Atlantic Power Corporation Releases Fourth Quarter and Year End 2014 Results

BOSTON, Feb. 26, 2015 /CNW/ -- Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the "Company") today released its results for the three months and year ended December 31, 2014.

"Since our third quarter earnings call, Atlantic Power has made significant progress on its strategy by meaningfully reducing overhead costs, delivering attractive cash returns from discretionary investments in its fleet, and moving ahead on a potential asset divestiture process," said Mr. James J. Moore, Jr., President and Chief Executive Officer of Atlantic Power.  "Our plans for 2015 include further significant reductions in our overhead run rates from 2015 to 2016 and additional investments in our fleet at cash returns and risk levels that are much more favorable than those available in the external markets, both of which should result in improved internal cash flow.  In addition, we are evaluating potential asset divestitures as well as refinancing to achieve our goal of reshaping our debt.  We expect that our successful execution of this plan will provide a stable platform for Atlantic Power to begin growing its business again in 2016 on an absolute basis, in addition to the organic growth in cash flows provided by returns on discretionary investments in our fleet and cost reductions."

Mr. Moore continued, "Project Adjusted EBITDA for 2014 came in at the high end of our guidance range.  We also generated an increase in Adjusted Cash Flows from Operating Activities, which we used to reinvest in our projects, pay down debt and pay dividends to shareholders.  Our results benefited from strong wind generation, increased waste heat at our Ontario generation projects, and steps we took to reduce administrative expenses.  We also received a modest contribution from the $18 million of discretionary optimization investments made in our existing fleet in 2013 and 2014."

"We continue to make significant progress in rationalizing our corporate overhead, including development expense, reducing it from $54 million in 2013 to an expected level of $38 million or lower in 2015, with further significant improvement expected in 2016.  We also expect to make another $11 million of discretionary optimization investments in 2015, for a three-year total of approximately $29 million.  By 2016, we expect these investments to be producing a cash flow benefit of at least $10 million annually," said Mr. Moore.  "In addition, we remain focused on reducing our leverage through amortization, opportunistic repurchases of our debt and the use of proceeds from potential asset divestitures, if market valuations are compelling, or by reshaping our debt through refinancing and extended amortization.  We expect to be able to provide greater detail on these efforts by our next quarterly earnings report." 

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 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)


 Years ended December 31,

Unaudited

2014

2013

Excluding results from discontinued operations (1)



Project revenue

$569.2

$544.1

Project (loss) income

(50.5)

63.7

Project Adjusted EBITDA

299.3

268.9

Cash Distributions from Projects

248.9

223.0

Adjusted Cash Flows from Operating Activities

142.4

75.7

Adjusted Free Cash Flow

29.9

37.6

Aggregate power generation (thousands of Net MWh)

8,199.3

8,094.5

Weighted average availability

93%

95%

Including results from discontinued operations (1)



Cash flows from operating activities

$65.0

$152.4

Free Cash Flow

(55.6)

108.8

(1) The Path 15 transmission line ("Path 15"), Auburndale Power Partners, L.P. ("Auburndale"), Lake CoGen, Ltd. ("Lake") and Pasco Cogen, Ltd. ("Pasco") (collectively, the "Sold Projects") were sold in April 2013, the Company's interest in Rollcast Energy ("Rollcast") was sold in November 2013, and Thermo Power & Electric, LLC ("Greeley") was sold in March 2014.  Accordingly, the revenues, project income (loss), Project Adjusted EBITDA, Cash Distributions from Projects, and Adjusted Cash Flows from Operating Activities from these assets are included in discontinued operations for the years ended December 31, 2013 and 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 Sold Projects, Rollcast 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 Sold Projects, Rollcast, and Greeley.  The Gregory project ("Gregory"), which was sold in August 2013, and the Delta-Person generating station ("Delta-Person"), which was sold in July 2014, are both accounted for under the equity method of accounting and therefore are included in the Company's financial results from continuing operations.

Year End 2014 Financial Highlights

  • Project Adjusted EBITDA of $299.3 million increased $30.4 million from 2013 and came in at the high end of the Company's revised guidance range of $285 to $300 million
  • GAAP results included $106.6 million of non-cash impairments and an $8.7 million non-cash loss on changes in the fair value of derivatives, partially offset by an $8.6 million asset sale gain, for a project loss of $(50.5) million; excluding these items, project income was $56.2 million. For 2013, project income of $63.7 million included a $34.9 million non-cash impairment, which was more than offset by a $49.5 million non-cash gain on changes in the fair value of derivatives and a $30.4 million asset sale gain; project income excluding these items was $18.7 million. Thus, the year-over-year increase in project income excluding these items was $37.5 million
  • Cash flows from operating activities of $65.0 million decreased $87.4 million from 2013, primarily due to interest expense related to the debt repayment and repurchase transactions in the first quarter of 2014, changes in working capital and the loss of cash flows from businesses that were divested in 2013
  • Free Cash Flow of $(55.6) million decreased $164.4 million from 2013 due primarily to the decrease in cash flows from operating activities described above, increased debt repayment and higher capex
  • Adjusted Cash Flows from Operating Activities, which excludes the items affecting cash flows from operating activities described above, was approximately $142 million in 2014, and was primarily used to reduce debt, fund capital expenditures, and pay dividends to shareholders; the increase of $66.7 million from 2013 was attributable to increased Project Adjusted EBITDA, higher cash distributions from projects and modestly lower cash interest expense
  • Adjusted Free Cash Flow of $29.9 million decreased $7.7 million from 2013, as the increase in Adjusted Cash Flows from Operating Activities was more than offset by a higher level of debt amortization
  • Completed $18 million of major optimization projects in 2013-2014 and expect to realize cash flow benefit of $4 to $8 million in 2015

Progress on Debt Reduction Goals

  • Reduced outstanding amount of APLP term loan through mandatory amortization and cash sweep by $58 million, approximately $5 million more than expected
  • Repaid approximately $29 million of project-level debt, including at equity-owned projects
  • Repaid Cdn$44.8 million convertible debenture at maturity on October 31, 2014 using cash on hand; expect interest savings in 2015 of $2.7 million
  • Repurchased $3.1 million of convertible debentures in December under Normal Course Issuer Bid (NCIB) and another $6.1 million in 2015 to date
  • Repurchased $9 million of senior unsecured notes in January 2015; amount outstanding now $310.9 million

2015 Guidance and Capital Deployment Plans

  • Total Company Project Adjusted EBITDA of $265 to $285 million
  • APLP Project Adjusted EBITDA of $148 to $160 million
  • Adjusted Cash Flows from Operating Activities of $120 to $140 million
  • Adjusted Free Cash Flow of $10 to $30 million
  • Expect to achieve at least a $16 million reduction in general and administrative (G&A) and development expenses in 2015 relative to 2013
  • Planning $11 million of optimization investments in 2015
  • Expect major maintenance and capex of approximately $35 million in 2015
  • Expect to amortize approximately $48 to $54 million of APLP term loan and $24 million of project-level debt (total of approximately $75 million); will continue to evaluate opportunistic debt repurchases using cash on hand and proceeds from potential asset sales, if market valuations are compelling

Strategy

The Company continues to focus on executing its business plan, including the objectives of enhancing the value of its existing assets through discretionary capital investments and commercial activities, delevering its balance sheet to reduce its interest expense and improve its cost of capital to better compete for new investments, improving its cost structure and reducing overhead.  In addition, the Company continues to assess other potential options, including selected asset sales or the contribution of assets to a joint venture, if the valuation of a particular asset or assets is compelling, in order to raise additional capital for growth and/or debt reduction. Going forward, as the Company executes its business strategy, and consistent with its objectives, the Board of Directors, together with management will regularly evaluate the optimal dividend policy for the Company.

Operating Results

Project availability declined to 93.4% in 2014 from 94.8% in 2013.  The decrease was attributable to a combination of forced outages (some weather-related, particularly in the first quarter) and extensions of scheduled maintenance outages, particularly at Nipigon, Chambers, Orlando and Canadian Hills.  For the year, reduced availability resulted in capacity payments being $10.3 million lower than their expected level.  The majority of this impact was at the Ontario projects, which had unplanned outages due to weather and other factors in the first quarter of 2014, and Piedmont, which had several forced outages during the year.    

Generation increased 1.3% year over year due primarily to the addition of Piedmont in April 2013 (additional quarter in 2014), increased generation at Orlando due to the expiration of an unfavorable natural gas contract in the comparable 2013 period, higher dispatch at Frederickson and favorable wind conditions for Meadow Creek.  These positive comparisons were partially offset by reduced dispatch at Manchief and Williams Lake, reduced generation at Selkirk due to mild summer weather, and reduced generation at Canadian Hills due to weather-related outages.  

Financial Results

Table 2 provides a breakdown of project income and Project Adjusted EBITDA by segment for the year ended December 31, 2014 as compared to the same period in 2013.  

Atlantic Power Corporation

Table 2 – Segment Results

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

Unaudited


Years ended December 31,


2014

2013

Project income (loss)



East

$21.8

$25.8

West

(51.3)

35.8

Wind

(11.5)

18.6

Un-allocated Corporate

(9.5)

(16.5)

Total

(50.5)

63.7

Project Adjusted EBITDA



East

$158.5

$150.7

West

78.5

77.2

Wind

69.8

59.6

Un-allocated Corporate

(7.5)

(18.6)

Total

299.3

268.9

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 11 for a reconciliation of this non-GAAP measure to a GAAP measure. 

Project Income

Reported 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 decreased by $114.2 million to a loss of $(50.5) million for the year ended December 31, 2014 compared to project income of $63.7 million for the same period in 2013.  The reduction in project income was primarily due to non-cash impairment charges in 2014 of $106.6 million, an increase of $71.7 million from the 2013 period; decreased asset sale gains of $21.8 million; net year-over-year non-cash changes in the fair value of gas purchase agreements and interest rate swap agreements accounted for as derivatives totaling $(58.2) million; and decreased project income of $11.9 million at Selkirk, due to lower energy revenues and accelerated depreciation.  These negative factors were partially offset by improvements at several projects in the East and West segments due to favorable outage comparisons; increased margins at Morris and Orlando; lower interest expense at Curtis Palmer; improved generation at Meadow Creek; an additional quarter of Piedmont operation; and a $7.1 million reduction in loss in the Un-allocated Corporate segment, primarily attributable to $3.5 million in development and administrative expense reductions at Ridgeline as well as administrative reduction initiatives undertaken during the year. 

Excluding the non-cash impairment charges, asset sale gains or losses and non-cash changes in the fair value of derivatives described above, the comparisons would be as follows:

  • 2014:  Reported project loss of $(50.5) million included $106.6 million of non-cash impairments, an $8.7 million non-cash loss on changes in the fair value of derivatives, and an $8.6 million asset sale gain.  Excluding these items, results were project income of $56.2 million
  • 2013:  Reported project income of $63.7 million included a $34.9 million non-cash impairment, which was more than offset by a $49.5 million non-cash gain on changes in the fair value of derivatives and a $30.4 million asset sale gain.  Excluding these items, project income was $18.7 million
  • Thus, the year-over-year increase in project income excluding these items was $37.5 million.  The increase was attributable to the factors described previously (improved results at several projects, lower interest expense at Curtis Palmer and a reduction in loss in the Un-allocated Corporate segment). 

Project Adjusted EBITDA

Project Adjusted EBITDA includes proportional EBITDA from the Company's equity method projects and 100% of EBITDA from Rockland, which is 50% owned by the Company, but is consolidated.  Projects classified as discontinued operations are excluded from Project Adjusted EBITDA. 

Project Adjusted EBITDA increased by $30.4 million to $299.3 million for the year ended December 31, 2014 from $268.9 million for the same period in 2013, at the high end of the Company's guidance range of $285 to $300 million.  For the year, the most significant contributors to the improvement in Project Adjusted EBITDA were the wind projects, primarily Meadow Creek, due to increased generation; the Ontario projects other than Calstock, due to the timing of maintenance expense and increased waste heat generation; Morris, due primarily to an increase in energy revenues, partially offset by higher fuel expenses; Orlando, due to higher gross margins under an amended PPA and following the expiration of above-market gas swaps; Piedmont, due to a full year of operation and lower maintenance expense; Naval Training Center, due primarily to favorable maintenance comparisons; Mamquam, due to favorable maintenance comparisons and improved water flows; and an $11.1 million reduction in loss from the Un-allocated Corporate segment, primarily due to a reduction in development costs at Ridgeline and a reduction in administrative costs.  These positive factors were partially offset by decreases at Selkirk, due to the expiration of the project's PPA in August 2014 and lower dispatch due to mild summer weather; Manchief, due to higher than normal dispatch in 2013; Chambers, due to higher major maintenance costs in 2014; the sales of Gregory in August 2013 and Delta-Person in July 2014; and smaller decreases at several other projects in the East and West segments.   

Corporate G&A Expense

Administrative expenses, which include corporate-level G&A expense, interest expense, foreign exchange gains and losses and other income, are not included in Project Adjusted EBITDA.

For the year, administration expense increased $2.7 million from the comparable year-ago period.  In the second half of the year, the Company incurred $6.0 million of severance charges associated with management changes and personnel reductions, which are expected to result in lower administrative costs going forward.  These charges were partially offset by lower transaction costs related to the asset divestitures in 2013 and a reduction in legal expenses, as in the third quarter of 2014 the Company exceeded its deductible under its directors and officers insurance policy with regard to legal costs incurred for the purported class action shareholder litigation, and expects additional incurred costs to be paid by its insurance carrier to the extent set forth under its terms of coverage. 

Cash Flow Metrics

Cash Distributions from Projects

Cash Distributions from Projects, which excludes projects classified as discontinued operations, increased by $25.9 million to $248.9 million for the year ended December 31, 2014, compared to $223.0 million for the same period in 2013.  This result includes an increase of $8.5 million in the fourth quarter of 2014 from the year-ago period. 

Significant increases for 2014 occurred at: (i) Meadow Creek, Canadian Hills, Rockland and Idaho Wind, due to the release of construction-related blade and credit reserves and increased wind generation; (ii) Orlando, due to lower gas costs following the termination of swaps that were above market as well as favorable changes to the project's PPA; (iii) the Navy projects in California,  attributable to lower operation and maintenance expenses than in 2013, during which the projects experienced planned outages, and to lower working capital requirements associated with a new gas supply agreement in 2014; (iv) the Ontario projects, due to higher waste heat availability; and (v) Mamquam, due to lower maintenance expense.

These increases were partially offset by decreases at (i) Selkirk, due to the expiration of the PPA at the end of August; (ii) Morris, due to gas storage purchases; and (iii) Chambers, which benefited from the release of the DuPont settlement in the 2013 period and for which there was a change in the distribution date under the project's new debt agreement in 2014.  The project made a distribution in December, which was released to the Company in January 2015. 

Cash Flows from Operating Activities

Cash flows from operating activities decreased by $87.4 million to $65.0 million for the year ended December 31, 2014 compared to $152.4 million for the same period in 2013.  The decrease is primarily due to $46.8 million of interest expense related to the debt repayment and repurchase transactions in the first quarter (as described in more detail in the first quarter 2014 press release dated May 12, 2014), a $65.7 million increase in cash outflows for working capital due to a $39.4 million decrease in prepaid and other assets due to the collection of security deposits related to completed construction projects in the first quarter of 2013, and a decrease in cash flows from discontinued operations (projects sold in 2013).

Free Cash Flow

Free Cash Flow decreased by $164.4 million to $(55.6) million for the year ended December 31, 2014 compared to $108.8 million for the same period in 2013.  The decrease is primarily due to an $87.4 million decrease in operating cash flows as described previously, $58.4 million of term loan facility repayments by APLP and a $10.6 million increase in project-level debt repayment. 

The Company's full year 2014 Free Cash Flow guidance of $0 to $10 million excluded (i) $49.4 million of interest expense related to the refinancing and debt repurchase transactions and (ii) the $8.1 million Piedmont construction debt repayment.  On that basis, Free Cash Flow for the full year 2014 was approximately $2 million compared to $109 million for the same period in 2013.  Relative to the Company's guidance, Free Cash Flow was reduced by approximately $5 million due to a higher level of term loan repayments than previously expected.

Adjusted Cash Flows from Operating Activities

Adjusted Cash Flows from Operating Activities increased by $66.7 million to $142.4 million for the year ended December 31, 2014 compared to $75.7 million for the same period in 2013.  Unlike cash flows from operating activities, which decreased on a year-over-year basis, Adjusted Cash Flows from Operating Activities excludes the impact of certain non-recurring items, such as the refinancing and repurchase transactions in the first quarter of 2014, as well as changes in working capital (both of which reduced operating cash flow in 2014 relative to 2013).  The increase in Adjusted Cash Flows from Operating Activities for the year was primarily attributable to higher levels of Project Adjusted EBITDA, higher cash distributions from projects and modestly lower cash interest expense.  

Adjusted Free Cash Flow

Adjusted Free Cash Flow decreased by $7.7 million to $29.9 million for the year ended December 31, 2014 compared to $37.6 million for the same period in 2013, as the increase in Adjusted Cash Flows from Operating Activities was more than offset by higher levels of debt repayment, particularly amortization of the APLP term loan.  Unlike Free Cash Flow, Adjusted Free Cash Flow does not include changes in working capital or cash outlays for transaction expenses (such as the refinancing transaction expenses incurred in the first quarter of 2014) or the repayment of Piedmont debt at term loan conversion, both of which reduced Free Cash Flow.

Tables 11 and 12 of this press release provide a reconciliation of the Company's non-GAAP cash flow metrics to cash flows from operating activities. 

Financial Results for the Three Months Ended December 31, 2014

Project income decreased by $4.5 million to $2.8 million for the three months ended December 31, 2014 from $7.3 million for the year-ago period.  The decrease in project income relates primarily to a $37.5 million mark-to-market decrease in the fair value of derivatives, partially offset by higher levels of Project Adjusted EBITDA and a reduction in project expenses including depreciation and interest expense.  

Project Adjusted EBITDA increased by $19.8 million to $77.9 million for the three months ended December 31, 2014 from $58.1 million for the year-ago period.  Significant increases occurred at Piedmont (lower maintenance expense due to a maintenance outage in the fourth quarter of 2013 and a partial reversal of a 2013 accrual), Orlando (more favorable PPA and gas supply costs), North Island (major gas turbine overhaul in 2013 period),  Williams Lake (higher availability and other factors), and the wind projects in Idaho (favorable winds).  In addition, the Company benefited from a reduction in Un-allocated Corporate expenses of $4.8 million due to steps taken earlier in the year to reduce administrative and development expense.  These positive factors were partially offset by a reduction at Selkirk, for which the PPA expired on August 31, and which was also affected by mild weather and reduced dispatch in the fourth quarter.   

Liquidity

As can be seen from Table 3, the Company's liquidity decreased from approximately $272 million as of September 30, 2014, to $214 million at December 31, 2014, including $110 million of unrestricted cash.  During the fourth quarter, the Company used approximately $43 million of cash on hand to repay Cdn$44.8 million of convertible debentures (ATP.DB) at their October 31st maturity date.  It also repurchased $3.1 million of convertible debentures under the NCIB and paid $3.1 million of dividends on its common shares.   

Atlantic Power Corporation

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

Unaudited

 September 30, 2014

December 31, 2014

Revolver capacity

$210.0

$210.0

Letters of credit outstanding

(106.0)

(105.7)

Unused borrowing capacity

104.0

104.3

Unrestricted cash (1)

167.6

109.9

Total Liquidity

$271.6

$214.2

(1) Includes project-level cash for working capital needs of $16.3 million at September 30, 2014 and $18.2 million at December 31, 2014. 

Other Financial Updates

Goodwill Impairment Assessment

At December 31, 2014, the Company had $197.2 million of goodwill.  As previously reported, the Company performed an event-driven test of its goodwill and long-lived assets at all of its projects as of August 31, 2014 and during the third quarter of 2014 recorded goodwill impairments at its Kenilworth, Manchief and Williams Lake projects.  During the fourth quarter, the Company performed its annual goodwill impairment test as of November 30, 2014 and determined that no further impairments were required at that time.  The Company also updated its asset impairment analysis for Tunis and determined that no further impairment of long-lived assets was required (the Company had previously written off all of the goodwill at Tunis). 

Senior Unsecured Notes – Fixed Charge Coverage Ratio

As previously reported, the Company can no longer satisfy the Fixed Charge Coverage Ratio test under the restricted payments covenant of its senior unsecured note indenture.  The test is based on rolling four quarter results.  In the second quarter of 2015, the charges recorded in the first quarter of 2014 for the refinancing and repurchase transaction costs will no longer be included in the calculation and the Company expects to be back in compliance at that time.  Until then, the Company is limited to the payment of common dividends not exceeding the Restricted Payments basket, which is the greater of $50 million or 2% of consolidated net assets ($55.8 million as of December 31, 2014).  Through year-end 2014, the Company had paid dividends totaling $32.5 million that count against the basket provision; another $3 million of dividends declared in February 2015 to be paid in March 2015 are also subject to the basket provision.  In addition, any similar debt prepayment charges incurred in connection with further debt reduction would also be reflected in the calculation of the fixed charge coverage ratio on a rolling four quarter basis, beginning with the quarter in which such charges are incurred, as would any associated reduction in interest expense.  

2015 Guidance and Outlook

G&A Expense Targets

Project-level G&A expense and Ridgeline expenses, including development expense, are included in the Un-allocated Corporate segment and therefore included in Project Adjusted EBITDA.  Corporate-level G&A expense is included in Administration expense, which is not included in Project Adjusted EBITDA.  Together these comprise total G&A expense.

As previously disclosed, during 2013 and 2014 the Company undertook a number of steps to reduce its G&A and development costs, including recent management changes and personnel reductions.  These actions are expected to result in cost savings going forward, including in 2015.  In addition to personnel cost savings, the Company expects to have lower project and business development expense, including a $3 million annual benefit from the scheduled expiration of a contractual obligation related to the Ridgeline acquisition in the first quarter of 2015.  In addition, as discussed above, the Company expects to have lower legal expenses going forward. 

Total G&A expense in 2014 was $45 million, including $6 million of severance expense.  The Company expects G&A expense in 2015 of no more than $38 million, including approximately $3 million of severance expense.  The Company is targeting further significant improvement in G&A expense in 2016.

Optimization Investments

In 2013 and 2014, the Company made approximately $18 million of discretionary investments in its existing projects designed to increase the output, improve the efficiency or improve the margins of these facilities.  In 2015, the Company expects to realize a cash flow benefit of $4 to $8 million from these investments.  The most significant of these projects were the repowering of two turbines at Curtis Palmer, the steam generator replacement and upgrade at Nipigon, an investment designed to boost output at Morris during peak periods and an interconnection upgrade at North Island.  The Company expects to revisit this expectation as it gains operating experience with these upgrades over the course of this year. 

The Company expects to invest another $11 million in 2015 across a number of projects, with the most significant at Curtis Palmer, Mamquam, Nipigon, and several at Morris.  Together with optimization investments completed in 2013 and 2014, the Company expects a cash flow benefit from these investments of at least $10 million in 2016. 

In addition to these production-based investments, the Company continues to pursue commercial and asset management opportunities around its existing projects, some of which require only a modest level of capital expenditures or expense.  Examples of these include bringing outsourced project management contracts in-house; improving commercial terms around fuel supply or other consumables; reducing letter of credit requirements; identifying ways to improve the terms of existing PPAs for both the Company and its customers; and positioning the projects to be able to take advantage of opportunities in the power markets.  Any cash contribution from these efforts is incremental to those realized from production-based optimization projects.

The Company views both the optimization projects as well as its commercial and asset management activities to be an attractive use of its cash considering the relatively modest capital requirements and potential for strong risk-adjusted returns. 

Major Maintenance and Capex

In 2014, the Company had capex of $13 million and major maintenance expense of $20 million, for a total of $33 million, in line with the Company's expectation of $35 million.  The capex figure is net of approximately $2.4 million of insurance proceeds and other recoveries for Piedmont.  Most of the capex (approximately $12 million) were for the discretionary optimization investments discussed above at Curtis Palmer, Nipigon, Morris and North Island.

For 2015, the Company expects capex of approximately $12 million, of which approximately $10 million relates to discretionary optimization investments at Morris, Nipigon and Curtis Palmer.  (Approximately $11 million of the $12 million total capex budget is for projects at APLP.)  Major maintenance expense is expected to be approximately $23 million, with the increase from 2014 primarily attributable to the scheduled gas turbine outage at Manchief. 

Debt Reduction

The Company expects to amortize approximately $24 million of project-level debt in 2015, including its share of debt at equity method projects.  It also expects to repay $48 to $54 million of APLP term loan through the 50% cash sweep and 1% mandatory amortization, for a total debt reduction through amortization of approximately $75 million.  Amortization of project-level debt and the APLP term loan is expected to average approximately $75 million annually over the next five years ($80 million on a three-year average basis).  In addition, the Company will continue to evaluate discretionary repurchases of debt using cash on hand or the proceeds from potential asset sales, if the valuation of a particular asset or assets is compelling.  In January 2015, the Company repurchased $9 million of senior unsecured notes.  Year to date through February 21, 2015, it had repurchased $6.1 million of convertible debentures under the NCIB.  

Guidance

The Company is initiating 2015 guidance as follows:

  • Project Adjusted EBITDA of $265 to $285 million. The decline from 2014 ($299.3 million) is primarily attributable to the expiration of PPAs for Selkirk and Tunis in 2014 and a gas turbine overhaul at Manchief, partially offset by higher results from Orlando, Nipigon and several other projects.
  • Project Adjusted EBITDA for APLP of $148 to $160 million
  • Adjusted Cash Flows from Operating Activities of $120 to $140 million. The decline from 2014 ($142 million) is primarily attributable to lower Project Adjusted EBITDA, partially offset by lower G&A expense and lower interest expense.
  • Adjusted Free Cash Flow of $10 to $30 million. This is net of planned capital expenditures totaling $12 million and consolidated project-level debt and term loan amortization totaling approximately $72 million. The decrease in Adjusted Free Cash Flow from the 2014 level of $30 million is primarily attributable to lower levels of G&A expense, interest expense, and debt amortization, which are expected to be more than offset by lower Project Adjusted EBITDA.

See Table 4 for full-year 2015 guidance and 2014 actual results.

Atlantic Power Corporation

Table 4 – 2015 Annual Guidance vs. 2014 Actual Results

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

 

Unaudited

2015 Annual Guidance

2014 Actual

Project Adjusted EBITDA

$265 - $285

$299.3

Adjusted Cash Flows from Operating Activities (1)

$120 - $140

$142.4

Adjusted Free Cash Flow (2)

$10 - $30

$29.9

APLP Project Adjusted EBITDA (3)

$148 - $160

$176.1

(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 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.

(2) Adjusted Free Cash Flow is defined as Free Cash Flow excluding changes in working capital balances, acquisition expenses, litigation expense, severance and restructuring charges, 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 new 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. 

Business Update

Piedmont

Currently the Company does not expect its Piedmont project to meet its debt service coverage ratio covenants, restricting its ability to make distributions before 2017 at the earliest, due to continued operational issues that have resulted in higher forecasted maintenance and fuel expenses than initially expected.

Tunis

The PPA with the Ontario Power Authority (OPA) for the Company's Tunis project expired on December 31, 2014; however, the Company has entered into an agreement with the OPA and its successor, the Independent Electricity System Operator (IESO), for the future operations of the Tunis facility.  Subject to meeting certain technical modifications to the plant, gas delivery and other requirements, Tunis will operate under a 15-year agreement with the IESO commencing between November 2017 and June 2019.

The new contract will require the plant to become fully dispatchable as opposed to its current baseload configuration.  As such, Tunis will provide electricity to the Ontario grid only when required, thereby assisting to reduce the incidents of surplus baseload generation in the market.  The new agreement provides Tunis with a fixed monthly payment which escalates annually according to a pre-defined formula while allowing Tunis to earn additional energy revenues for those periods during which it is called upon to operate.

Supplementary Financial Information

For further information, attached to this news release is a summary of Project Adjusted EBITDA by segment for the three months and years ended December 31, 2014 and 2013 (Table 9) 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, 2014 (Table 10A) and the year ended December 31, 2013 (Table 10B); 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 years ended December 31, 2014 and 2013 (Table 11); a reconciliation of Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow to cash flows from operating activities (Table 12); and a summary of Project Adjusted EBITDA for selected projects (top contributors based on the Company's 2014 budget, representing approximately 80% of total Project Adjusted EBITDA) for the years ended December 31, 2014 and 2013 (Table 13). 

Investor Conference Call and Webcast

A telephone conference call hosted by Atlantic Power's management team will be held on Friday, February 27, 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 4977312 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 10058795.  The replay will be available 1 hour after the end of the conference call through May 28, 2015 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.  Atlantic Power'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.  Its power generation projects in operation have an aggregate gross electric generation capacity of approximately 2,945 MW in which its aggregate ownership interest is approximately 2,024 MW. Its current portfolio consists of interests in twenty-eight operational power generation projects across eleven 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:

  • the Company's plans for 2015, including further significant reductions in overhead run rates from 2015 to 2016 and additional investments in its fleet at cash returns that the company believes are more favorable than those available in external markets, both of which the company expects to result in improved cash flow;
  • the Company's expectation that successful execution of its business plan will provide a stable platform for it to begin growing its business again in 2016 on an absolute basis, in addition to the organic growth in cash flows provided by returns on discretionary investments in its fleet and cost reductions;
  • the outcome or impact of the Company's business plan, including the objective of enhancing the value of its existing assets through optimization investment and commercial activities, delevering its balance sheet to improve its cost of capital and ability to compete for new investments, utilizing its core competencies to create proprietary investment opportunities, improving its cost structure and reducing overhead;
  • the Company's ability to evaluate and/or implement potential options, including asset sales or the contribution of assets to a joint venture, if the valuation of a particular asset or assets is compelling, in order to raise additional capital for growth and/or debt reduction, and the outcome or impact on the Company's business plan of any such potential options;
  • the Company's expectations regarding the pursuit of commercial and asset management opportunities around its existing projects and any cash contributions from such opportunities;
  • the Company will achieve expected annual interest rate savings of $2.7 million in 2015 in connection with the repayment at maturity of the Company's Cdn$44.8 million convertible debenture on October 31, 2014;
  • 2015 Project Adjusted EBITDA will be in the range of $265 to $285 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 $120 to $140 million;
  • 2015 Adjusted Free Cash Flow will be in the range of $10 to $30 million;
  • the Company expects to amortize $48 to $54 million of the APLP term loan and $24 million of project-level debt in 2015, for a total debt reduction through amortization of approximately $75 million; and the expectation that amortization of project-level debt and the APLP term loan will average approximately $75 million annual over the next five years ($80 million on a three-year average basis);
  • the Company's expectations regarding compliance with the fixed charge coverage ratio test included in the restricted payments covenant in its senior unsecured note indenture;
  • the expectation that recent management changes and personnel reduction will result in cost savings going forward;
  • the Company expects to have G&A costs of no more than $38 million in 2015, for a total reduction of at least $16 million relative to 2013, with further significant improvement expected in 2016;
  • the Company expects to incur approximately $3 million of severance expense in 2015;
  • the Company expects to have lower project and business development expenses, including a $3 million annual benefit from the scheduled expiration of a contractual obligation related to the Ridgeline acquisition beginning in the first quarter of 2015;
  • the Company expects to have lower legal expenses associated with the purported class action shareholder litigation, and expects that additional costs incurred in connection with such purported class action shareholder litigation will be paid by the Company's directors and officers insurance carrier to the extent set forth under the terms of its coverage;
  • the optimization investments in 2013 and 2014 of approximately $18 million will produce approximately $4 to $8 million of annual cash flow benefit;
  • the level of optimization investments will be approximately $11 million in 2015, and cumulative investments for 2013 through 2015 will produce a cash flow contribution of at least $10 million annually in 2016;
  • the Company will have project capital expenditures and major maintenance expenses of approximately $35 million in 2015, including optimization initiatives of approximately $11 million;
  • Piedmont will be unable to pass its debt service coverage ratio covenant or make distributions before 2017; 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 Company's ability to evaluate and/or implement potential options, including asset sales or joint ventures, if the valuation of a particular asset or assets is compelling, to raise additional capital for growth and/or potential debt reduction.  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 financial outlook information contained in this news release is presented to provide readers with guidance on the cash distributions expected to be received by the Company and to give readers a better understanding of the Company's ability to pay its current level of distributions into the future.  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. Readers are cautioned that such information may not be appropriate for other purposes.

 

Atlantic Power Corporation

Table 6 – Consolidated Balance Sheet (in millions of U.S. dollars)

 


December 31,

December 31,


2014

2013

Assets

 (Unaudited)


Current assets:                         

Cash and cash equivalents

$109.9

$158.6

Restricted cash

22.5

96.2

Accounts receivable

57.4

64.3

Current portion of derivative instruments asset

-

0.2

Inventory

19.3

16.0

Prepayments and other current assets

16.3

16.1

Refundable income taxes

0.2

4.0

Total current assets

225.6

355.4


Property, plant and equipment, net

1,673.4

1,813.4

Equity investments in unconsolidated affiliates

343.9

394.3

Power purchase agreements and intangible assets, net

381.4

451.5

Goodwill

197.2

296.3

Derivative instruments asset

1.1

13.0

Restricted cash

19.1

18.0

Deferred financing costs

64.2

41.7

Other assets

10.7

11.4

Total assets

$2,916.6

$3,395.0


Liabilities

Current liabilities:

Accounts payable

$11.0

$14.0

Accrued interest

5.4

17.7

Other accrued liabilities

34.9

58.8

Current portion of long-term debt

26.4

216.2

Current portion of convertible debentures

-

42.1

Current portion of derivative instruments liability

39.2

28.5

Dividends payable

-

6.8

Other current liabilities

6.8

5.3

Total current liabilities

123.7

389.4


Long-term debt

1,388.3

1,254.8

Convertible debentures

340.6

363.1

Derivative instruments liability

57.5

76.1

Deferred income taxes

92.3

111.5

Power purchase and fuel supply agreement liabilities, net

33.4

38.7

Other long-term liabilities

64.2

65.4

Commitments and contingencies

-

-

Total liabilities

2,100.1

2,299.0


Equity

Common shares, no par value, unlimited authorized shares; 121,323,614 and 120,205,813 issued and outstanding at December 31, 2014 and December 31, 2013, respectively

1,288.4

1,286.1

Preferred shares issued by a subsidiary company

221.3

221.3

Accumulated other comprehensive income (loss)

(68.3)

(22.4)

Retained deficit

(863.9)

(655.4)

Total Atlantic Power Corporation shareholders' equity

577.5

829.6

Noncontrolling interest

239.0

266.4

Total equity

816.6

1,096.0

Total liabilities and equity

$2,916.6

$3,395.0

 

 


Atlantic Power Corporation

Table 7 – Consolidated Statements of Operations

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

Unaudited


Years Ended
December 31,

Three months ended
 December 31,


2014

2013

2012

2014

2013

Project revenue

Energy sales

$315.9

$302.2

$214.5

$81.7

$75.6

Energy capacity revenue

161.3

163.7

147.2

37.3

36.6

Other

92.0

78.2

68.1

23.4

18.5


569.2

544.1

429.8

142.4

130.7







Project expenses:






Fuel

210.4

194.3

164.9

50.9

48.5

Operations and maintenance

130.2

150.8

119.6

29.4

41.2

Development

3.7

7.2

-

1.0

2.3

Depreciation and amortization

162.6

166.1

116.6

40.3

41.4


506.9

518.4

401.1

121.6

133.4

Project other income (expense):






Change in fair value of derivative instruments

(8.7)

49.5

(59.3)

(21.0)

16.1

Equity in earnings of unconsolidated affiliates

25.8

26.9

15.2

7.1

2.3

Gain on sale of equity investments

8.6

30.4

0.6

-

-

Interest expense, net

(31.9)

(34.4)

(16.4)

(5.6)

(8.7)

Impairment of goodwill

(106.6)

(34.9)

-

-

-

Other income, net

-

0.5

-

1.5

0.3


(112.8)

38.0

(59.9)

(18.0)

10.0

Project (loss) income

(50.5)

63.7

(31.2)

2.8

7.3







Administrative and other expenses (income):






Administration

37.9

35.2

28.3

12.0

6.7

Interest, net

146.7

104.1

89.8

25.9

25.4

Foreign exchange (gain) loss

(38.3)

(27.4)

0.5

(17.9)

(14.5)

Other income, net

(2.8)

(10.5)

(5.7)

(0.7)

(1.0)


143.5

101.4

112.9

19.3

16.6

Loss from continuing operations before income taxes

(194.0)

(37.7)

(144.1)

(16.5)

(9.3)

Income tax benefit

(11.9)

(19.5)

(28.1)

(4.5)

(17.6)

(Loss) income from continuing operations

(182.1)

(18.2)

(116.0)

(12.0)

8.3

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

(0.1)

(5.6)

15.7

-

(0.4)

Net (loss) income

(182.2)

(23.8)

(100.3)

(12.0)

7.9

Net loss attributable to noncontrolling interest

(16.4)

(3.4)

(0.6)

(4.6)

(0.1)

Net income attributable to preferred share dividends of a subsidiary company

11.6

12.6

13.1

2.8

3.0

Net (loss) income attributable to Atlantic Power Corporation

$(177.4)

$(33.0)

$(112.8)

$(10.2)

$4.9







Basic and diluted earnings (loss) earnings per share:






(Loss) income from continuing operations attributable to Atlantic Power Corporation

$(1.47)

$(0.23)

$(1.10)

$(0.09)

$0.04

(Loss) income from discontinued operations, net of tax

-

(0.05)

0.13

-

-

Net (loss) income attributable to Atlantic Power Corporation

$(1.47)

$(0.28)

(0.97)

$(0.09)

$0.04

(1) Includes contributions from the Sold Projects and Rollcast which are a component of discontinued operations.

 

 


Atlantic Power Corporation

Table 8 – Consolidated Statements of Cash Flows (in millions of U.S. dollars)


Years ended December 31,

Unaudited

2014

2013

2012

Cash flows from operating activities:




Net loss

$(182.2)

$(23.8)

$(100.3)

Adjustments to reconcile to net cash provided by operating activities




Depreciation and amortization

162.6

176.4

157.2

Loss from discontinued operations

-

32.8

-

(Gain) loss on sale of assets & other charges

(2.9)

(5.1)

0.8

Long-term incentive plan expense

3.5

2.2

2.5

Long-lived asset and goodwill impairment charges

106.6

39.7

60.5

Gain on sale of equity investments

(8.6)

(30.4)

(0.6)

Equity in earnings from unconsolidated affiliates

(25.8)

(26.9)

(25.7)

Distributions from unconsolidated affiliates

76.2

40.9

38.4

Unrealized foreign exchange (gain) loss

(38.8)

(13.0)

19.0

Change in fair value of derivative instruments

8.7

(60.2)

46.7

Change in deferred income taxes

(15.7)

(27.3)

(34.1)

Change in other operating balances




Accounts receivable

6.9

3.4

2.3

Inventory

(3.3)

0.8

(6.2)

Prepayments, refundable income taxes and other assets

21.1

51.5

(13.3)

Accounts payable

(4.1)

(8.4)

21.1

Accruals and other liabilities

(39.2)

(0.2)

(1.2)

Cash provided by operating activities

65.0

152.4

167.1



Cash flows provided by (used in) investing activities




Change in restricted cash

72.6

(93.7)

(11.6)

Proceeds from sale of assets and equity investments, net

9.5

182.6

27.9

Cash paid for acquisitions and investments, net of cash acquired

-

-

(80.5)

Proceeds from treasury grant

-

103.2

-

Biomass development costs

-

(0.2)

(0.5)

Construction in progress

-

(39.3)

(456.2)

Purchase of property, plant and equipment

(13.4)

(5.5)

(2.9)

Cash provided by (used in) investing activities

68.7

147.1

(523.8)



Cash flows (used in) provided by financing activities




Proceeds from senior secured term loan facility

600.0

-

-

Proceeds from issuance of convertible debentures

-

-

230.6

Proceeds from issuance of equity, net of offering costs

-

(1.0)

66.3

Proceeds from project-level debt

-

20.8

291.9

Repayment of corporate and project-level debt

(639.8)

(118.8)

(284.8)

Repayment of convertible debentures

(43.0)

-

-

Payments for revolving credit facility borrowings

-

(67.0)

(60.8)

Proceeds from revolving credit facility borrowings

-

-

69.8

Deferred financing costs

(39.0)

(2.8)

(31.2)

Equity contribution from noncontrolling interest

-

44.6

225.0

Dividends paid to common shareholders

(34.9)

(65.1)

(131.0)

Dividends paid to noncontrolling interests

(25.7)

(18.3)

(13.1)

Cash (used in) provided by financing activities

(182.4)

(207.6)

362.7



Net (decrease) increase in cash and cash equivalents

(48.7)

91.9

6.0

Less cash at discontinued operations

-

-

(6.5)

Cash and cash equivalents at beginning of period at discontinued operations

-

6.5

-

Cash and cash equivalents at beginning of period

158.6

60.2

60.7

Cash and cash equivalents at end of period

$109.9

$158.6

$60.2

Supplemental cash flow information




Interest paid

$168.8

$130.4

$40.2

Income taxes paid, net

$3.8

$5.9

$1.1

Accruals for construction in progress

$-

$8.9

$4.1





 

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 9 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 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 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 10A and 10B on page 17.  A reconciliation of Free Cash Flow to cash flows from operating activities is provided in Table 11 on page 18 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 Table 12 on page 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 9 – Project Adjusted EBITDA by segment

Unaudited


Years ended
December 31,

Three months ended
December 31,


2014

2013

2012

2014

2013

Project Adjusted EBITDA by segment






East (1)

$158.5

$150.7

$145.7

$42.2

$38.2

West (2)

78.5

77.2

78.9

16.0

9.5

Wind

69.8

59.6

10.9

20.8

16.3

Un-allocated corporate (3)

(7.5)

(18.6)

(11.1)

(1.1)

(5.9)

Total

299.3

268.9

224.4

77.9

58.1







Reconciliation to project income






Depreciation and amortization

201.7

208.8

163.5

46.8

55.2

Interest expense, net

39.5

38.5

24.0

7.4

10.7

Change in the fair value of derivative instruments

10.4

(50.3)

56.6

22.0

(15.4)

Other expense

98.2

8.2

11.5

-

0.4

Project (loss) income

$(50.5)

$63.7

$(31.2)

$1.7

$7.2

(1) Excludes Auburndale, Lake and Pasco, which are components of discontinued operations.

(2) Excludes Path 15, which is a component of discontinued operations.

(3) Excludes Rollcast, which is a component of discontinued operations.

 

Notes: Table 9 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 10A – Cash Distributions from Projects (by Segment, in millions of U.S. dollars)

Year 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







 Consolidated

$114.2

$(14.6)

$(7.6)

$(10.1)

$10.7

$92.6

  Equity method

44.3

(5.0)

(6.8)

(0.6)

1.0

32.9

  Total

158.5

(19.6)

(14.4)

(10.7)

11.7

125.5

West







  Consolidated

64.1

-

-

(0.8)

6.4

69.7

  Equity method

14.4

(1.0)

(0.1)

-

1.0

14.3

  Total

78.5

(1.0)

(0.1)

(0.8)

7.4

84.0

Wind







  Consolidated

58.2

(6.4)

(14.2)

(1.4)

(2.2)

34.0

  Equity method

11.6

(2.8)

(4.8)

0.1

1.3

5.4

  Total

69.8

(9.2)

(19.0)

(1.3)

(0.9)

39.4

  Total consolidated

236.5

(21.0)

(21.8)

(12.3)

14.9

196.3

  Total equity method

70.3

(8.8)

(11.7)

(0.5)

3.3

52.6

Un-allocated corporate

(7.5)

-

-

(1.2)

8.7

-

Total

$299.3

$(29.8)

$(33.5)

$(14.0)

$26.9

$248.9

Notes: Table 10A 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 10B – Cash Distributions from Projects (by Segment, in millions of U.S. dollars)

Year ended December 31, 2013 

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






 Consolidated

$100.3

$(3.9)

$(17.3)

$(6.7)

$18.8

$91.2

  Equity method

50.4

(14.0)

(3.6)

(0.9)

4.3

36.2

  Total

150.7

(17.9)

(20.9)

(7.6)

23.1

127.4

West







  Consolidated

60.0

-

-

(1.1)

(3.3)

55.6

  Equity method

17.2

1.2

(0.3)

(1.1)

(2.9)

14.1

  Total

77.2

1.2

(0.3)

(2.2)

(6.2)

69.7

Wind







  Consolidated

50.0

(7.0)

(14.6)

(5.5)

0.5

23.4

  Equity method

9.6

(2.6)

(4.9)

-

0.4

2.5

  Total

59.6

(9.6)

(19.5)

(5.5)

0.9

25.9

  Total consolidated

210.3

(10.9)

(31.9)

(13.3)

16.0

170.2

  Total equity method

77.2

(15.4)

(8.8)

(2.0)

1.8

52.8

Un-allocated corporate

(18.6)

(0.2)

3.1

0.2

15.5

-

Total

$268.9

$(26.5)

$(37.6)

$(15.1)

$33.3

$223.0

Notes: Table 10B 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 11 – Free Cash Flow (in millions of U.S. dollars)

Unaudited                             

Years ended December 31,


2014

2013

2012

Cash Distributions from Projects

$248.9

$223.0

$196.6

Repayment of long-term debt

(29.8)

(26.5)

(27.4)

Interest expense, net

(33.5)

(37.6)

(24.0)

Capital expenditures

(14.0)

(15.1)

(1.8)

Other, including changes in working capital

26.9

33.3

25.4

Project Adjusted EBITDA

$299.3

$268.9

$224.4

Depreciation and amortization

201.7

208.8

163.5

Interest expense, net

39.5

38.5

24.0

Change in the fair value of derivative instruments

10.4

(50.3)

56.6

Other (income) expense

98.2

8.2

11.5

Project (loss) income

$(50.5)

$63.7

$(31.2)

Administrative and other expenses

143.5

101.4

112.9

Income tax expense (benefit)

(11.9)

(19.5)

(28.1)

Income (loss) from discontinued operations, net of tax

(0.1)

(5.6)

15.7

Net loss

$(182.2)

$(23.8)

$(100.3)

Adjustments to reconcile to net cash provided by operating activities

265.8

129.1

264.7

Change in other operating balances

(18.6)

47.1

2.7

Cash flows from operating activities

$65.0

$152.4

$167.1

Term loan facility repayments (1)

(58.4)

-

-

Project-level debt repayments

(26.2)

(15.6)

(19.6)

Purchases of property, plant and equipment (2)

(13.4)

(6.5)

(2.9)

Distributions to noncontrolling interests (3)

(11.0)

(8.9)

-

Dividends on preferred shares of a subsidiary company

(11.6)

(12.6)

(13.0)

Free Cash Flow

$(55.6)

$108.8

$131.6

Additional  GAAP cash flow measures:




Cash flows from investing activities

$68.7

$147.1

$(523.8)

Cash flows from financing activities

$(182.4)

$(207.6)

$362.7

(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 and 2013 and its Piedmont and Meadow Creek projects in 2013.

(3) 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 11 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 12 – Adjusted Cash Flows from Operating Activities and Adjusted Free Cash Flow (in millions of U.S. dollars)

Unaudited                             

Years ended December 31,


2014

2013

2012

Cash flows from operating activities

$65.0

$152.4

$167.1

Changes in other operating balances

18.6

(47.1)

(2.7)

Cash flows from discontinued operations

-

(31.6)

(89.0)

Severance charges

6.0

1.0

-

Restructuring charges

2.0

-

-

Shareholder litigation expenses

1.4

1.0

-

Refinancing transaction costs

49.4

-

-

Adjusted Cash Flows from Operating Activities

$142.4

$75.7

$75.4

Term loan facility repayments (1)

(58.4)

-

-

Project-level debt repayments

(26.2)

(15.6)

(19.6)

   Amount associated with discontinued operations (included in line above)

-

5.2

15.6

   Principal repayment of Piedmont debt at term conversion (included above)

8.1

-

-

Purchases of property, plant and equipment (2)

(13.4)

(6.5)

(2.9)

   Amount associated with discontinued operations (included in line above)

-

0.3

1.6

Distributions to noncontrolling interests (3)

(11.0)

(8.9)

-

Dividends on preferred shares of a subsidiary company

(11.6)

(12.6)

(13.0)

Adjusted Free Cash Flow

$29.9

$37.6

$57.1

Additional  GAAP cash flow measures:




Cash flows from investing activities

$68.7

$147.1

$(523.8)

Cash flows from financing activities

$(182.4)

$(207.6)

$362.7

(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 and 2013 and its Piedmont and Meadow Creek projects in 2013.

(3) 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 12 presents 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 13 – Project Adjusted EBITDA by Project (for Selected Projects)

(in millions of U.S. dollars) 

Unaudited


Years ended December 31,



2014

2013

2012

East

Accounting




Cadillac

Consolidated

$7.5

$9.1

$9.2

Curtis Palmer

Consolidated

31.5

32.1

28.0

Morris

Consolidated

12.7

6.3

8.2

Nipigon

Consolidated

15.3

13.4

14.6

North Bay

Consolidated

10.6

8.5

8.1

Piedmont

Consolidated

6.5

2.3

(0.1)

Tunis

Consolidated

10.3

9.5

13.5

Other (1)

Consolidated

19.8

19.1

9.6

Chambers

Equity method

18.6

20.6

27.8

Selkirk

Equity method

10.3

20.8

17.8

Orlando

Equity method

15.4

9.0

9.0

Total


158.5

150.7

145.7

West





Manchief

Consolidated

15.0

16.9

15.1

Naval Station

Consolidated

10.3

10.5

7.3

Williams Lake

Consolidated

15.8

16.5

18.5

Other (2)

Consolidated

23.0

16.1

23.0

Frederickson

Equity Method

12.2

12.1

10.8

Other (3)

Equity method

2.2

5.1

4.2

Total


78.5

77.2

78.9

Wind





Canadian Hills

Consolidated

26.6

25.6

0.8

Meadow Creek

Consolidated

19.3

14.0

-

Rockland

Consolidated

12.3

10.4

3.5

Other (4)

Equity method

11.6

9.6

6.6

Total


69.8

59.6

10.9

Totals





Consolidated projects


236.5

210.3

159.3

Equity method projects


70.3

77.2

76.2

Un-allocated corporate


(7.5)

(18.6)

(11.1)

Total Project Adjusted EBITDA


$299.3

$268.9

$224.4






Depreciation and amortization


$201.7

$208.8

$163.5

Interest expense, net


39.5

38.5

24.0

Change in the fair value of derivative instruments


10.4

(50.3)

56.6

Other (income) expense


98.2

8.2

11.5

Project income (loss)


$(50.5)

$63.7

$(31.2)

(1) 2012 and 2013: Kenilworth, Calstock, Kapuskasing, and Onondaga; 2014: Kenilworth, Calstock, and Kapuskasing

(2) Moresby Lake, Mamquam, North Island, Naval Training Station, and Oxnard

(3) 2012: Badger Creek, Delta-Person, Gregory, PERH, and Koma Kulshan; 2013: Koma Kulshan, Gregory, and Delta-Person; 2014:  Koma Kulshan and Delta-Person

(4) 2012: Idaho Wind; 2013 and 2014: Idaho Wind and Goshen North

 

Notes: Table 13 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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