Atlantic Power Corporation Releases Fourth Quarter and Year End 2015 Results

DEDHAM, Mass., March 7, 2016 /CNW/ – Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the "Company") today released its results for the three and twelve months ended December 31, 2015.

Progress on Key Initiatives

  • Reduced debt by a total of $833 million in the past two years as a result of asset sales, debt amortization and discretionary debt repurchases; lowered annual interest expense by more than $65 million
  • Reduced overhead costs from $54 million in 2013 to $32 million in 2015; expect further reduction to $27 million in 2016 (cumulative expected reduction of 50% from 2013)
  • Invested a total of $22 million in attractive optimization projects from 2013 to 2015; realized cash flow benefit of approximately $6 million in 2015; expect $10 million benefit in 2016
  • In December, announced modification of the Morris energy services agreement and 11-year extension to December 2034; changes expected to be modestly accretive to Project Adjusted EBITDA

Recent Developments

  • Implemented normal course issuer bid (NCIB) for up to 10% of each of the Company's convertible debentures and common shares and up to 5% of Atlantic Power Preferred Equity Ltd.'s preferred shares, subject to limitations described in the Company's December 22, 2015 press release
  • Shareholder litigation in United States and Ontario dismissed without payments by the Company (December 2015); proposed action in Quebec expected to be resolved in a similar manner
  • In February 2016, Standard & Poor's upgraded the Company's corporate credit rating to B+ from B; Moody's had upgraded to B1 from B2 in October 2015; both agencies have "stable" outlooks for the credit
  • Common dividend eliminated as part of changes to overall capital allocation strategy (February 2016)
  • Management and directors purchased approximately 493,000 shares in Q4 2015 at an average price of US$1.77 per share; for the year, management and director purchases totaled approximately 1.05 million shares at an average price of US$2.31

Full Year 2015 Financial Results

  • Reported project loss of $(41) million vs. project loss of $(39) million in 2014; 2015 results include $128 million impairment of long-lived assets and goodwill (results for both years exclude the Wind Projects, which are included in discontinued operations)
  • Achieved Project Adjusted EBITDA of $209 million vs. $229 million in 2014, in the upper half of the Company's 2015 guidance range of $200 to $215 million (results exclude Wind Projects)
  • Reported (GAAP) Cash flows provided by operating activities of $87 million vs. $65 million in 2014 (results include cash flows from the Wind Projects)
  • Generated Adjusted Cash Flows from Operating Activities of $105 million vs. $92 million in 2014, at the upper end of the Company's 2015 guidance range of $95 to $105 million (results exclude Wind Projects and debt redemption costs)
  • Achieved Adjusted Free Cash Flow of $2 million vs. approximately zero in 2014, in the lower end of the Company's 2015 guidance range of $0 to $10 million because of a delay in a $6 million reimbursement for a customer-owned construction project that was received in February 2016 (results exclude Wind Projects and debt redemption costs)

Q4 2015 Financial Results

  • Recorded $128 million non-cash impairment of long-lived assets and goodwill, primarily at Williams Lake
  • Project loss of $(104) million vs. project income of $2 million in Q4 2014; loss for the fourth quarter of 2015 is attributable to the $128 million impairment charge (results for both years exclude the Wind Projects)
  • Project Adjusted EBITDA of $50 million vs. $57 million in Q4 2014 (results exclude Wind Projects)
  • Reported (GAAP) Cash flows provided by operating activities of $20 million vs. $19 million in Q4 2014 (results include Wind Projects)
  • Adjusted Cash flows from Operating Activities of $29 million vs. $18 million in Q4 2014 (excludes Wind)
  • Adjusted Free Cash Flow of $9 million vs. $(1) million in Q4 2014 (results exclude Wind projects)

2016 Guidance

  • Project Adjusted EBITDA of $200 to $220 million
    • Atlantic Power Limited Partnership (APLP) Project Adjusted EBITDA of $145 to $155 million
  • Adjusted Cash Flows from Operating Activities of $110 to $130 million
  • Adjusted Free Cash Flow of $20 to $40 million

"In 2015, we made further progress in strengthening our financial position and reducing our risk profile.  Over the past two years, we have reduced our debt by $833 million, lowered our cash interest and overhead costs by approximately half, and improved our debt maturity profile.  In the past five months, our credit ratings have been upgraded by both Moody's and Standard & Poor's.  In December, the proposed shareholder actions in both the United States and Ontario were dismissed by the courts without any payments by us," said James J. Moore, Jr., President & CEO of Atlantic Power. 

Mr. Moore continued, "We had success on other fronts as well.  Our projects performed well in 2015 and earned substantially all of their capacity payments.  We achieved Project Adjusted EBITDA and cash flow in line with our guidance.  We continued to make attractive investments in our own fleet, which are yielding cash returns of more than 20%.  We announced an 11-year extension of our energy services agreement with the customer at our Morris project, and we continue to make progress on other contract extensions."      

"Looking ahead, we remain focused on growing the intrinsic value per share of the Company.  The amount of our discretionary cash flow after debt repayment is growing, and we see ample opportunities to put this to work at good returns.  As we announced earlier this month, we have prioritized repurchases of our debt and equity, which are currently trading at compelling price-to-value levels.  In addition, we see the potential for additional attractive investments in our fleet, some of which are linked to possible contract extensions," said Mr. Moore.  "We believe that both these uses of cash have considerably higher risk-adjusted returns than those available externally at present.  Although primarily focused on organic growth initiatives, management has considerable experience building other IPP businesses and will continue to evaluate potential external investments in a disciplined and opportunistic manner."

All amounts are in U.S. dollars and are approximate unless otherwise indicated. Adjusted Cash Flows from Operating Activities, Free Cash Flow, Adjusted Free Cash Flow, Cash Distributions from Projects, Project Adjusted EBITDA and APLP Project Adjusted EBITDA are not recognized measures under generally accepted accounting principles in the United States ("GAAP") and do not have standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies. Please see "Regulation G Disclosures" on page 18 of this news release for an explanation and the GAAP reconciliation of "Adjusted Cash Flows from Operating Activities", "Free Cash Flow", "Adjusted Free Cash Flow", "Cash Distributions from Projects" and "Project Adjusted EBITDA" as used in this news release.  The Company has not reconciled non-GAAP financial measures relating to individual projects or the projects in discontinued operations or the APLP projects to the directly comparable GAAP measures due to the difficulty in making the relevant adjustments on an individual project basis.  The Company has not provided a reconciliation of forward-looking non-GAAP measures, due primarily to variability and difficulty in making accurate forecasts and projections, as not all of the information necessary for a quantitative reconciliation is available to the Company without unreasonable efforts.

Atlantic Power Corporation








Table 1 – Selected Results








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





Unaudited









Three months ended December 31

Twelve months ended December 31



2015

2014



2015

2014

Excluding results from discontinued operations(1)







Project revenue


$98.4

$119.9



$420.2

$489.9

Project income (loss)


(104.3)

2.1



(41.4)

(38.9)

Project Adjusted EBITDA


50.4

56.9



208.9

229.4

Cash Distributions from Projects


46.0

57.6



192.3

209.1

Adjusted Cash Flows from Operating Activities


29.3

17.9



105.3

92.4

Adjusted Free Cash Flow


9.2

(1.4)



1.8

(0.3)

Aggregate power generation (thousands of Net MWh)


1,646.4

1,592.1



6,353.3

6,398.9

Weighted average availability


96.0%

93.6%



95.2%

93.0%

Including results from discontinued operations (1)








Cash flows from operating activities


$19.7

$19.1



$87.4

$65.0

Free Cash Flow


(0.4)

(7.2)



(19.8)

(55.6)

Results of discontinued operations








Project Adjusted EBITDA


$-

$20.7



$28.1

$69.8

Cash Distributions from Projects


-

4.8



7.3

39.4

Cash flows from operating activities (as reported)


-

11.3



21.9

48.3

Cash flows from operating activities (as adjusted) (2)


(5.0)

11.3



15.7

48.3

(1) Canadian Hills, Meadow Creek, Goshen North, Idaho Wind and Rockland (the "Wind Projects") were sold in June 2015 and are designated as discontinued operations for the twelve months ended December 31, 2015 and 2014.  Greeley was sold in March 2014 and is included as a component of discontinued operations for the twelve months ended December 31, 2014.  The results of discontinued operations are excluded from Project revenue, Project income, Project Adjusted EBITDA, Cash Distributions from Projects, Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow as presented in Table 1.  The results for discontinued operations have also been excluded from the aggregate power generation and weighted average availability statistics shown in Table 1.  Under GAAP, the cash flows attributable to the Wind Projects and Greeley are included in cash flows from operating activities as shown on the Company's Consolidated Statement of Cash Flows; therefore, the Company's calculation of Free Cash Flow shown on Table 1 also includes cash flows from the Wind Projects and Greeley.  However, the inclusion of Greeley in 2014 had no impact on cash flows from operating activities or Free Cash Flow.  Results of discontinued operations shown above are for the Wind Projects, as Greeley had no impact on Project Adjusted EBITDA, Cash Distributions from Projects or cash flows from operating activities for the 2014 period in which it was included in discontinued operations.   

(2) Adjusted for cash tax payments associated with the sale of the Wind Projects of $5.0M in the fourth quarter of 2015 and $6.3M for the Full Year 2015.

Note: Project Adjusted EBITDA, Cash Distributions from Projects, Adjusted Cash Flows from Operating Activities, Adjusted Free Cash Flow and Free Cash Flow are not recognized measures under GAAP and do not have any standardized meaning prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies. Please refer to Tables 8 and 10 through 12 for reconciliations of these non-GAAP measures to GAAP measures.

 

Operating Results

The discussion of operating results excludes the Wind Projects, which were sold in June 2015 and are included in discontinued operations.

Three Months Ended December 31, 2015

Project availability was 96.0% in the fourth quarter of 2015, an increase from 93.6% in the year-ago period.  Increased availability at Koma Kulshan and Selkirk, both of which had maintenance outages in the comparable 2014 period, was partially offset by lower availability at Mamquam, which had a scheduled maintenance outage that extended into the fourth quarter of 2015.  (The 2015 availability figure excludes Tunis, which has been mothballed since February 2015 following the expiration of its Power Purchase Agreement, or PPA, in December 2014.)

Generation increased 3.4% in the fourth quarter of 2015 from the year-ago period, primarily due to Frederickson, which had increased dispatch due to stronger demand and lower fuel gas pricing as compared to 2014; Selkirk, which had a hedging agreement in place for November 2015; Morris, which experienced favorable PJM pricing as well as higher merchant demand in the fourth quarter of 2015, and Naval Station, due to a forced outage in the year-ago period.  These increases were partially offset by decreases at Tunis, due to the expiration of its PPA; Manchief, due to reduced dispatch, and Mamquam, which had a scheduled maintenance outage that extended into the fourth quarter of 2015.  

Twelve Months Ended December 31, 2015

Project availability increased to 95.2% in 2015 from 93.0% in 2014.  Increased availability at Nipigon, Piedmont, Cadillac and Orlando, all of which had maintenance outages in 2014, more than offset decreased availability at Mamquam, Manchief and Naval Training Center, which had scheduled maintenance outages in 2015.  (The 2015 availability figure excludes Tunis.) 

Generation decreased by 0.7% in 2015 from 2014, primarily due to a PPA expiration at Tunis (December 2014); lower dispatch at Manchief (demand), Chambers (unfavorable pricing), Mamquam (scheduled maintenance outage and lower water flows), and Curtis Palmer (lower water flows).  These decreases were partially offset by an increase at Frederickson due to higher dispatch and increases at Nipigon (outage in 2014 and waste heat), Calstock (waste heat) and Morris (favorable PJM pricing/increased merchant demand). 

Financial Results

In the second quarter of 2015, the Company revised its reportable business segments as a result of recent significant asset sales and in order to align with changes in management's structure, resource allocation and performance assessment in making decisions regarding the Company's operations.  Results of the Company's businesses are now reported in four segments:  East U.S., West U.S., Canada and Un-allocated Corporate.

Table 2 provides a breakdown of project income and Project Adjusted EBITDA by segment for the three and twelve months ended December 31, 2015 as compared to the same periods in 2014.  The Company's Wind Projects were sold in June 2015 and are included in results of discontinued operations for the three and twelve-month periods ended December 31, 2015 and 2014.  Greeley was sold in March 2014 and is included as a component of discontinued operations for the twelve months ended December 31, 2014.  Results for project income and Project Adjusted EBITDA exclude discontinued operations.  Accordingly, results of the Wind Projects and Greeley are not included in Project income or Project Adjusted EBITDA for either the 2015 or 2014 periods shown in Table 2. 

Atlantic Power Corporation

Table 2 – Segment Results

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

Unaudited


Three months ended December 31

Twelve months ended December 31



2015

2014


2015

2014

Project income (loss)







East U.S.


$12.4

$3.9


$52.4

$8.7

West U.S.


0.3

(0.5)


7.6

(27.6)

Canada


(117.3)

1.3


(99.4)

(10.5)

Un-allocated Corporate


0.3

(2.6)


(2.0)

(9.5)

Total


(104.3)

2.1


(41.4)

(38.9)

Project Adjusted EBITDA







East U.S.


$23.8

$24.1


$104.8

$106.4

West U.S.


9.8

9.4


46.9

54.2

Canada


16.7

24.7


59.7

76.3

Un-allocated Corporate


0.1

(1.3)


(2.5)

(7.5)

Total


50.4

56.9


208.9

229.4

The results of the Wind Projects and Greeley, which are components of discontinued operations, are excluded from Project income and Project Adjusted EBITDA as presented in Table 2. 

Note: Project Adjusted EBITDA is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP; therefore, this measure may not be comparable to similar measures presented by other companies. Please refer to Tables 8 and 10 through 12 for a reconciliation of this non-GAAP measure to a GAAP measure.  The Company has not reconciled this non-GAAP financial measure relating to individual project segments to the directly comparable GAAP measure due to the difficulty in making the relevant adjustments on a segment basis. 

 

Three Months Ended December 31, 2015

Project income (loss) can fluctuate significantly due to non-cash adjustments to "mark-to-market" the fair value of derivatives.  Non-cash goodwill impairment charges and gains or losses on the sale of assets are included in project income and can also affect year-over-year comparisons.  None of these items are included in Project Adjusted EBITDA.

In the fourth quarter of 2015, the Company reported a project loss of $(104.3) million as compared to project income of $2.1 million in the year-ago period.  Results for the fourth quarter of 2015 included a non-cash impairment charge of $127.8 million.  Included in this charge were impairments of property, plant and equipment at Williams Lake and Calstock of $74.1 million and $2.5 million, respectively.  The Company also recorded full impairments of the remaining goodwill at Williams Lake and Calstock of $35.6 million and $1.9 million, respectively, and a partial goodwill impairment of $13.7 million at Curtis Palmer.  No impairment charges were recorded in the fourth quarter of 2014.  Results for the fourth quarter of 2015 also included a $23.2 million mark-to-market increase in the fair value of derivatives as compared to the fourth quarter of 2014.

Project Adjusted EBITDA includes the proportional share of Project Adjusted EBITDA from the Company's equity method projects.  Project Adjusted EBITDA is a non-GAAP measure.  Table 8 of this press release provides a reconciliation of Project Adjusted EBITDA to Project income. 

Project Adjusted EBITDA decreased $6.5 million to $50.4 million in the fourth quarter of 2015 from $56.9 million in the fourth quarter of 2014.  The most significant drivers of lower EBITDA were the Tunis PPA expiration, lower water flows at Mamquam, lower excess energy margins at Chambers and lower electric revenue at Williams Lake.  These factors were partially offset by higher Project Adjusted EBITDA at Curtis Palmer, which benefited from higher water flows, and Selkirk, which realized lower fuel costs.  In addition, the Un-allocated Corporate segment improved by $1.4 million in the fourth quarter of 2015 from the year-ago period, primarily due to $1.2 million of lower project-level compensation expense.  Currency had an approximate $(3.0) million impact on Project Adjusted EBITDA, with an average U.S. dollar to Canadian dollar exchange rate for the fourth quarter of 2015 of 1.34 versus 1.14 for the year-ago period.  However, from an overall cash standpoint, that impact was mostly offset by the benefit of the stronger U.S. dollar on the Company's Canadian-denominated interest and dividend payments.

Corporate-level G&A expense (shown as "Administration" on the Consolidated Statements of Operations) decreased $4.8 million to $6.4 million in the fourth quarter of 2015 from $11.2 million a year ago.  The improvement was due primarily to a $1.4 million decrease in legal expenses associated with the U.S. and Canadian shareholder actions, $0.6 million of reduced employee compensation expenses and $0.5 million of lower business development expenses.  The 2014 figure also included $0.5 million of certain fees that were not incurred in 2015.

Cash Flow Metrics

Cash flows from operating activities (GAAP) and Free Cash Flow include the cash flows from projects classified as discontinued operations.  Free Cash Flow is a non-GAAP measure.  Table 10 of this press release provides a reconciliation of Free Cash Flow to cash flows from operating activities.

Cash flows provided by operating activities of $19.7 million in the fourth quarter of 2015 increased $0.6 million from $19.1 million in the fourth quarter of 2014.  The increase was primarily attributable to significantly lower interest expense and lower corporate G&A expense, which were partially offset by lower Project Adjusted EBITDA (primarily due to the sale of the Wind projects in 2015) and other factors.

Free Cash Flow, which is after debt repayment, capital expenditures and preferred dividends, was $(0.4) million for the fourth quarter of 2015 compared to $(7.2) million for the fourth quarter of 2014.  The increase is primarily due to a decrease in project-level debt repayments and a reduction in distributions to noncontrolling interests, including preferred dividends (which were favorably affected by the exchange rate).

Cash Distributions from Projects and the adjusted cash flow metrics discussed below, all of which are non-GAAP measures, exclude cash flows from projects classified as discontinued operations.  Adjusted Cash Flows from Operating Activities, which excludes discontinued operations, changes in working capital, severance, restructuring charges, acquisition and disposition expenses and debt prepayment and redemption costs, is a measure of the cash flow available to the Company to make principal repayments on its debt (primarily through amortization and the cash sweep under the APLP term loan), invest in its fleet through required or discretionary capital expenditures, and make dividend payments to preferred shareholders.  Adjusted Free Cash Flow is after debt repayment or amortization, capital expenditures and preferred dividends, but is before any discretionary uses of cash flow, including repurchases of debt and equity securities, external growth investments or additional internal capex projects.  Tables 10 and 11 of this press release provide a reconciliation of the Company's non-GAAP cash flow metrics to cash flows from operating activities.

Cash Distributions from Projects decreased $11.6 million to $46.0 million for the fourth quarter of 2015 from $57.6 million for the same period in 2014.  The decrease was primarily due to the PPA expiration at Tunis, which had a negative impact of $4.7 million; the Ontario projects, due to the timing of customer payments; Mamquam, which experienced record low water flows in 2015; the Navy projects, which benefited from the timing of gas payments in the 2014 period, and Williams Lake, which experienced an unfavorable foreign exchange rate impact.  This net decrease was partially offset by increases at Nipigon, which underwent a major outage to upgrade and replace its steam generator in 2014; Curtis Palmer, which benefited from higher water flows, and Kenilworth, which benefited from the timing of a gas payment.

Adjusted Cash Flows from Operating Activities increased $11.4 million to $29.3 million in the fourth quarter of 2015 from $17.9 million in the year-ago period, primarily because of lower cash interest payments and lower corporate G&A expense, partially offset by lower Project Adjusted EBITDA.  The 2015 result excludes $5.0 million of cash tax payments associated with the sale of the Wind Projects; the 2014 result excludes operating cash flows of the Wind Projects of $11.3 million.

Adjusted Free Cash Flow increased to $9.2 million in the fourth quarter of 2015 from $(1.4) million in the fourth quarter of 2014.  The $10.6 million increase was primarily attributable to higher Adjusted Cash Flows from Operating Activities and several other less significant factors. 

Twelve Months Ended December 31, 2015

Project loss for the full year 2015 was $(41.4) million as compared to ($38.9) million in 2014.  The increased loss was attributable to a $21.2 million increase in impairment expense and the absence of an $8.6 million gain on the sale of Delta-Person recorded in 2014, partially offset by an $11.2 million increase in equity earnings of affiliates, a $9.5 million reduction in interest expense and an $8.6 million increase in the change in the fair value of derivatives.  Impairment expense in 2015 was as described in the discussion of results for the three months ended December 31, 2015, while in 2014 it included $106.6 million of impairments of long-lived assets and goodwill at Tunis and of goodwill at Kenilworth, Manchief and Williams Lake.

Project Adjusted EBITDA decreased $20.5 million to $208.9 million for the full year 2015 from $229.4 million for 2014.  The most significant drivers of the decline were lower results from Tunis, due to its mothballed status; Selkirk, due to the expiration of its PPA and reduced dispatch in an unfavorable market environment; Manchief, which had a gas turbine maintenance outage; lower water flows at Curtis Palmer and Mamquam; higher fuel and maintenance expense at North Bay and Kapuskasing, partially offset by higher waste heat generation; and lower excess energy margins at Chambers.  Currency had an approximate $(9.0) million impact on Project Adjusted EBITDA, with an average U.S. dollar to Canadian dollar exchange rate for 2015 of 1.27 versus 1.11 for the year-ago period.  These negative factors were partially offset by increases at Orlando, which benefited from higher generation, lower fuel expenses due to lower gas prices and rate escalations under the PPA; Morris, which had lower fuel expense, reduced property taxes, and higher PJM capacity pricing, partially offset by lower merchant pricing than the comparable year-ago period; Nipigon, which had a maintenance outage in the comparable year-ago period and also benefited from rate escalations and high levels of waste heat; North Island, which had a gas turbine overhaul in 2014, and Calstock, which had higher waste heat generation and lower maintenance expense than the year-ago period.  In addition, the Un-allocated Corporate segment had a reduced loss of $(2.5) million versus $(7.5) million in the year-ago period, due primarily to a reduction in project-level compensation expense and decreased development and administrative costs. 

Corporate-level G&A expense decreased $8.5 million to $29.4 million for the full year 2015 from $37.9 million in 2014.  The improvement was primarily attributable to a $3.9 million reduction in legal expenses associated with the U.S. and Canadian shareholder actions, a $1.9 million decrease in business development costs related to divestitures and a $1.9 million decrease in employee severance expense.

Cash Flow Metrics

Cash flows provided by operating activities of $87.4 million for the full year 2015 increased $22.4 million from $65.0 million for the comparable period in 2014.  The increase is primarily due to a $27.3 million reduction in financing transaction costs and a $13.6 million reduction in total G&A expense, partially offset by a $21.9 million reduction in operating cash flows from the Wind Projects, which were sold in June 2015.

Free Cash Flow was $(19.8) million for the full year 2015 compared to $(55.6) million for 2014.  The increase is primarily due to the $22.4 million increase in operating cash flows described previously, a $7.3 million decrease in distributions to noncontrolling interests related to Canadian Hills and Rockland, a $2.8 million decrease in preferred dividends (driven primarily by the exchange rate) and a $2.1 million reduction in capital expenditures.  Repayment of the APLP term loan and amortization of project debt totaled $83.4 million in 2015 versus $84.6 million in 2014, including $6.4 million associated with the Wind Projects and an $8.1 million repayment of Piedmont principal at term loan conversion in February 2014.

Cash Distributions from Projects decreased $16.8 million to $192.3 million for the full year 2015 from $209.1 million for 2014.  The decrease was primarily due to PPA expirations at Tunis and Selkirk, an impact of $13.1 million and $9.3 million, respectively; Manchief, due to the gas turbine outage and reduced dispatch, and the Navy projects, which benefited from the timing of gas payments in the 2014 period.  This net decrease was  partially offset by increases at the following projects:  Chambers, due to a change in the timing of distributions; Morris, which benefited from lower gas prices, reduced property taxes and a higher PJM capacity rate; Orlando, which benefited from lower gas prices, higher capacity payments and increased generation; Calstock, which benefited from additional waste heat and lower maintenance expense relative to the year-ago period when it had an outage, and Nipigon, which benefited from improved availability following two outages in 2014, additional waste heat and higher capacity payments due to contract escalation.

Adjusted Cash Flows from Operating Activities of $105.3 million for the full year 2015 increased $12.9 million from $92.4 million in 2014.  The 2015 result excludes $6.2 million of cash tax payments in the third and fourth quarters associated with the sale of the Wind Projects as well as the $14.0 million premium and $5.5 million of accrued interest paid at redemption of the 9.0% Senior Unsecured Notes (the "9.0% Notes") in June 2015.  The 2014 result excludes $49.4 million of interest expense associated with the debt refinancing and repurchase transactions in the first quarter of 2014.  The increase in Adjusted Cash Flows from Operating Activities was primarily attributable to a $26.7 million reduction in cash interest payments and an $8.5 million reduction in corporate G&A expense, partially offset by lower Project Adjusted EBITDA.

Adjusted Free Cash Flow of $1.8 million increased $2.1 million for the full year 2015 from $(0.3) million in 2014.  Results for both years exclude interest expense associated with debt refinancing or redemption as described above.  The 2014 result also excludes an $8.1 million Piedmont principal repayment at term loan conversion.  The increase in Adjusted Free Cash Flow was primarily attributable to the $12.9 million increase in Adjusted Cash Flows from Operating Activities described above and a $2.8 million reduction in preferred dividend payments (driven by a more favorable exchange rate), which were mostly offset by a $13.3 million increase in term loan and project debt amortization.  The 2015 Adjusted Free Cash Flow of $1.8 million was at the lower end of the Company's guidance range of $0 to $10 million due to a delay in receipt of a customer reimbursement for a 2015 construction project.  The $6 million cash payment was received in February 2016.

Results of Discontinued Operations

The Wind Projects were sold in June 2015 and are a component of discontinued operations for the three and twelve months ended December 31, 2015 and 2014.  Greeley was sold in March 2014 and is included as a component of discontinued operations for the twelve months ended December 31, 2014.  The results for Greeley were immaterial during that period.

Project Adjusted EBITDA of the Wind Projects was $0.0 million for the fourth quarter of 2015 versus $20.7 million for the comparable year-ago period.  Results for the full year 2015 were $28.1 million versus $69.8 million for 2014. 

Cash flows from operating activities of the Wind Projects were $0.0 million and $21.9 million for the fourth quarter and full year 2015, respectively.  These operating cash flows were reduced by $5.0 million and $6.2 million, respectively, of withholding and alternative minimum tax payments associated with the sale of the Wind Projects.  The operating cash flows of the Wind Projects were $11.3 million and $48.3 million, respectively, for the fourth quarter and full year 2014.

Liquidity

As shown in Table 3, the Company's liquidity at December 31, 2015 was $178.4 million, including $72.4 million of unrestricted cash.  In February 2016, there were two developments that positively affected the Company's liquidity.  The Company received a $6 million reimbursement for construction costs incurred in 2015 at one of its projects on behalf of the project's customer.  That reimbursement is subject to the 50% cash sweep of the APLP term loan.  Separately, Standard & Poor's upgraded the Company's corporate credit rating to B+ from B, which allowed the Company to reduce an existing letter of credit with one of its counterparties by $10 million.  Pro forma for these two adjustments, the Company's liquidity would be approximately $13 million higher than the year end 2015 level.

Atlantic Power Corporation



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



Unaudited




September 30, 2015

December 31, 2015

Revolver capacity

$210.0

$210.0

Letters of credit outstanding

(109.2)

(104.0)

Unused borrowing capacity

100.8

106.0

Unrestricted cash (1)

76.4

72.4

Total Liquidity

$177.2

$178.4

(1) Includes project-level cash for working capital needs of $13.0 million at each of September 30, 2015 and December 31, 2015.

Note:  Does not include restricted cash of $14.5 million at September 30, 2015 and $15.2 million at December 31, 2015.

Other Financial Updates

Impairment Charge and Finding of Material Weakness

In the fourth quarter of 2015, the Company performed its annual goodwill impairment test and determined that it was necessary to impair the carrying value of long-lived assets at Calstock and Williams Lake and to record a full impairment of remaining goodwill at both projects as well as a partial impairment of goodwill at Curtis Palmer.  The primary reason for the impairment was the impact of significantly lower forward power prices, driven by an extended period of lower natural gas and oil prices, on expected cash flows from the projects following the expirations of their respective PPAs.  The impairment charge, which is non-cash, totaled $127.8 million.  There was no impact on Project Adjusted EBITDA or the Company's adjusted cash flow metrics.

As discussed in the Company's annual report on Form 10-K, management has determined that a material weakness existed in the Company's internal control over financial reporting because its annual goodwill impairment test resulted in an initial finding that no impairment of long-lived assets was required and that goodwill would be impaired by a smaller amount than subsequently determined.  Management is in the process of determining and implementing a remediation plan and expects the control weakness to be remediated in the coming year. 

Progress on Debt Reduction

In the fourth quarter of 2015, the Company made additional progress in reducing its debt, making $11.7 million of payments on the APLP term loan and amortizing $4.4 million of project-level debt.  The Company also repurchased $0.2 million of convertible debentures pursuant to the NCIB. 

For the full year 2015, the Company repaid $68.3 million of the APLP term loan through the 1% mandatory annual amortization and the 50% cash sweep, reducing the outstanding balance to $473.2 million, and amortized $15.1 million of project-level debt.   Discretionary repurchases of its convertibles pursuant to the NCIB totaled $21.8 million; in addition, the Company repurchased $9.0 million of its 9.0% Notes in the first quarter of 2015.  The Company used the proceeds from the sale of its Wind Projects to fund the redemption of the $310.9 million remaining principal amount of the 9.0% Notes in July.  Approximately $249 million of debt associated with the Wind Projects was deconsolidated as a result of the sale.

Since year end 2013, the Company has reduced its total debt by $833 million, including its $76 million share of debt at equity-owned projects (mostly for Wind projects).  The interest cost savings associated with total debt reduction are more than $65 million on an annualized basis.

Further debt reduction is expected to be achieved through continued amortization of project-level debt and the APLP term loan, which together are expected to average approximately $65 to $70 million annually over the next two years. 

The Company also has an improved corporate maturity profile.  The remaining corporate debt consists of $285 million (U.S. dollar equivalent) of convertible debentures maturing in 2017 ($103 million) and 2019 ($182 million).  The Company continues to explore opportunities to address these maturities.

In February 2016, the Company received a corporate credit rating upgrade from Standard & Poor's to B+ from B.  This follows an upgrade by Moody's last October to B1 from B2.  Both agencies have "stable" ratings outlooks for the Company.     

G&A Expense Targets

For the full year 2015, total G&A expense was $31.9 million, including $2.6 million of development expense and project-level G&A that are included in Project Adjusted EBITDA.  The $31.9 million includes $4 million of severance expense and $2 million of restructuring and other charges.  The Company expects 2016 total G&A expense of approximately $27 million, which would represent a 50% cumulative reduction from the 2013 level of approximately $54 million.

Optimization Investments

The majority of the Company's capital expenditures are discretionary investments in existing projects designed to increase their output or improve their efficiency in order to enhance the margins of these facilities.  The Company considers these investments to be an attractive use of its cash considering the relatively modest capital requirements and potential for strong risk-adjusted returns.

From 2013 to 2015, the Company invested approximately $22 million in such projects, net of a customer reimbursement, the most significant of which were the turbine upgrades at Curtis Palmer completed in 2013 and 2014, the Nipigon Once-Through Steam Generator upgrade and feedwater booster pump installation, completed in 2014 and 2015, respectively, and several projects at Morris.  In 2015, the Company realized a cash flow benefit from completed projects of approximately $6 million.  This contribution, although reduced by low water flows at Curtis Palmer and high levels of waste heat at Nipigon, was in line with the Company's expectations.  The Company expects this contribution to increase to approximately $10 million in 2016, including an initial cash flow contribution from projects expected to be completed by mid-2016.  This outlook assumes lower waste heat levels in 2016 than in 2015, though still above typical levels, and average water flows at Curtis Palmer.

The Company expects that optimization-related investments will total approximately $4 million in 2016, mostly for upgrades to a boiler and two gas turbines at Morris and a spillway upgrade project at Curtis Palmer.  The Company has other optimization projects under consideration that could require additional expenditures in 2016.

Maintenance and Capex

For the full year 2015, capital expenditures were $11 million, of which approximately $9 million was attributable to discretionary optimization projects.  In addition to amounts capitalized, the Company incurs maintenance expense to maintain its projects.  Total maintenance expense was approximately $56 million for 2015.

For 2016, the Company expects to have capital expenditures of $16 to $19 million, with the range attributable to potential optimization projects not yet firmly committed to.  The most significant budgeted expenditures are for the optimization projects at Morris and Curtis Palmer (approximately $4 million) and for the 2016 portion of costs associated with the repowering of Tunis and a new fuel shredder for Williams Lake (approximately $7 million for the two projects).  In addition, the Company expects to incur maintenance expense of approximately $57 million

Morris Energy Services Agreement (ESA) and Planned Outages

As announced in December, the Company has executed an agreement with the customer at its Morris project to modify and extend the ESA from November 2023 to December 2034.  The modifications to the ESA are expected to be modestly accretive to the Project Adjusted EBITDA from Morris on average relative to the original contract terms.  As of December 31, 2015, including the impact of the Morris ESA extension, the weighted-average remaining life of the Company's PPAs is 7.5 years (on an EBITDA-weighted basis). 

Separately, and not related to the ESA modifications and extension, the Company expects that Morris will undergo an approximately six-week major maintenance outage in the late summer of 2016.  During this outage, the Company will continue work on upgrading two of the project's combustion turbines, overhaul the steam turbine and upgrade the plant's Distributed Controls System.  Together with an upgrade to one of the project's boilers scheduled to be completed earlier in the year, these upgrades are expected to increase output and fuel efficiency as well as enhance reliability of steam delivery for the customer.  Higher maintenance expense and lost margin associated with the extended outage, as well as other less significant factors, are expected to reduce Project Adjusted EBITDA from the Morris project by approximately $9 million in 2016 from a higher-than-average level in 2015.

Normal Course Issuer Bid (NCIB)

As announced in December 2015, the Company has implemented an NCIB for up to 10% of each of its outstanding convertible debentures and its common shares and up to 5% of Atlantic Power Preferred Equity Ltd.'s preferred shares.  The NCIB became effective in late December and is scheduled to expire on December 28, 2016.  Since late December, the Company has repurchased approximately 575,000 shares under the NCIB at a total cost of approximately US$1.0 million.

Changes to Capital Allocation Strategy

In February 2016, the Company announced changes to its capital allocation strategy designed to create value for shareholders in a tax-efficient manner while improving the Company's financial flexibility and strengthening its balance sheet.  These changes included elimination of the common stock dividend (and the related dividend reinvestment plan), effective immediately, and prioritization of its discretionary cash after debt repayment for higher-return purposes, including repurchases of its debt and equity securities under the NCIB at compelling price-to-value levels and attractive investments in internal optimization projects.

2016 Guidance

Atlantic Power Corporation



Table 4 –  FY 2015 Actual Results vs. 2016 Guidance



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



Unaudited




FY 2015

FY 2016


Actual

Guidance

Project Adjusted EBITDA

$208.9

$200 - $220

Adjusted Cash Flows from Operating Activities (1)

$105.3

$110 - $130

Adjusted Free Cash Flow (2)

$1.8

$20 - $40

APLP Project Adjusted EBITDA (3)

$155.2

$145 - $155




(1) Adjusted Cash Flows from Operating Activities is used to evaluate cash flows from operating activities without the effects of changes in
working capital balances, acquisition and disposition expenses, litigation expenses, severance and restructuring charges, debt prepayment
and redemption costs and cash provided by or used in discontinued operations.  The intent is to reflect normal operations and remove items
that are not reflective of the long-term operations of the business.

(2) Adjusted Free Cash Flow is defined as Free Cash Flow excluding changes in working capital balances, acquisition and disposition expenses, litigation expense, severance and restructuring charges, debt prepayment and redemption costs and cash provided by or used in discontinued operations.  Free Cash Flow is defined as cash flows from operating activities less capex; project-level debt repayments, including amortization of the APLP term loan; and distributions to noncontrolling interests, including preferred share dividends. 

(3) APLP is a wholly owned subsidiary of the Company.  APLP Project Adjusted EBITDA is a summation of Project Adjusted EBITDA at each APLP project, and is calculated in a manner which is consistent with the Company's Project Adjusted EBITDA calculation. 


Note: Project Adjusted EBITDA, Adjusted Cash Flows from Operating Activities, Adjusted Free Cash Flow and APLP Project Adjusted EBITDA are not recognized measures under GAAP and do not have any standardized meaning prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies.  The Company has not provided a reconciliation of forward-looking non-GAAP measures, due primarily to variability and difficulty in making accurate forecasts and projections, as not all of the information necessary for a quantitative reconciliation is available to the Company without unreasonable efforts.

Table 4 shows the Company's full-year 2016 guidance as compared to the actual results for 2015.  Key drivers are as follows: 

  • Total Company Project Adjusted EBITDA of $200 to $220 million. Positive drivers in 2016 include an assumed return to average water flows at Mamquam and Curtis Palmer (versus historic lows in 2015), a full-year return on optimization investments and the non-recurrence of the major gas turbine outage at Manchief in 2015. These are mostly offset by the negative impacts of an extended outage at Morris, an unfavorable exchange rate, and an assumed reduction in waste heat from historically high levels in 2015.
  • APLP Project Adjusted EBITDA of $145 to $155 million. Drivers are consistent with those for Total Company Project Adjusted EBITDA.
  • Adjusted Cash Flows from Operating Activities of $110 to $130 million. The expected increase in 2016 is largely attributable to lower cash interest payments.
  • Adjusted Free Cash Flow of $20 to $40 million. The expected increase in 2016 is attributable to the expected increase in Adjusted Cash Flows from Operating Activities, lower debt repayment and a customer reimbursement for 2015 construction costs received in 2016.

Other Recent Developments

Share Purchases by Insiders

In the fourth quarter, two senior executives and one director of the Company purchased a total of approximately 493,000 common shares of the Company at an average price of US$1.77 per share.  Including those made in previous quarters, purchases by management and directors this year total approximately 1.05 million common shares.  The average purchase price for these purchases was US$2.31 per share.  There have been no sales of shares by officers or directors this year, other than those sold automatically for tax withholding purposes upon vesting under the Long-Term Incentive Plan.   

Shareholder Litigation

As announced by the Company in December, both the U.S. and Ontario securities class action suits were dismissed by the respective courts, with no payments required by the Company.  Following the resolution of the Ontario matter, the petitioner in the Quebec proceedings has agreed in principle with the defendants in the suit to discontinue the proceedings, with each side bearing its own costs.  The agreement is subject to the approval of the Superior Court of Quebec.

Supplementary Financial Information

For further information, attached to this news release is a summary of Project Adjusted EBITDA by segment for the three and twelve months ended December 31, 2015 and 2014 (Table 8) with a reconciliation to project income (loss); a bridge from Project Adjusted EBITDA to Cash Distributions from Projects by segment for the year ended December 31, 2015 (Table 9A) and the year ended December 31, 2014 (Table 9B); a reconciliation of Cash Distributions from Projects and Project Adjusted EBITDA to net income (loss) and of various non-GAAP cash flow metrics to cash flows from operating activities for the three and twelve months ended December 31, 2015 and 2014 (Table 10); reconciliations of Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow to cash flows from operating activities for the three and twelve months ended December 31, 2015 and 2014 (Tables 11A and 11B); and a summary of Project Adjusted EBITDA for selected projects (top contributors based on the Company's 2015 budget, representing approximately 90% of total Project Adjusted EBITDA) for the three and twelve months ended December 31, 2015 and 2014 (Table 12). 

Investor Conference Call and Webcast

Atlantic Power's management team will host a telephone conference call on Tuesday, March 8, 2016 at 8:30 AM ET.  An accompanying slide presentation will be available on the Company's website prior to the call. 

Conference Call / Webcast Information:

DateTuesday, March 8, 2016 
Start Time8:30 AM ET
Phone Number:  U.S. (Toll Free) 1-877-870-4263; Canada (Toll Free) 1-855-669-9657; International (Toll) 1-412-317-0790
Conference Access:  Please request access to the Atlantic Power conference call.
Webcast:  The call will be broadcast over Atlantic Power's website at www.atlanticpower.com.

Replay/Archive Information:

Replay:  Access conference call number 10079885 at the following telephone numbers:  U.S. (Toll Free) 1-877-344-7529; Canada (Toll Free) 1-855-669-9658; International (Toll) 1-412-317-0088.  The replay will be available one hour after the end of the conference call through April 6, 2016 at 11:59 PM ET.      

Webcast archive:  The conference call will be archived on Atlantic Power's website at www.atlanticpower.com for a period of 12 months. 

About Atlantic Power

Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada.  The Company's power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices.  Atlantic Power's power generation projects in operation have an aggregate gross electric generation capacity of approximately 2,138 megawatts ("MW") in which its aggregate ownership interest is approximately 1,500 MW.  The Company's current portfolio consists of interests in twenty-three operational power generation projects across nine states in the United States and two provinces in Canada.

Atlantic Power trades on the New York Stock Exchange under the symbol AT and on the Toronto Stock Exchange under the symbol ATP.  For more information, please visit the Company's website at www.atlanticpower.com or contact:

Atlantic Power Corporation 
Investor Relations
(617) 977-2700 
info@atlanticpower.com

Copies of certain financial data and other publicly filed documents are filed on SEDAR at www.sedar.com or on EDGAR at www.sec.gov/edgar.shtml under "Atlantic Power Corporation" or on the Company's website.

Cautionary Note Regarding Forward-Looking Statements

To the extent any statements made in this news release contain information that is not historical, these statements are forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended, and under Canadian securities law (collectively, "forward-looking statements").

Certain statements in this news release may constitute "forward-looking statements", which reflect the expectations of management regarding the future growth, results of operations, performance and business prospects and opportunities of the Company and its projects.  These statements, which are based on certain assumptions and describe the Company's future plans, strategies and expectations, can generally be identified by the use of the words "may," "will," "project," "continue," "believe," "intend," "anticipate," "expect" or similar expressions that are predictions of or indicate future events or trends and which do not relate solely to present or historical matters.  Examples of such statements in this press release include, but are not limited, to statements with respect to the following:  

  • that the Company's discretionary cash flow after debt repayment is growing, and there are ample opportunities to invest the cash at good returns;
  • the Company's ability to make progress on further extensions of its existing PPAs;
  • the Company's ability to address its convertible debenture maturities;
  • the Company expects to further reduce debt through continued amortization of project-level debt and the APLP term loan, which together are expected to average approximately $65 to $70 million annually over the next two years;
  • the Company expects to have total G&A costs of approximately $27 million in 2016;
  • the Company expects to realize a cash flow benefit from discretionary investments in its existing projects of approximately $10 million in 2016;
  • the Company expects that discretionary optimization investments in its fleet will be approximately $4 million in 2016;
  • the Company expects that in 2016, capital expenditures will total approximately $16 to $19 million, before a $5 million credit for a customer reimbursement, and maintenance expense will total approximately $57 million;
  • the Company expects a modest increase in Project Adjusted EBITDA from Morris on average relative to the terms of the original ESA;
  • the Company expects that Morris will undergo an extended maintenance outage in the late summer of 2016;
  • upgrades of the Morris project's combustion turbines and one of its boilers are expected to enhance the project's output and reliability;
  • the Company expects an approximate $9 million reduction in 2016 Project Adjusted EBITDA from Morris due to the planned outages and other less significant factors in 2016;
  • the Company may purchase, through the NCIB, up to 10% of each of its convertible debentures and common shares and Atlantic Power Preferred Equity Ltd. may purchase up to 5% of its preferred shares;
  • changes to the Company's capital allocation strategy will create value in a tax-efficient manner while improving the Company's financial flexibility and strengthening its balance sheet;
  • the Company's ability to capture value from repurchases of its equity and debt securities;
  • the Company's plans to focus on organic growth and to evaluate external opportunities in a disciplined and opportunistic manner;
  • the Company's ability to realize high returns on its internal growth investments;
  • 2016 Project Adjusted EBITDA will be in the range of $200 to $220 million;
  • 2016 APLP Project Adjusted EBITDA will be in the range of $145 to $155 million;
  • 2016 Adjusted Cash Flows from Operating Activities will be in the range of $110 to $130 million;
  • 2016 Adjusted Free Cash Flow will be in the range of $20 to $40 million;
  • the nature of any further proceedings in the Quebec securities action;
  • the Company's ability to remediate the material weakness in its internal controls over financial reporting; and
  • the results of operations and performance of the Company's projects, business prospects, opportunities and future growth of the Company will be as described herein.

Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not or the times at or by which such performance or results will be achieved.  Please refer to the factors discussed under "Risk Factors" and "Forward-Looking Information" in the Company's periodic reports as filed with the Securities and Exchange Commission from time to time for a detailed discussion of the risks and uncertainties affecting the Company, including, without limitation, the outcome or impact of the Company's business plan, including the objective of enhancing the value of its existing assets through optimization investments and commercial activities, delevering its balance sheet to improve its cost of capital and ability to compete for new investments, and utilizing its core competencies to create proprietary investment opportunities, and the Company's ability to raise additional capital for growth and/or debt reduction, and the outcome or impact on the Company's business of any such actions.  Although the forward-looking statements contained in this news release are based upon what are believed to be reasonable assumptions, investors cannot be assured that actual results will be consistent with these forward-looking statements, and the differences may be material.  These forward-looking statements are made as of the date of this news release and, except as expressly required by applicable law, the Company assumes no obligation to update or revise them to reflect new events or circumstances.  The Company's ability to achieve its longer-term goals, including those described in this news release, is based on significant assumptions relating to and including, among other things, the general conditions of the markets in which it operates, revenues, internal and external growth opportunities, its ability to sell assets at favorable prices or at all and general financial market and interest rate conditions.  The Company's actual results may differ, possibly materially and adversely, from these goals.


Atlantic Power Corporation



Table 5 – Consolidated Balance Sheet (in millions of U.S. dollars)



(Unaudited)




December 31,

December 31,


2015

2014

Assets



Current assets:



Cash and cash equivalents

$72.4

$106.0

Restricted cash

15.2

22.5

Accounts receivable

39.6

46.2

Inventory

16.9

19.3

Prepayments and other current assets

8.3

10.6

Assets held for sale

-

790.4

Income taxes receivable

3.5

0.2

Other current assets

4.4

3.3

Total current assets

160.3

998.5




Property, plant and equipment, net

777.7

962.9

Equity investments in unconsolidated affiliates

286.2

306.9

Power purchase agreements and intangible assets, net

308.9

377.1

Goodwill

134.5

197.2

Derivative instruments asset

0.3

1.1

Deferred financing costs

42.5

62.8

Other assets

6.7

9.5

Total assets

$1,717.1

$2,916.0




Liabilities



Current liabilities:



Accounts payable

$6.9

$9.4

Accrued interest

1.6

5.3

Other accrued liabilities

28.8

30.7

Current portion of long-term debt

15.8

20.0

Current portion of derivative instruments liability

36.7

36.1

Liabilities held for sale

-

271.8

Other current liabilities

2.5

6.8

Total current liabilities

92.3

380.1




Long-term debt

717.5

1,145.9

Convertible debentures

285.4

340.6

Derivative instruments liability

20.8

47.5

Deferred income taxes

85.7

92.4

Power purchase and fuel supply agreement liabilities, net

27.0

33.4

Other long-term liabilities

53.2

59.6

Total liabilities

$1,281.9

$2,099.5




Equity



Common shares, no par value, unlimited authorized shares; 122,153,082 and 121,323,614


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

1,290.6

1,288.4

Accumulated other comprehensive loss

(139.3)

(68.3)

Retained deficit

(937.4)

(863.9)

Total Atlantic Power Corporation shareholders' equity

213.9

356.2

Preferred shares issued by a subsidiary company

221.3

221.3

Noncontrolling interests

-

239.0

Total equity

435.2

816.5

Total liabilities and equity

$1,717.1

$2,916.0

 

 

Atlantic Power Corporation







Table 6 – Consolidated Statements of Operations






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






Unaudited















Three months ended

Twelve months ended


December 31,

December 31,



2015

2014


2015

2014

Project revenue:







Energy sales


$46.6

$59.4


$191.5

$236.9

Energy capacity revenue


31.9

37.3


149.3

161.3

Other


19.9

23.1


79.4

91.7



98.4

119.9


420.2

489.9

Project expenses:







Fuel


39.8

50.9


165.1

210.4

Operations and maintenance


21.9

23.5


103.5

109.0

Development


-

1.0


1.1

3.7

Depreciation and amortization


26.2

30.2


110.0

122.3



87.9

105.6


379.7

445.4

Project other income (expense):







Change in fair value of derivative instruments


6.7

(16.5)


15.4

6.8

Equity in earnings of unconsolidated affiliates


8.4

(2.3)


36.7

25.5

Gain on sale of equity investments


-

8.6


-

8.6

Interest expense, net


(2.0)

(2.0)


(8.2)

(17.7)

Impairment


(127.8)

-


(127.8)

(106.6)

Other income (expense), net


(0.1)

-


2.0

-



(114.8)

(12.2)


(81.9)

(83.4)

Project income (loss)


(104.3)

2.1


(41.4)

(38.9)








Administrative and other expenses (income):







Administration


6.4

11.2


29.4

37.9

Interest, net


15.8

25.9


107.1

146.7

Foreign exchange gain


(11.2)

(17.9)


(60.3)

(38.3)

Other income, net


0.2

(0.6)


(3.1)

(0.6)



11.2

18.6


73.1

145.7

(Loss) income from continuing operations before income taxes


(115.5)

(16.5)


(114.5)

(184.6)

Income tax expense (benefit)


(30.1)

(11.4)


(30.4)

(31.4)

(Loss) income from continuing operations


(85.4)

(5.1)


(84.1)

(153.2)

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


(1.3)

(7.3)


19.5

(29.0)

Net income (loss)


(86.7)

(12.4)


(64.6)

(182.2)

Net income (loss) attributable to noncontrolling interests


-

(4.6)


(11.0)

(16.4)

Net income attributable to preferred share dividends of a subsidiary company

1.9

2.8


8.8

11.6

Net income (loss) attributable to Atlantic Power Corporation


($88.6)

($10.6)


($62.4)

($177.4)








Basic and diluted earnings per share:







Loss from continuing operations attributable to Atlantic Power Corporation

($0.60)

($0.07)


($0.76)

($1.37)

Income (loss) from discontinued operations, net of tax


(0.01)

(0.02)


$0.25

($0.10)

Net income (loss) attributable to Atlantic Power Corporation


($0.61)

($0.09)


($0.51)

($1.47)








Weighted average number of common shares outstanding:







Basic


122.1

121.0


121.9

120.7

Diluted


122.1

121.0


121.9

120.7








Dividends paid per common share:


$0.02

$0.03


$0.09

$0.29

(1) Includes contributions from the Wind Projects and Greeley, which are components of discontinued operations.










 

 

Atlantic Power Corporation





Table 7 – Consolidated Statements of Cash Flows (in millions of U.S. dollars)



Unaudited







Twelve months ended December 31,




2015

2014

Cash flows from operating activities:





Net Income (loss)



($64.6)

($182.2)

Adjustments to reconcile to net cash provided by operating activities:





Depreciation and amortization



120.3

162.6

Loss from discontinued operations



-

-

Gain on sale of assets



(48.7)

(2.9)

Gain on sale of equity investments



-

(8.6)

Gain on purchase and cancellation of convertible debentures



(3.1)

-

Stock-based compensation expense



2.3

3.5

Long-lived asset and goodwill impairment charges



127.8

106.6

Equity in earnings from unconsolidated affiliates



(36.2)

(25.8)

Distributions from unconsolidated affiliates



58.5

76.2

Unrealized foreign exchange gain



(60.5)

(38.8)

Change in fair value of derivative instruments



(14.7)

8.7

Change in deferred income taxes



(3.5)

(15.7)

Change in other operating balances





Accounts receivable



5.7

6.9

Inventory



2.4

(3.3)

Prepayments, refundable income taxes and other assets



20.9

21.1

Accounts payable



(8.9)

(4.1)

Accruals and other liabilities



(10.3)

(39.2)

Cash provided by operating activities



87.4

65.0






Cash flows provided by investing activities:





Change in restricted cash



7.3

72.6

Proceeds from sale of assets and equity investments, net



326.3

9.5

Contribution to unconsolidated affiliate



(0.6)

-

Development costs



(0.8)

-

Purchase of property, plant and equipment



(11.3)

(13.4)

Cash provided by investing activities



320.9

68.7






Cash flows used in financing activities:





Proceeds from senior secured term loan facility



-

600.0

Repayment of corporate and project-level debt



(403.3)

(639.8)

Repayment of convertible debentures



(18.9)

(43.0)

Deferred financing costs



-

(39.0)

Dividends paid to common shareholders



(11.1)

(34.9)

Dividends paid to noncontrolling interests



(3.7)

(11.1)

Dividends paid to preferred shareholders



(8.8)

(14.6)

Cash used in financing activities



(445.8)

(182.4)






Net increase (decrease) in cash and cash equivalents



(37.5)

(48.7)

Cash and cash equivalents at beginning of period at discontinued operations


3.9

(3.9)

Cash and cash equivalents at beginning of period



106.0

158.6

Cash and cash equivalents at end of period



$72.4

$106.0






Supplemental cash flow information





Interest paid



$100.0

$168.8

Income taxes paid, net



$10.2

$3.8

Accruals for construction in progress



$0.6

$0.0

 

Regulation G Disclosures

Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP, and is therefore unlikely to be comparable to similar measures presented by other companies.  Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in the fair value of derivative instruments.  Management uses Project Adjusted EBITDA at the project level to provide comparative information about project performance and believes such information is helpful to investors.  A reconciliation of Project Adjusted EBITDA to project income (loss) is provided in Table 8 below.  Investors are cautioned that the Company may calculate this measure in a manner that is different from other companies.

Cash Distributions from Projects, Adjusted Cash Flows from Operating Activities, Free Cash Flow and Adjusted Free Cash Flow are not measures recognized under GAAP and do not have standardized meanings prescribed by GAAP, and are therefore unlikely to be comparable to similar measures presented by other companies.  Adjusted Cash Flows from Operating Activities is used to evaluate cash flows from operating activities without the effects of changes in working capital balances, acquisition and disposition expenses, litigation expenses, severance and restructuring charges, and cash provided by or used in discontinued operations.  The intent is to reflect normal operations and remove items that are not reflective of the long-term operations of the business.  Free Cash Flow is defined as cash flows from operating activities less capex; project-level debt repayments, including amortization of the term loan; and distributions to noncontrolling interests, including preferred share dividends.

Adjusted Free Cash Flow is defined as Free Cash Flow excluding changes in working capital balances, acquisition and disposition expenses, litigation expense, severance and restructuring charges, and cash provided by or used in discontinued operations.  Management believes that these non-GAAP cash flow measures are relevant supplemental measures of the Company's ability to earn and distribute cash returns to investors.  A bridge of Project Adjusted EBITDA to Cash Distributions from Projects is provided in Tables 9A and 9B on page 19.  A reconciliation of Free Cash Flow to cash flows from operating activities is provided in Table 10 on page 20 of this release.  Reconciliations of Adjusted Free Cash Flow and Adjusted Cash Flows from Operating Activities to cash flows from operating activities are provided in Tables 11A and 11B on pages 21 and 22 of this release.  Investors are cautioned that the Company may calculate these measures in a manner that is different from other companies.

Atlantic Power Corporation







Table 8 – Project Adjusted EBITDA by Segment (in millions of U.S. dollars)





Unaudited















Three months ended December 31


Twelve months ended December 31


2015

2014



2015

2014

Project Adjusted EBITDA by segment







East U.S.

$23.8

$24.1



$104.8

$106.4

West U.S. (1)

9.8

9.4



46.9

54.2

Canada

16.7

24.7



59.7

76.3

Un-allocated Corporate

0.1

(1.3)



(2.5)

(7.5)

Total

$50.4

$56.9



$208.9

$229.4








Reconciliation to project income







Depreciation and amortization

$31.2

$35.3



$130.1

$155.9

Interest expense, net

2.1

2.4



9.8

20.5

Change in the fair value of derivative instruments

(6.7)

16.8



(15.4)

(6.2)

Other (income) expense

128.1

0.2



125.8

98.1

Project income (loss)

($104.3)

$2.1



($41.4)

($38.9)

(1) Excludes Greeley, which is a component of discontinued operations.





Notes: Table 8 excludes the Wind Projects, which comprise the entirety of the former Wind segment. The Wind Projects are designated as discontinued operations for the three and twelve months ended December 31, 2015 and 2014.

Table 8 presents Project Adjusted EBITDA, which is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP; therefore, this measure may not be comparable to a similar measure presented by other companies.

 

 

Atlantic Power Corporation





Table 9A – Cash Distributions from Projects (by Segment, in millions of U.S. dollars)



Twelve months ended December 31, 2015 (Unaudited)



















Unaudited

Project
Adjusted
EBITDA

Repayment of
long-term debt

Interest
expense,
net

Capital
expenditures

Other, including
changes in
working capital

Cash
Distributions
from
Projects

Segment












East U.S.












  Consolidated

$65.8


($8.9)


($8.2)


($7.6)


$2.8


$43.9

  Equity method

39.0


(6.0)


(1.6)


(0.2)


3.7


34.9

  Total

104.8


(14.9)


(9.8)


(7.8)


6.5


78.8

West U.S.












  Consolidated

33.6


-


-


(1.7)


4.3


36.1

  Equity method

13.3


-


-


(0.1)


0.7


13.9

  Total

46.9


-


-


(1.8)


4.9


50.0

Canada












  Consolidated

59.7


(0.3)


-


(2.3)


6.2


63.4

  Equity method

-


-


-


-


-


-

  Total

59.7


(0.3)


-


(2.3)


6.2


63.4

  Total consolidated

159.1


(9.1)


(8.2)


(11.6)


13.3


143.5

  Total equity method

52.3


(6.0)


(1.6)


(0.3)


4.4


48.8

Un-allocated corporate

(2.5)


-


-


0.3


2.2


(0.0)

Total

$208.9


($15.1)


($9.8)


($11.5)


$19.9


$192.3

Note: Table 9A presents Cash Distributions from Projects and Project Adjusted EBITDA, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies.

























Atlantic Power Corporation











Table 9B – Cash Distributions from Projects (by Segment, in millions of U.S. dollars)



Twelve months ended December 31, 2014 (Unaudited)




















Project Adjusted EBITDA

Repayment of
long-term debt

Interest
expense,
net

Capital expenditures

Other, including
changes in
working capital

Cash
Distributions
from
Projects

Segment












East U.S.












  Consolidated

$62.2


($14.6)


($11.4)


($2.6)


$2.5


$36.0

  Equity method

44.2


(5.0)


(2.9)


(0.6)


1.2


36.9

  Total

106.4


(19.6)


(14.4)


(3.2)


3.6


72.8

West U.S.












  Consolidated

39.8


-


-


-


1.7


41.6

  Equity method

14.4


-


-


(0.0)


0.5


14.9

  Total

54.2


-


-


(0.0)


2.3


56.4

Canada












  Consolidated

76.3


-


(0.0)


(7.8)


5.9


74.4

  Equity method

-


-


-


-


-


-

  Total

76.3


-


(0.0)


(7.8)


5.9


74.4

  Total consolidated

178.4


(14.6)


(11.5)


(10.4)


10.1


151.9

  Total equity method

58.6


(5.0)


(2.9)


(0.6)


1.7


51.7

Un-allocated corporate

(7.5)


-


-


(1.6)


14.6


5.5

Total

$229.4


($19.6)


($14.4)


($12.6)


$26.4


$209.1

Note: Table 9B presents Cash Distributions from Projects and Project Adjusted EBITDA, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies.

 

 

Atlantic Power Corporation









Table 10 – Free Cash Flow (in millions of U.S. dollars)









Unaudited




















Three months ended

December 31,


Twelve months ended

December 31,




2015

2014



2015

2014

Cash Distributions from Projects



$46.0

$57.6



$192.3

$209.1

Repayment of long-term debt



(4.3)

(3.6)



(15.1)

(19.6)

Interest expense, net



(2.3)

(2.5)



(9.8)

(14.4)

Capital expenditures



(1.2)

(3.1)



(11.5)

(12.6)

Other, including changes in working capital



3.5

9.9



19.9

26.4

Project Adjusted EBITDA



$50.4

$56.9



$208.9

$229.4

Depreciation and amortization



31.2

35.3



130.1

155.9

Interest expense, net



2.1

2.4



9.8

20.5

Change in the fair value of derivative instruments



(6.7)

16.8



(15.4)

(6.2)

Other (income) expense



128.1

0.2



125.8

98.1

Project income (loss)



($104.3)

$2.1



($41.4)

($38.9)

Administrative and other expenses (income)



11.2

18.6



73.1

145.7

Income tax expense (benefit)



(30.1)

(11.4)



(30.4)

(31.4)

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


(1.3)

(7.3)



19.5

(29.0)

Net income (loss)



($86.7)

($12.4)



($64.6)

($182.2)

Adjustments to reconcile to net cash provided by operating activities

120.8

56.2



142.2

265.8

Change in other operating balances



(14.5)

(24.8)



9.8

(18.6)

Cash flows from operating activities



$19.7

$19.1



$87.4

$65.0

Term loan facility repayments (1)



(11.7)

(11.3)



(68.3)

(58.4)

Project-level debt repayments



(4.4)

(6.6)



(15.1)

(26.2)

Purchases of property, plant and equipment (2)



(1.9)

(3.4)



(11.3)

(13.4)

Distributions to noncontrolling interests (3)



-

(2.2)



(3.7)

(11.0)

Dividends on preferred shares of a subsidiary company



(2.1)

(2.8)



(8.8)

(11.6)

Free Cash Flow



($0.4)

($7.2)



($19.8)

($55.6)

Additional GAAP cash flow measures:









Cash flows from investing activities



($2.7)

($7.7)



$320.9

$68.7

Cash flows from financing activities



($21.0)

($69.1)



($445.8)

($182.4)

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


(2) Excludes construction costs related to the Company's Canadian Hills project in 2014.




(3) Distributions to noncontrolling interests include distributions to the tax equity investors at Canadian Hills and to the other 50% owner of Rockland.  These projects were sold in June 2015.


Note: This table presents Cash Distributions from Projects, Project Adjusted EBITDA and Free Cash Flow, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies.

 

 

Atlantic Power Corporation  


Table 11A – Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow (in millions of U.S. dollars)

Three months ended December 31, 2015 and 2014
(Unaudited)


















Three months ended

December 31, 2015



Three months ended

December 31, 2014




Continuing
Operations

Discontinued
Operations

Total



Continuing
Operations

Discontinued
Operations

Total

Project Adjusted EBITDA



$50.4

$-

$50.4



$56.9

$20.7

$77.6

Adjustment for equity method projects (1)


6.0

-

6.0



10.5

(2.9)

7.6

Corporate G&A expense



(6.5)

-

(6.5)



(11.2)

-

(11.2)

Cash interest payments



(20.6)

-

(20.6)



(39.4)

(4.8)

(44.2)

Cash taxes



(1.0)

(5.0)

(6.0)



(1.1)

-

(1.1)

Other, including changes in working capital


(3.6)

-

(3.6)



(7.9)

(1.7)

(9.6)

Cash flows from operating
activities



$24.7

($5.0)

$19.7



$7.8

$11.3

$19.1

Changes in other operating balances


3.6

-

3.6



7.9

1.7

9.6

Severance charges



-

-

-



0.9

-

0.9

Restructuring and other charges



-

-

-



0.7

-

0.7

Shareholder litigation expenses



-

-

-



0.6

-

0.6

Refinancing transaction costs (Q1 2014)


1.0

-

1.0



-

-

-

Debt redemption costs (9.0% Notes)


-

-

-



-

-

-

Adjusted Cash Flows from Operating Activities

$29.3

($5.0)

$24.3



$17.9

$13.0

$30.9

Term loan facility repayments (2)



(11.7)

-

(11.7)



(11.3)

-

(11.3)

Project-level debt repayments



(4.4)

-

(4.4)



(3.7)

(2.9)

(6.6)

Purchases of property, plant and equipment (3)

(1.9)

-

(1.9)



(1.5)

(1.9)

(3.4)

Distributions to noncontrolling interests (4)


-

-

-



-

(2.2)

(2.2)

Dividends on preferred shares of a subsidiary company

(2.1)

-

(2.1)



(2.8)

-

(2.8)

Adjusted Free Cash Flow



$9.2

($5.0)

$4.2



($1.4)

$6.0

$4.6

Additional GAAP cash flow measures:










Cash flows from investing activities


(2.7)

-

(2.7)



(5.5)

(2.2)

(7.7)

Cash flows from financing activities


(21.0)

-

(21.0)



(59.8)

(9.3)

(69.1)

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


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

(3) Excludes construction costs related to the Company's Canadian Hills project in 2014.

(4) Distributions to noncontrolling interests primarily include distributions, if any, to the tax equity investors at Canadian Hills and to the other 50% owner of Rockland. These projects were sold in June 2015.

Note: This table presents Project Adjusted EBITDA, Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies.

 

 


Atlantic Power Corporation  





Table 11B – Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow (in millions of U.S. dollars)

Twelve months ended December 31, 2015 and 2014 (Unaudited)















Twelve months ended

 December 31, 2015



Twelve months ended

December 31, 2014




Continuing Operations

Discontinued Operations

Total



Continuing Operations

Discontinued Operations

Total

Project Adjusted EBITDA



$208.9

$28.1

$237.0



$229.4

$69.8

$299.2

Adjustment for equity method projects (1)


2.2

(2.7)

(0.5)



(0.8)

(6.1)

(6.9)

Corporate G&A expense



(29.4)

-

(29.4)



(37.9)

-

(37.9)

Cash interest payments



(98.3)

(1.5)

(99.8)



(154.9)

(13.8)

(168.7)

Cash taxes



(3.9)

(6.2)

(10.1)



(2.1)

-

(2.1)

Other, including changes in working capital

(7.8)

(2.0)

(9.8)



(17.0)

(1.6)

(18.6)

Cash flows from operating activities

$71.7

$15.7

$87.4



$16.7

$48.3

$65.0

Changes in other operating balances


7.8

2.0

9.8



17.0

1.6

18.6

Severance charges



3.9

-

3.9



6.1

-

6.1

Restructuring and other charges



0.6

-

0.6



1.7

-

1.7

Shareholder litigation expenses



0.6

-

0.6



1.4

-

1.4

Refinancing transaction costs (Q1 2014)


1.1

-

1.1



49.4

-

49.4

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


19.5

-

19.5



-

-

-

Adjusted Cash Flows from Operating
Activities


$105.3

$17.7

$123.0



$92.4

$49.9

$142.3

Term loan facility repayments (2)



(68.3)

-

(68.3)



(58.4)

-

(58.4)

Project-level debt repayments(3)



(15.1)

-

(15.1)



(11.7)

(6.4)

(18.1)

Purchases of property, plant and equipment (4)

(11.3)

-

(11.3)



(11.1)

(2.3)

(13.4)

Distributions to noncontrolling interests (5)


-

(3.7)

(3.7)



-

(11.0)

(11.0)

Dividends on preferred shares of a subsidiary company

(8.8)

-

(8.8)



(11.6)

-

(11.6)

Adjusted Free Cash Flow



$1.8

$14.0

$15.8



($0.3)

$30.2

$29.9

Additional GAAP cash flow measures:










Cash flows from investing activities



$333.7

($12.8)

$320.9



$73.5

($4.8)

$68.7

Cash flows from financing activities



($432.8)

($13.0)

($445.8)



($131.6)

($50.8)

($182.4)

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


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

(3) Excludes $8.1 million principal repayment at Piedmont on term loan conversion (February 2014).

(4) Excludes construction costs related to the Company's Canadian Hills project in 2014.

(5) Distributions to noncontrolling interests primarily include distributions, if any, to the tax equity investors at Canadian Hills and to the other 50% owner of Rockland. These projects were sold in June 2015.

Note: This table presents Project Adjusted EBITDA, Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow, which are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies.

 

 

Atlantic Power Corporation



Table 12 – Project Adjusted EBITDA by Project (for Selected Projects)




(in millions of U.S. dollars)




Unaudited



















Three months ended

December 31,


Twelve months ended

December 31,




2015

2014


2015

2014

East U.S.

Accounting







Cadillac

Consolidated

$2.7

$2.3


$8.8

$7.7

Curtis Palmer

Consolidated

8.9

7.3


29.8

31.5

Morris

Consolidated

3.2

3.1


16.5

12.7

Piedmont

Consolidated

(0.1)

2.5


7.6

6.7

Other (1)

Consolidated

0.8

0.5


3.2

3.7

Chambers

Equity method

3.3

4.5


17.0

18.6

Orlando

Equity method

5.4

5.4


22.0

15.4

Other (2)

Equity method

(0.2)

(1.4)


0.1

10.3

Total



23.8

24.1


104.8

106.4

West U.S.








Manchief

Consolidated

3.4

4.0


5.8

15.0

Naval Station

Consolidated

1.3

1.2


10.2

10.3

North Island

Consolidated

1.4

1.1


8.4

5.4

Other (3)

Consolidated

0.2

(0.6)


9.2

9.1

Frederickson

Equity method

3.3

3.3


12.5

12.2

Other (4)

Equity method

0.2

0.4


0.8

2.2

Total



9.8

9.4


46.9

54.2

Canada








Calstock

Consolidated

2.5

2.9


9.5

6.8

Kapuskasing

Consolidated

3.7

3.1


7.8

9.2

Nipigon

Consolidated

5.2

5.2


18.3

15.3

North Bay

Consolidated

3.6

3.6


7.2

10.5

Williams Lake

Consolidated

1.5

3.2


14.0

15.8

Other (5)

Consolidated

0.2

6.7


2.9

18.7

Total



16.7

24.7


59.7

76.3

Totals








Consolidated projects



38.4

46.0


159.1

178.4

Equity method projects



11.9

12.1


52.3

58.6

Un-allocated corporate



0.1

(1.3)


(2.5)

(7.5)

Total Project Adjusted EBITDA



$50.4

$56.9


$208.9

$229.4









Reconciliation to project income (loss)








Depreciation and amortization



$31.2

$35.3


$130.1

$155.9

Interest expense, net



2.1

2.4


9.8

20.5

Change in the fair value of derivative instruments


(6.7)

16.8


(15.4)

(6.2)

Impairment and other expense



128.1

0.2


125.8

98.1

Project income (loss)



($104.3)

$2.1


($41.4)

($38.9)

(1) Kenilworth








(2) Selkirk








(3) Naval Training Station and Oxnard








(4) Q4 2014: Koma Kulshan; FY 2014:  Koma Kulshan and Delta-Person; Q4 and FY 2015: Koma Kulshan


(5) Tunis, Moresby Lake and Mamquam
















Notes: Table 12 presents Project Adjusted EBITDA, which is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP; therefore, this measure may not be comparable to a similar measure presented by other companies. The Company has not reconciled non-GAAP financial measures relating to individual projects to the directly comparable GAAP measures due to the difficulty in making the relevant adjustments on an individual project basis. 

 

SOURCE Atlantic Power Corporation


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