of 2015 from $40.8 million for the same period in 2014.  Significant increases occurred at the following projects:  Nipigon, which benefited from higher availability than in the third quarter of 2014, when it underwent a major outage to upgrade and replace its steam generator, and from higher waste heat and capacity revenue due to rate escalation under the PPA; Chambers, which benefited from lower debt service and lower capital expenditures, and which did not make a distribution in the year-ago quarter (the timing of distributions changed under the project's new debt agreement in June 2014); Calstock, which had a maintenance outage in the third quarter of 2014, and which benefited from additional waste heat this quarter, and Orlando, which benefited from lower gas costs and increased capacity payments.  These increases were partially offset by reductions at Manchief, which had a major gas turbine outage in the second quarter of 2015 and which has also experienced reduced dispatch, and Selkirk, which has been operating on a merchant basis in unfavorable market conditions since its PPA expired in August 2014.

Adjusted Cash Flows from Operating Activities decreased $5.5 million to $38.7 million in the third quarter of 2015 from $44.2 million in the year-ago period, primarily because of lower Project Adjusted EBITDA and several other less significant factors.  The 2015 result excludes the $14.0 million premium and $5.5 million of accrued interest paid at redemption of the 9.0% Notes in June 2015.      

Adjusted Free Cash Flow decreased modestly to $18.1 million in the third quarter of 2015 from $20.1 million in the third quarter of 2014.  The decrease was primarily attributable to lower Adjusted Cash Flows from Operating Activities, partially offset by lower capital expenditures and the favorable impact of the appreciation of the U.S. dollar against the Canadian dollar on the level of preferred dividend payments. 

Nine Months Ended September 30, 2015

Project income increased $104.0 million to $63.0 million in the third quarter of 2015 from a project loss of ($41.0) million in the third quarter of 2014.  The 2014 result included $106.6 million of non-cash impairments of long-lived assets and goodwill at Tunis and of goodwill at Kenilworth, Manchief and Williams Lake.  Results also benefited from increases in project income at Orlando, Morris, Piedmont, Curtis Palmer (lower interest expense, partially offset by lower water flows), North Island and Calstock.  These increases were partially offset by increased maintenance expense at Manchief related to a gas turbine overhaul in the second quarter of 2015, the expiration of the PPA at Tunis in December 2014, higher fuel expense and higher maintenance expense associated with a turbine repair at North Bay and the $8.6 million gain on the sale of Delta-Person in 2014.  In addition, there was a $14.6 million negative year-over-year change in the fair value of derivatives. 

Project Adjusted EBITDA decreased $14.1 million to $158.5 million for the first nine months of 2015 from $172.6 million for the comparable period in 2014.  The most significant drivers of the decline were lower results from Selkirk due to the expiration of its PPA and reduced dispatch in an unfavorable market environment, the gas turbine maintenance outage at Manchief, the mothballed status of Tunis, lower water flows at Curtis Palmer and Mamquam and higher fuel and maintenance expense at North Bay and Kapuskasing, partially offset by higher waste heat generation.  Currency had an approximate $(6.0) million impact on Project Adjusted EBITDA, with an average U.S. dollar to Canadian dollar exchange rate for the first nine months of 2015 of 1.27 versus 1.10 for the year-ago period.  These negative factors were partially offset by increases at Orlando, which benefited from higher generation and lower fuel expenses due to lower gas prices; Morris, which had lower fuel expense and lower maintenance expense than the comparable year-ago period; Piedmont, which had higher revenue, lower fuel expense and lower maintenance expense than a year ago; Calstock, which had higher waste heat generation and lower maintenance expense, and Nipigon, which had a maintenance outage in the comparable year-ago period and also benefited from high levels of waste heat.  In addition, the Un-allocated Corporate segment had a reduced loss of $(2.6) million versus $(6.2) million in the year-ago period, due primarily to a $1.9 million reduction in project-level compensation expense and $1.6 million of decreased development and administrative costs.      

Corporate-level G&A expense decreased $3.7 million to $23.0 million in the first nine months of 2015 from $26.7 million in the comparable year-ago period.  The improvement was primarily attributable to a $2.5 million reduction in legal expenses associated with the U.S. and Canadian shareholder actions, a $1.4 million decrease in business development costs related to divestitures and a $0.6 million reduction in employee compensation expense.

Cash Flow Metrics

Cash flows from operating activities of $67.7 million for the first nine months of 2015 increased $21.8 million from $45.9 million for the comparable period in 2014.  The increase is primarily due to $46.8 million of interest expense related to the debt repayment and repurchase transactions in the first quarter of 2014, partially offset by $19.5 million of premiums and accrued interest paid related to the redemption of the 9.0% Notes in July 2015, as well as $1.1 million of tax payments and $15.0 million of reduced cash flows from the wind businesses, which were sold in June 2015. 

Free Cash Flow of $(19.5) million for the first nine months of 2015 increased $28.9 million from $(48.4) million for the comparable period in 2014.  The increase is primarily due to the $21.8 million increase in operating cash flows described previously, a $5.0 million decrease in distributions to noncontrolling interests related to Canadian Hills and Rockland and a $2.1 million decrease in preferred dividends (driven primarily by the exchange rate).  Repayment of the APLP term loan and amortization of project debt totaled $67.3 million in the first nine months of 2015 versus $66.7 million in 2014, including an $8.1 million repayment of Piedmont principal at term loan conversion in February 2014. 

Cash Distributions from Projects decreased $(6.1) million to $146.3 million for the first nine months of 2015 from $152.4 million for the comparable year-ago period.  Significant increases were experienced 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.  These increases were more than offset by decreases at Selkirk and Tunis, due to their PPA expirations; 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.

Adjusted Cash Flows from Operating Activities of $77.7 million for the first nine months of 2015 increased $3.1 million from $74.6 million in the comparable year-ago period.  The 2015 result excludes the $14.0 million premium and $5.5 million of accrued interest paid at redemption of 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 $10.0 million reduction in cash interest payments and to slightly lower G&A expense, partially offset by lower Project Adjusted EBITDA. 

Adjusted Free Cash Flow of $(5.7) million decreased $6.8 million for the first nine months of 2015 from $1.1 million in the comparable year-ago period.  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 decrease in Adjusted Free Cash Flow was primarily attributable to the $3.1 million increase in Adjusted Cash Flows from Operating Activities described above and a $2.1 million reduction in preferred dividend payments (driven by a more favorable exchange rate), which were more than offset by a $12.2 million increase in term loan and project debt amortization.   

Results of Discontinued Operations

The Wind Projects were sold in June 2015 and are a component of discontinued operations for the three and nine months ended Sept. 30, 2015 and 2014.  Greeley was sold in March 2014 and is included as a component of discontinued operations for the first nine months of 2014.  The results for Greeley were immaterial during that period. 

Project Adjusted EBITDA of the Wind Projects was $0.0 million for the third quarter of 2015 versus $14.1 million for the comparable year-ago period.  Results for the first nine months of 2015 were $28.3 million versus $49.0 million for the comparable year-ago period. 

Cash flows from operating activities of the Wind Projects were $0.0 million and $21.9 million for the third quarter and first nine months of 2015, respectively, versus $10.8 million and $36.9 million, respectively, for the comparable 2014 periods.   

Liquidity

As shown in Table 3, the Company's liquidity at Sept. 30, 2015 was $177.2 million, including $76.4 million of unrestricted cash.  Liquidity at June 30, 2015 of $492.2 million included approximately $335 million of net cash proceeds received from the sale of the Company's Wind Projects in June.  In July, the Company used $330.4 million of cash to redeem the $310.9 million of 9.0% Notes, including redemption premiums and accrued interest.  On a pro forma basis for that transaction, liquidity at June 30, 2015 was $161.8 million

 

Atlantic Power Corporation

Table 3 – Liquidity (in millions of U.S. dollars)



Unaudited


June 30, 2015

Redemption of 9.0% Notes

July 2015

September 30, 2015

Revolver capacity


$210.0


$210.0

Letters of credit outstanding


(111.6)


(109.2)

Unused borrowing capacity


98.4


100.8

Unrestricted cash (1)


393.8

(330.4)

76.4

Total Liquidity


$492.2


$177.2

(1) Includes project-level cash for working capital needs of $11.4 million at June 30, 2015 and $13.0 million at September 30, 2015. 

 

Note:  Does not include restricted cash of $17.6 million at June 30, 2015 and $14.5 million at September 30, 2015.

 

Progress on Debt Reduction

Redemption of Senior Unsecured Notes

The Company completed the redemption of its outstanding $310.9 million principal amount of 9.0% Notes in July, and used the cash proceeds from the sale of its Wind Projects to fund the redemption.  The 9.0% Notes were redeemed at a price equal to 104.5% of the principal amount, plus accrued interest to the redemption date, for a total amount of $330.4 million.  The redemption premium of $14.0 million and accrued interest of $5.5 million as well as a non-cash write-off of deferred financing costs of $9.0 million were recorded in interest expense in the third quarter of 2015.  Annual interest expense savings associated with the redemption are approximately $28.0 million

Discretionary Debt Repurchases

In the third quarter of 2015, the Company repurchased $0.7 million of convertible debentures under the Normal Course Issuer Bid (NCIB).  In the first nine months of 2015, the Company repurchased $21.6 million of convertible debentures under the NCIB and $9.0 million of 9.0% Notes, for total discretionary debt repurchases of $30.6 million year to date.  The Company also had repurchased $3.0 million of convertible debentures under the NCIB in December 2014.  The NCIB is scheduled to expire on November 10, 2015. 

Amortization of APLP Term Loan and Project Debt

In the third quarter of 2015, the Company made repayments on the APLP term loan totaling $9.7 million and amortized $4.4 million of project-level debt.  On a year to date basis, repayments totaled $56.6 million and $10.7 million, respectively.  For the full year, the Company expects to repay approximately $65 million of the APLP term loan through the 50% cash sweep and 1% mandatory annual amortization.  For the full year, amortization of project-level debt is expected to total approximately $14 million.   

Cumulative Debt Reduction since Year End 2013

The Company had consolidated debt at Sept. 30, 2015 of approximately $1.0 billion.  This represents a net reduction of approximately $741 million since year end 2013, including $249 million of project debt associated with the Wind Projects that was transferred to the buyer of the assets at closing.  The Company has also reduced its share of debt at equity-owned projects by approximately $76 million, most of which was associated with the two equity-owned Wind Projects.  Thus, total debt has been reduced approximately $817 million over the past seven quarters.  Cash interest savings associated with this reduction in debt 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 $70 to $80 million annually over the next two years. 

The Company also has an improved corporate maturity profile.  The remaining corporate debt consists of $292 million (U.S. dollar equivalent) of convertible debentures maturing in 2017 and 2019.  The Company continues to explore opportunities to address these maturities.

2015 Guidance

The Company's 2015 guidance is as follows:

  • Total Company Project Adjusted EBITDA of $200 to $215 million
  • APLP Project Adjusted EBITDA of $148 to $160 million
  • Adjusted Cash Flows from Operating Activities of $95 to $105 million, revised from the previous range provided August 10, 2015 of $90 to $105 million
  • Adjusted Free Cash Flow of $0 to $10 million

Adjusted Cash Flows from Operating Activities has benefited from modestly lower G&A expense and slightly lower cash interest payments relative to previous expectations.  Although this benefits Adjusted Free Cash Flow as well, that benefit is expected to be offset by higher than expected amortization of the APLP term loan.  Table 4 shows the Company's full-year 2015 guidance and actual results for the first nine months of 2015.

 

Atlantic Power Corporation

Table 4 – Updated 2015 Guidance vs. YTD 2015 Actual Results

(in millions of U.S. dollars, except as otherwise stated)

 



Unaudited



2015 Guidance

(Updated 11/5/15)

YTD 2015

Actual

Project Adjusted EBITDA



$200 - $215

$158.5

Adjusted Cash Flows from Operating Activities (1)



$95 - $105

$77.7

Adjusted Free Cash Flow (2)



$0 - $10

$(5.7)

APLP Project Adjusted EBITDA (3)



$148 - $160

$116.0

(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.  Adjusted Free Cash Flow is a key measure in evaluating the amount of cash flow available to the Company to make common dividend payments.

(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. 








 

Other Financial Updates

G&A Expense Targets

The Company now expects 2015 corporate G&A of approximately $32 million versus previous guidance of $35 million, and is on track to achieve its corporate G&A cost target of $28 million or lower by 2016, representing a 48% cumulative reduction from 2013.  The 2015 G&A of $32 million includes approximately $4 million of severance expense and approximately $1 million of restructuring and other charges.  

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. 

The most significant of these investments have been 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 total, these represent an investment of $29 million over the three-year period 2013 through 2015.  The Company expects to realize a cash flow benefit from completed projects of approximately $6 million in 2015, at the midpoint of previous expectations of $4 to $8 million due to lower water flows at Curtis Palmer and high levels of waste heat at Nipigon.  The Company expects this to increase to approximately $10 million in 2016, including an initial cash flow contribution from projects expected to be completed in late 2015 and the first quarter of 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 $5 million in 2016.

Maintenance and Capex

The Company projects 2015 capital expenditures of approximately $14 million, of which approximately $12 million relates to discretionary optimization projects described above.  The Company has incurred approximately $10.5 million of capital expenditures year to date.  In the fourth quarter, the Company expects to receive a customer reimbursement of approximately $6 million related to one of the optimization projects.  Net of that reimbursement, 2015 capital expenditures are expected to be approximately $8 million

In addition to amounts capitalized, the Company incurs maintenance expense to maintain its projects.  Total maintenance expense is expected to be approximately $46 million for 2015, of which $36.7 million was incurred in the first nine months of 2015.   

Share Purchases by Insiders

In the third quarter, CEO James J. Moore, Jr. and two directors of the Company purchased a total of 185,000 common shares of the Company at an average price of $2.23 per share.  Including those made in the second quarter, purchases by management and directors this year total approximately 565,000 shares.  The average purchase price in the second quarter of 2015 was $3.09 per share.  There have been no sales by officers or directors this year.   

U.S. Shareholder Litigation

In late October, the plaintiffs in the U.S. securities class action suit informed the Company that they would not further pursue the appeal of the district court ruling in March of this year that had granted the Company's motion to dismiss the suit.  On Oct. 29, the plaintiffs and the Company filed a joint stipulation with the United States Court of Appeals for the First Circuit agreeing to voluntarily dismiss the appeal with prejudice, with each party bearing its own costs and fees.  The stipulation is pending approval by the appeals court. 

Supplementary Financial Information

For further information, attached to this news release is a summary of Project Adjusted EBITDA by segment for the three and nine months ended September 30, 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 nine months ended September 30, 2015 (Table 9A) and the nine months ended September 30, 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 nine months ended September 30, 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 nine months ended September 30, 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 nine months ended September 30, 2015 and 2014 (Table 12). 

Investor Conference Call and Webcast

A telephone conference call hosted by Atlantic Power's management team will be held on Friday, November 6, 2015 at 8:30 AM ET.  An accompanying slide presentation will be available on the Company's website prior to the call.  The telephone numbers for the conference call are:  U.S. Toll Free: 1-888-317-6003; Canada Toll Free: 1-866-284-3684; International Toll: +1-412-317-6061.  Participants will need to provide access code 2718429 to enter the conference call.  The conference call will also be broadcast over Atlantic Power's website, with an accompanying slide presentation.  Please call or log in 10 minutes prior to the call.  The telephone numbers to listen to the conference call after it is completed (Instant Replay) are U.S. Toll Free:  1-877-344-7529; Canada Toll Free 1-855-669-9658; International Toll: +1-412-317-0088.  Please enter conference call number 10073982.  The replay will be available 1 hour after the end of the conference call through February 11, 2016 at 9:00 AM ET.  The conference call will also be archived on Atlantic Power's website.

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 2,141 megawatts ("MW") in which its aggregate ownership interest is approximately 1,504 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 
Amanda Wagemaker, 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:  

  • 2015 Project Adjusted EBITDA will be in the range of $200 to $215 million;
  • 2015 APLP Project Adjusted EBITDA will be in the range of $148 to $160 million;
  • 2015 Adjusted Cash Flows from Operating Activities will be in the range of $95 to $105 million;
  • 2015 Adjusted Free Cash Flow will be in the range of $0 to $10 million;
  • the benefit of lower corporate G&A expense and lower cash interest payments to guidance for Adjusted Free Cash Flow is expected to be offset by higher than expected amortization of the APLP term loan;
  • the Company's dividend level;
  • the Company expects to have G&A costs of approximately $32 million in 2015, and expects to achieve its corporate G&A cost target of $28 million or lower in 2016;
  • the Company expects to incur approximately $4 million of severance expense and approximately $1 million of restructuring charges in 2015;
  • for 2015, the Company projects that capital expenditures will total approximately $14 million, before an expected $6 million customer reimbursement, and total maintenance expense will be approximately $46 million;
  • the Company expects to realize a cash flow benefit from discretionary investments in its existing projects of approximately $6 million in 2015;
  • 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 investments in its fleet will be approximately $5 million in 2016;
  • for the full year 2015, the Company expects to repay approximately $65 million of the APLP term loan through the 50% cash sweep and 1% mandatory annual amortization, and expects amortization of project-level debt to total approximately $14 million;
  • 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 $70 to $80 million annually over the next two years;
  • the Company's expectations regarding the exploration of opportunities to reshape its remaining corporate debt and address the maturities of its convertible debentures;
  • the nature of any further proceedings in the U.S. and Canadian securities litigation; 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)

 

September 30,

December 31,

2015

2014

Assets

        (Unaudited)

Current assets:                         

Cash and cash equivalents

$76.4

$106.0

Restricted cash

14.5

22.5

Accounts receivable

41.6

46.2

Inventory

17.6

19.3

Prepayments and other current assets

12.8

13.9

Assets held for sale

-

792.1

Refundable income taxes

-

0.2

Total current assets

162.9

1,000.2


Property, plant and equipment, net

875.7

962.9

Equity investments in unconsolidated affiliates

296.5

305.2

Other intangible assets, net

324.4

377.1

Goodwill

197.2

197.2

Derivative instruments asset

-

1.1

Deferred financing costs

44.8

62.8

Other assets

8.7

10.1

Total assets

$1,910.2

$2,916.6


Liabilities

Current liabilities:

Accounts payable

$7.1

$9.4

Income taxes payable

0.6

-

Accrued interest

6.6

5.3

Other accrued liabilities

35.5

30.7

Current portion of long-term debt

16.8

20.0

Current portion of derivative instruments liability

35.1

36.1

Liabilities held for sale

-

271.8

Other current liabilities

5.5

6.8

Total current liabilities

107.2

380.1


Long-term debt

738.3

1,145.9

Convertible debentures

291.9

340.6

Derivative instruments liability

30.9

47.5

Deferred income taxes

112.8

92.4

Power purchase and fuel supply agreement liabilities, net

28.4

33.4

Other non-current liabilities

56.4

60.2

Commitments and contingencies

-

-

Total liabilities

1,365.9

2,100.1



Common shares, no par value, unlimited authorized shares; 122,118,147 and 121,323,614

        issued and outstanding at September 30, 2015 and December 31, 2014, respectively

1,290.4

1,288.4

Accumulated other comprehensive loss

(121.1)

(68.3)

Retained deficit

(846.3)

(863.9)

Total Atlantic Power Corporation shareholders' equity

323.0

356.2

Preferred shares issued by a subsidiary company

221.3

221.3

Noncontrolling interests held for sale

-

239.0

Total equity

544.3

816.5

Total liabilities and equity

$1,910.2

$2,916.6

 

 


Atlantic Power Corporation

Table 6 – 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,



2015

2014


2015

2014


Project revenue:






Energy sales

$43.4

$53.0


$144.9

$177.6


Energy capacity revenue

45.9

49.1


117.4

124.0


Other

18.2

19.5


59.5

68.4



107.5

121.6


321.8

370.0









Project expenses:







Fuel

41.1

49.3


125.3

159.5


Operations and maintenance

24.8

28.9


81.6

85.5


Development

-

1.0


1.1

2.7


Depreciation and amortization

27.8

30.7


83.8

92.1



93.7

109.9


291.8

339.8


Project other income (expense):







Change in fair value of derivative instruments

3.6

1.7


8.7

23.3


Equity in earnings of unconsolidated affiliates

8.9

15.6


28.3

27.8


Interest expense, net

(2.1)

(2.3)


(6.2)

(15.7)


Impairment

-

(91.8)


-

(106.6)


Other income (expense), net

-

-


2.2

-



10.4

(76.8)


33.0

(71.2)


Project (loss) income

24.2

(65.1)


63.0

(41.0)









Administrative and other expenses (income):







Administration

6.9

9.2


23.0

26.7


Interest, net

41.0

26.7


91.3

120.8


Foreign exchange gain

(21.7)

(19.0)


(49.1)

(20.4)


Other income, net

-

-


(3.1)

-



26.2

16.9


62.1

127.1


(Loss) income from continuing operations before income taxes

(2.0)

(82.0)


0.9

(168.1)


Income tax expense (benefit)

1.4

1.4


(0.3)

(20.0)


(Loss) income from continuing operations

(3.4)

(83.4)


1.2

(148.1)


Net income (loss) from discontinued operations, net of tax (1)

(0.5)

(7.7)


20.6

(21.8)


Net income (loss)

(3.9)

(91.1)


21.8

(169.9)


Net loss attributable to noncontrolling interests of discontinued operations

-

(5.1)


(11.0)

(11.8)


Net income attributable to preferred share dividends of a subsidiary company

2.1

2.9


6.7

8.8


Net income (loss) attributable to Atlantic Power Corporation

$(6.0)

$(88.9)


$26.1

$(166.9)









Basic and diluted earnings per share:







Loss from continuing operations attributable to Atlantic Power Corporation

$(0.05)

$(0.72)


$(0.05)

$(1.30)


Income (loss) from discontinued operations, net of tax

-

(0.02)


0.26

(0.08)


Net income (loss) attributable to Atlantic Power Corporation

$(0.05)

$(0.74)


$0.21

$(1.38)


 

Weighted average number of common shares outstanding:







Basic

122.1

120.7


121.8

120.6


Diluted

122.2

120.7


121.9

120.6









Dividends paid per common share:

$0.02

$0.06


$0.07

$0.23


(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







Nine months ended September 30,






2015

2014


Cash flows from operating activities:







Net (loss) income




$21.8

$(169.9)


Adjustments to reconcile to net cash provided by operating activities







Depreciation and amortization




94.1

122.3


Gain on sale of discontinued operations




(47.2)

(2.1)


Gain on sale of development project and other assets




(2.3)

-


Gain on sale of equity investment




-

(8.6)


Gain on purchase and cancellation of convertible debentures




(3.1)

-


Long-term incentive plan expense




2.0

1.8


Impairment charges




-

106.6


Equity in earnings from unconsolidated affiliates




(28.3)

(18.8)


Distributions from unconsolidated affiliates




40.0

52.8


Unrealized foreign exchange gain




(49.3)

(21.0)


Change in fair value of derivative instruments




(8.0)

(12.3)


Change in deferred income taxes




23.6

(11.1)


Change in other operating balances







Accounts receivable




4.3

(0.3)


Inventory




1.7

(4.3)


Prepayments, refundable income taxes and other assets




20.2

18.2


Accounts payable




(6.0)

(4.8)


Accruals and other liabilities




4.2

(2.6)


Cash provided by operating activities




67.7

45.9









Cash flows provided by investing activities







Change in restricted cash




8.0

78.2


Proceeds from sale of assets, net of cash sold




326.3

0.9


Contribution to unconsolidated affiliate




(0.5)

8.6


Capitalized development costs




(0.8)

-


Purchase of property, plant and equipment




(9.4)

(11.3)


Cash provided by investing activities




323.6

76.4









Cash flows used in financing activities







Proceeds from senior secured term loan facility




-

600.0


Repayment of corporate and project-level debt




(387.1)

(621.9)


Repayment of convertible debentures




(18.7)

-


Deferred financing costs




-

(39.0)


Dividends paid to common shareholders




(8.5)

(32.0)


Dividends paid to noncontrolling interests




(10.5)

(20.4)


Cash used in financing activities




(424.8)

(113.3)









Net increase (decrease) in cash and cash equivalents




(33.5)

9.0


Cash and cash equivalents at beginning of period at discontinued operations




3.9

-


Cash and cash equivalents at beginning of period




106.0

158.6


Cash and cash equivalents at end of period




$76.4

$167.6









Supplemental cash flow information







Interest paid




$75.5

$124.4


Income taxes paid, net




$4.1

$1.0


Accruals for construction in progress




$1.2

$8.2












 

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 new 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 16.  A reconciliation of Free Cash Flow to cash flows from operating activities is provided in Table 10 on page 17 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 18 and 19 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 September 30,

Nine months ended September 30,


2015

2014

2015

2014

Project Adjusted EBITDA by segment





East U.S.

$27.4

$27.3

$81.0

$82.4

West U.S. (1)

21.4

21.3

37.1

44.8

Canada

7.6

12.3

43.0

51.6

Un-allocated Corporate

(0.4)

(2.8)

(2.6)

(6.2)

Total

$56.0

$58.1

$158.5

$172.6






Reconciliation to project income





Depreciation and amortization

 

32.8

38.9

98.9

120.6

Interest expense, net

 

2.5

3.0

7.7

18.1

Change in the fair value of derivative instruments

 

(3.6)

(1.8)

(8.7)

(23.1)

Other (income) expense

 

0.1

83.1

(2.4)

98.0

Project income (loss)

$24.2

$(65.1)

$63.0

$(41.0)

(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 nine months ended September 30, 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)

Nine months ended September 30, 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

$50.4

$(6.1)

$(5.5)

$(7.2)

$1.7

$33.3


  Equity method

30.6

(4.5)

(2.0)

(0.2)

5.2

29.1


  Total

81.0

(10.6)

(7.5)

(7.4)

6.9

62.4


West U.S.








  Consolidated

27.3

-

-

(0.6)

(2.3)

24.4


  Equity method

9.8

-

-

-

0.8

10.6


  Total

37.1

-

-

(0.6)

(1.5)

35.0


Canada








  Consolidated

43.0

(0.2)

-

(2.5)

8.6

48.9


  Equity method

-

-

-

-

-

-


  Total

43.0

(0.2)

-

(2.5)

8.6

48.9


  Total consolidated

120.7

(6.3)

(5.5)

(10.3)

8.0

106.6


  Total equity method

40.4

(4.5)

(2.0)

(0.2)

6.0

39.7


Un-allocated corporate

(2.6)

-

-

0.2

2.4

-


Total

$158.5

$(10.8)

$(7.5)

$(10.3)

$16.4

$146.3


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)

Nine months ended September 30, 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

$46.6

$(12.2)

$(5.7)

$(1.2)

$3.8

$31.3


  Equity method

35.8

(3.8)

(6.2)

(0.6)

1.2

26.4


  Total

82.4

(16.0)

(11.9)

(1.8)

5.0

57.7


West U.S.








  Consolidated

34.0

-

-

(0.5)

3.1

36.6


  Equity method

10.8

(1.0)

(0.1)

-

1.1

10.8


  Total

44.8

(1.0)

(0.1)

(0.5)

4.2

47.4


Canada








  Consolidated

51.6

(0.1)

-

(6.9)

2.7

47.3


  Equity method

-

-

-

-

-

-


  Total

51.6

(0.1)

-

(6.9)

2.7

47.3


  Total consolidated

132.2

(12.3)

(5.7)

(8.6)

9.6

115.2


  Total equity method

46.6

(4.8)

(6.3)

(0.6)

2.3

37.2


Un-allocated corporate

(6.2)

-

-

(1.0)

7.2

-


Total

$172.6

$(17.1)

$(12.0)

$(10.2)

$19.1

$152.4


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

 September 30,


Nine months ended

September 30,



2015

2014


2015

2014


Cash Distributions from Projects

$51.5

$40.8


$146.3

$152.4


Repayment of long-term debt

(4.4)

(4.2)


(10.8)

(17.1)


Interest expense, net

(2.5)

(2.7)


(7.5)

(12.0)


Capital expenditures

(5.2)

(7.3)


(10.3)

(10.2)


Other, including changes in working capital

7.6

(3.1)


16.4

19.1


Project Adjusted EBITDA

$56.0

$58.1


$158.5

$172.6


Depreciation and amortization

32.8

38.9


98.9

120.6


Interest expense, net

2.5

3.0


7.7

18.1


Change in the fair value of derivative instruments

(3.6)

(1.8)


(8.7)

(23.1)


Other (income) expense

0.1

83.1


(2.4)

98.0


Project income (loss)

$24.2

$(65.1)


$63.0

$(41.0)


Administrative and other expenses (income)

26.2

16.9


62.1

127.1


Income tax expense (benefit)

1.4

1.4


(0.3)

(20.0)


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

(0.5)

(7.7)


20.6

(21.8)


Net income (loss)

$(3.9)

$(91.1)


$21.8

$(169.9)


Adjustments to reconcile to net cash provided by operating activities

10.7

117.4


21.5

209.6


Change in other operating balances

7.7

14.1


24.4

6.2


Cash flows from operating activities

$14.5

$40.4


$67.7

$45.9


Term loan facility repayments (1)

(9.7)

(9.6)


(56.6)

(47.1)


Project-level debt repayments

(4.4)

(4.2)


(10.7)

(19.6)


Purchases of property, plant and equipment (2)

(4.4)

(7.5)


(9.4)

(10.0)


Distributions to noncontrolling interests (3)

-

(2.9)


(3.8)

(8.8)


Dividends on preferred shares of a subsidiary company

(2.1)

(3.6)


(6.7)

(8.8)


Free Cash Flow

$(6.1)

$12.6


$(19.5)

$(48.4)


Additional GAAP cash flow measures:







Cash flows from investing activities

$(1.3)

$0.9


$323.6

$76.4


Cash flows from financing activities

(330.5)

(31.4)


(424.8)

(113.3)


(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: Table 10 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 September 30, 2015 and 2014 (Unaudited)


Three months ended

September 30, 2015

Three months ended

September 30, 2014



Continuing Operations

Discontinued
Operations

Total

Continuing
Operations

Discontinued
Operations

Total


Project Adjusted EBITDA

$56.0

$-

$56.0

$58.1

$14.1

$72.2


Adjustment for equity method projects (1)

0.1

-

0.1

(1.5)

(0.5)

(2.0)


Corporate G&A expense

(6.9)

-

(6.9)

(9.2)

-

(9.2)


Cash interest payments

(29.2)

-

(29.2)

(7.8)

(1.9)

(9.7)


Cash taxes

(1.2)

(1.2)

(2.4)

-

-

-


Other, including changes in working capital

(3.1)

-

(3.1)

(9.9)

(0.9)

(10.9)


Cash flows from operating activities

$15.7

$(1.2)

$14.5

$29.7

$10.8

$40.4


Changes in other operating balances

3.1

-

3.1

9.9

0.9

10.9


Severance charges

0.4

-

0.4

4.4

-

4.4


Restructuring and other charges

-

-

-

0.9

-

0.9


Shareholder litigation expenses

-

-

-

(0.7)

-

(0.7)


Refinancing transaction costs (Q1 2014)

-

-

-

-

-

-


Debt redemption costs (9.0% Notes) (Q3 2015)

19.5

-

19.5

-

-

-


Adjusted Cash Flows from Operating Activities

$38.7

$(1.2)

$37.5

$44.2

$11.7

$55.9


Term loan facility repayments (2)

(9.7)

-

(9.7)

(9.6)

-

(9.6)


Project-level debt repayments

(4.4)

-

(4.4)

(4.2)

-

(4.2)


Purchases of property, plant and equipment (3)

(4.4)

-

(4.4)

(7.4)

(0.1)

(7.5)


Distributions to noncontrolling interests (4)

-

-

-

-

(3.6)

(3.6)


Dividends on preferred shares of a subsidiary company

(2.1)

-

(2.1)

(2.9)

-

(2.9)


Adjusted Free Cash Flow

$18.1

$(1.2)

$16.9

$20.1

$8.0

$28.1


Additional GAAP cash flow measures:








Cash flows from investing activities

$(1.3)

$-

$(1.3)

$0.5

$0.4

$0.9


Cash flows from financing activities

(330.5)

-

(330.5)

(18.9)

(12.5)

(31.4)


(1) Represents difference between Project Adjusted EBITDA and cash distributions from equity method projects. 

(2) Includes mandatory 1% 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.

 

Note: Table 11A 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)

Nine months ended September 30, 2015 and 2014 (Unaudited)

 



Nine months ended

September 30, 2015

Nine months ended

September 30, 2014



Continuing
Operations

Discontinued
Operations

Total

Continuing
Operations

Discontinued
Operations

Total


Project Adjusted EBITDA

$158.5

$28.3

$186.8

$172.6

$49.0

$221.6


Adjustment for equity method projects (1)

(3.8)

(2.7)

(6.5)

(11.3)

(3.2)

(14.5)


Corporate G&A expense

(23.0)

-

(23.0)

(26.7)

-

(26.7)


Cash interest payments

(75.5)

-

(75.5)

(115.4)

(9.0)

(124.4)


Cash taxes

(2.9)

(1.2)

(4.1)

(1.0)

-

(1.0)


Other, including changes in working capital

(6.3)

(3.7)

(10.0)

(9.3)

0.1

(9.1)


Cash flows from operating activities

$47.0

$20.7

$67.7

$8.9

$36.9

$45.9


Changes in other operating balances

6.3

3.7

10.0

9.3

(0.1)

9.1


Severance charges

3.8

-

3.8

5.2

-

5.2


Restructuring and other charges

0.5

-

0.5

1.0

-

1.0


Shareholder litigation expenses

0.6

-

0.6

0.8

-

0.8


Refinancing transaction costs (Q1 2014)

-

-

-

49.4

-

49.4


Debt redemption costs (9.0% Notes) (Q3 2015)

19.5

-

19.5

-

-

-


Adjusted Cash Flows from Operating Activities

$77.7

$24.4

$102.1

$74.6

$36.8

$111.4


Term loan facility repayments (2)

(56.6)

-

(56.6)

(47.1)

-

(47.1)


Project-level debt repayments (3)

(10.7)

-

(10.7)

(8.0)

(3.5)

(11.5)


Purchases of property, plant and equipment (4)

(9.4)

0.1

(9.3)

(9.6)

(0.4)

(10.0)


Distributions to noncontrolling interests (5)

-

(3.8)

(3.8)

-

(8.8)

(8.8)


Dividends on preferred shares of a subsidiary company

(6.7)

-

(6.7)

(8.8)

-

(8.8)


Adjusted Free Cash Flow

$(5.7)

$20.7

$15.0

$1.1

$24.1

$25.2


Additional GAAP cash flow measures:








Cash flows from investing activities

$336.4

$(12.8)

$323.6

$69.5

$6.9

$76.4


Cash flows from financing activities

(411.8)

(13.0)

(424.8)

(71.9)

(41.4)

(113.3)


(1) Represents difference between Project Adjusted EBITDA and cash distributions from equity method projects.

(2) Includes mandatory 1% annual amortization and 50% excess cash flow repayments by the Partnership.

(3) 2014 continuing operations and total columns exclude $8.1 million repayment of Piedmont principal at term loan conversion in 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.

 

Note: Table 11B 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

September 30,

Nine months ended

September 30,





2015

2014

2015

2014


East U.S.


Accounting






Cadillac


Consolidated

$1.6

$2.2

$6.1

$5.4


Curtis Palmer


Consolidated

5.4

5.5

20.9

24.2


Morris


Consolidated

4.5

3.0

13.3

9.6


Piedmont


Consolidated

5.6

3.4

7.7

4.2


Other (1)


Consolidated

0.7

1.0

2.4

3.2


Chambers


Equity method

4.0

4.3

13.7

14.1


Orlando


Equity method

5.4

5.3

16.6

10.0


Other (2)


Equity method

0.2

2.6

0.3

11.7


Total



27.4

27.3

81.0

82.4


West U.S.








Manchief


Consolidated

3.8

3.7

2.4

10.9


Naval Station


Consolidated

4.3

4.4

8.9

9.1


North Island


Consolidated

3.3

3.1

7.0

4.3


Other (3)


Consolidated

6.7

6.9

9.0

9.7


Frederickson


Equity method

3.2

3.0

9.2

8.9


Other (4)


Equity method

0.1

0.2

0.6

1.9


Total



21.4

21.3

37.1

44.8


Canada








Calstock


Consolidated

2.3

0.6

7.0

3.9


Kapuskasing


Consolidated

(0.3)

1.2

4.1

6.1


Nipigon


Consolidated

3.3

1.4

13.1

10.1


North Bay


Consolidated

(1.2)

0.9

3.6

6.9


Williams Lake


Consolidated

4.9

5.8

12.5

12.6


Other (5)


Consolidated

(1.4)

2.4

2.7

12.0


Total



7.6

12.3

43.0

51.6


Totals








Consolidated projects



43.5

45.5

120.7

132.2


Equity method projects



12.9

15.4

40.4

46.6


Un-allocated corporate



(0.4)

(2.8)

(2.6)

(6.2)


Total Project Adjusted EBITDA



$56.0

$58.1

$158.5

$172.6










Reconciliation to project income (loss)








Depreciation and amortization



$32.8

$38.9

$98.9

$120.6


Interest expense, net



2.5

3.0

7.7

18.1


Change in the fair value of derivative instruments



(3.6)

(1.8)

(8.7)

(23.1)


Other (income) expense



0.1

83.1

(2.4)

98.0


Project income (loss)



$24.2

$(65.1)

$63.0

$(41.0)


(1) Kenilworth

(2) Selkirk

(3) Naval Training Station and Oxnard

(4) Q3 2014: Koma Kulshan; YTD September 2014:  Koma Kulshan and Delta-Person; Q3 and YTD June 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. 



















 

SOURCE Atlantic Power Corporation


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