News Column

Atlantic Power Corporation Releases Second Quarter 2014 Results

August 7, 2014

BOSTON, Aug. 7, 2014 /CNW/ -- Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the "Company") today released its results for the three and six months ended June 30, 2014. 

Atlantic Power Corporation Logo

"Our results this quarter benefited from continued strong wind generation, increased waste heat at our Ontario projects, improved water flows at Curtis Palmer and lower maintenance and administrative expenses versus a year ago.  The improvement in our operating results this quarter largely offset the impact of outages that we experienced earlier in the year," said Barry Welch, President and CEO of Atlantic Power.

"During the quarter, we repaid $37.5 million of our new term loan, which puts us on track to reduce total debt on a net basis by approximately $80 million this year.  The significant amount of term loan repayment resulted in negative Free Cash Flow this quarter, but we expect positive Free Cash Flow generation in the second half of the year," Mr. Welch continued.  "Based on our results year to date and our expectations for the balance of the year, we are reaffirming our 2014 guidance metrics for Project Adjusted EBITDA and Free Cash Flow."

All amounts are in U.S. dollars and are approximate unless otherwise indicated. Free Cash Flow, Cash Distributions from Projects, and 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 "Free Cash Flow", "Cash Distributions from Projects" and "Project Adjusted EBITDA" as used in this news release.

Second Quarter 2014 Financial Highlights

•Project loss of $(3.8) million decreased $24.1 million from  Q2 2013, driven by a $14.8 million non-cash impairment charge at Tunis in 2014 and $27.1 million of negative non-cash changes in fair value of derivatives  •Project Adjusted EBITDA of $75.0 million increased $19.1 million from Q2 2013, due to fewer outages, stronger wind and waste heat, higher water flows at Curtis Palmer and a full quarter of Piedmont•Cash flows from operating activities of $34.0 million increased $26.8 million from Q2 2013 •Free Cash Flow of $(15.1) million decreased $7.6 million from Q2 2013, as increased cash flows from operating activities were offset by the initial repayment on Atlantic Power Limited Partnership (APLP) term loan of $37.5 million (approximately 70% of amount expected for full year)

YTD June 2014 Financial Highlights

•Project income of $16.4 million decreased $35.4 million from YTD June 2013, driven by the $14.8 millionTunis impairment charge in 2014 and $25.0 million of negative non-cash changes in fair value of derivatives •Project Adjusted EBITDA of $149.6 million increased $13.5 million from YTD June 2013•Cash flows from operating activities of $5.5 million decreased $91.4 million from YTD June 2013, primarily due to $54 million of debt refinancing and repurchase costs, a $33 million reduction from businesses divested in 2013 and a $29 million reduction in working capital from 2013 •Free Cash Flow of $(61.0) million decreased $135.5 million from YTD June 2013 due to the reduction in cash flows from operating activities and $37.5 million of term loan repayment

Other Highlights

•On track to invest $17 million in 2014 (2013-2014 total $27 million) in existing projects to boost output, improve efficiency and reduce costs, with expected cash return of at least $8 million annually beginning in 2015 •Closed sale of Delta-Person for $7.2 million in proceeds, plus another $1.4 million held in escrow, expected to be released 12 months after close of the transaction •Liquidity at quarter-end totaled $261 million, including $158 million of unrestricted cash

2014 Guidance Reaffirmed





•Project Adjusted EBITDA of $280 to $305 million•Project Adjusted EBITDA for APLP alone of $165 to $175 million•Free Cash Flow of $0 to $25 million, which excludes approximately $49 million of debt refinancing transaction costs and $8 million of Piedmont debt payment (total $57.5 million)

 

Atlantic Power Corporation

Table 1 – Selected Results

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

Unaudited



Three months ended June 30,

Six months ended June 30,



2014

2013

2014

2013

Excluding results from discontinued operations(1)









Project revenue

$143.2

$136.1

$288.5

$273.6

Project (loss) income

(3.8)

20.3

16.4

51.8

Project Adjusted EBITDA

75.0

55.9

149.6

136.1

Cash Distributions from Projects

85.3

50.1

135.7

104.0

Aggregate power generation (thousands of Net MWh)

2,022.8

2,008.6

4,110.7

3,890.7

Weighted average availability

91.2%

92.9%

91.9%

93.9%

Including results from discontinued operations (1)









Cash flows from operating activities

$34.0

$7.2

$5.5

$96.9

Free Cash Flow

(15.1)

(7.5)

(61.0)

74.5

(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 and Cash Distributions from these assets are included in discontinued operations for the three and six month periods ended June 30, 2013 and June 30, 2014.

 The results of discontinued operations are excluded from Project revenue, Project income, Project Adjusted EBITDA and Cash Distributions from Projects 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.


 

Note: Project Adjusted EBITDA, Free Cash Flow and Cash Distributions from Projects are not recognized measures under GAAP and do not have any standardized meaning prescribed by GAAP;

therefore, these measures may not be comparable to similar measures presented by other companies. Please refer to Tables 9 through 12 for reconciliations of these non-GAAP measures to GAAP measures.


















 

Financial Results

Table 2 provides a breakdown of project income and Project Adjusted EBITDA by segment for the three and six month periods ended June 30, 2014 as compared to the same period in 2013. 

Project Income

Reported project income can fluctuate significantly due to impacts from non-cash mark-to-market fair value of derivatives adjustments. 

Three Months Ended June 30, 2014

Project income decreased by $24.1 million to $(3.8) million compared to $20.3 million for the same period in 2013.  The reduction in project income was primarily due to:

•Negative non-cash changes in the fair value of gas purchase agreements and interest rate swap agreements accounted for as derivatives in the East and Wind segments totaling $27.1 million•Decreased project income of $12.6 million at Tunis (East), primarily due to a long-lived asset and goodwill impairment of $14.8 million, partially offset by favorable outage comparisons •Decreased project income of $4.9 million at Selkirk (East), primarily due to accelerated depreciation resulting from the scheduled expiration of the project's Power Purchase Agreement (PPA) in August 2014

These decreases were partially offset by the following positive factors:





•Increased project income of $11.5 million at Kapuskasing (East) and Naval Training Center, Williams Lake and Mamquam (West) mostly due to lower maintenance expense versus 2013, when the projects underwent scheduled maintenance outages •Increased project income of $3.4 million at Curtis Palmer (East), primarily due to a decrease in interest expense of $2.8 million due to redemption of project's senior notes in February 2014•Increased project income of $3.3 million at Orlando (East), which benefited from lower gas costs following the termination of above-market swaps in February 2014 and higher capacity payments under a new PPA •Increased project income of $2.3 million at Piedmont (East), excluding the impact of derivatives included above, attributable to a full quarter of operation versus a partial quarter in 2013

 

Atlantic Power Corporation

Table 2 – Segment Results

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

Unaudited





Three months ended June 30,

Six months ended June 30,



2014

2013

2014

2013

Project income (loss)









East

$(3.6)

$12.2

$27.7

$43.4

West

6.7

(3.1)

1.5

0.4

Wind

(1.9)

14.5

(7.5)

15.3

Un-allocated Corporate

(5.0)

(3.3)

(5.3)

(7.3)

Total

(3.8)

20.3

16.4

51.8

Project Adjusted EBITDA









East

$38.5

$29.4

$84.0

$78.5

West

22.9

14.1

34.1

34.7

Wind

17.2

15.5

35.1

30.5

Un-allocated Corporate

(3.6)

(3.1)

(3.6)

(7.6)

Total

75.0

55.9

149.6

136.1

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 9 through 12 for a reconciliation of this non-GAAP measure to a GAAP measure.


The Company has not reconciled non-GAAP financial measures relating to individual projects to the directly comparable GAAP measure due to the difficulty in making the relevant adjustments on an

individual project basis. 






 

Six Months Ended June 30, 2014

Project income decreased by $35.4 million to $16.4 million compared to $51.8 million for the same period in 2013. The reduction in project income was primarily due to:

•Net negative non-cash changes in fair value of gas purchase agreements and interest rate swap agreements accounted for as derivatives in the East and Wind segments totaling $25.0 million•Decreased project income of $12.8 million at Tunis (East), primarily due to the $14.8 million impairment recorded in the second quarter of 2014, partially offset by favorable outage comparisons •Decreased project income of $7.2 million at Selkirk (East), primarily due to accelerated depreciation as described above •Decreased project income of $2.8 million at Piedmont (East), excluding the impact of derivatives included above, primarily due to higher fuel and maintenance costs, partially offset by increased capacity payments (the project had two quarters of operation in 2014 versus a partial quarter in 2013) •Net decreases in project income for other projects totaling approximately $7 million

These decreases were partially offset by the following positive factors:

•Increased project income of $10.5 million at Morris and North Bay (East) and Naval Training Center (West) primarily due to lower maintenance expense relative to 2013, when the projects underwent scheduled maintenance outages •Increased project income from Wind segment of $3.8 million, excluding the impact of derivatives included above, primarily due to increased wind generation from Meadow Creek•Increased project income of $3.1 million at Orlando (East), excluding the impact of derivatives included above, primarily due to lower gas costs and higher capacity payments as described above •Reduction in Un-allocated Corporate segment of $2.0 million, including $1.7 million in development costs and $0.6 million in administrative expenses related to cost reduction initiatives undertaken in 2013

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. 

Three Months Ended June 30, 2014

Project Adjusted EBITDA increased $19.1 million to $75.0 million from $55.9 million for the comparable period in 2013. The most significant contributors to the increase in Project Adjusted EBITDA were the following: 

Naval Training Center, Williams Lake and Mamquam (West), totaling approximately $9.1 million, primarily due to lower maintenance costs in 2014 relative to 2013, when the projects had scheduled maintenance outages •Ontario projects (East), totaling approximately $6.5 millionTunis, Kapuskasing and North Bay experienced lower maintenance costs in 2014 relative to 2013, when the projects had scheduled maintenance outages.  In addition, the Ontario projects benefited from higher waste heat generation resulting in additional energy margin •Piedmont (East), approximately $2.1 million, due to a full quarter of operation versus a partial quarter of operation in 2013 •Other projects in the East totaling approximately $2.0 million, primarily Orlando, due to lower gas costs and higher capacity payments, and Curtis Palmer, due to increased water flows due to a late snowmelt and above-average rainfall •Wind projects $1.7 million, primarily due to stronger wind generation, particularly at Meadow Creek

These increases were partially offset by the following decreases:

Cadillac (East), $1.3 million due to lower capacity revenue and energy margin and higher maintenance expenses due to a scheduled outage

Six Months Ended June 30, 2014

Project Adjusted EBITDA increased by $13.5 million to $149.6 million from $136.1 million for the same period in 2013, as the $19.1 million increase in the second quarter of 2014 described previously more than offset the reduction in the first quarter of 2014.  Results for the first quarter were adversely affected by extreme weather and several plant outages, difficulties sourcing fuel at the Company's biomass projects, a gas swap termination at Orlando and several project-specific factors.  For the six-month period, the most significant contributors to the increase in Project Adjusted EBITDA were the following:

•Wind projects, $4.6 million due to stronger wind generation, particularly at Meadow Creek and Rockland, partly offset by impact of Canadian Hills weather-related outage in January •Tunis, North Bay and Kapuskasing (East), totaling $4.5 million, due primarily to increased waste heat, decreased maintenance expenses and other factors •Morris (East)$4.4 million, due primarily to lower maintenance costs, lower fuel expenses and higher revenues (higher PJM power prices) •Naval Training Center (West), $3.9 million due to lower maintenance expense compared to 2013, when the project underwent scheduled turbine maintenance •Reduction in Un-allocated Corporate loss of $4.0 million, primarily due to a reduction in development costs at Ridgeline of $1.7 million and a reduction in administrative costs of $2.2 million resulting from cost reduction initiatives undertaken in 2013

These increases were partially offset by the following decreases:

Cadillac (East), $1.4 million due to lower capacity revenue and increased maintenance expenses resulting from a scheduled maintenance outage in March and April of 2014 that was extended  •Net decreases totaling approximately $6.5 million at other projects, including Williams Lake and North Island (West) and Calstock (East), as well as smaller decreases at other projects 

Cash Distributions from Projects

Cash Distributions from Projects, which excludes projects classified as discontinued operations, increased by $32 million to approximately $136 million for the six months ended June 30, 2014, compared to $104 million for the same period in 2013.  This result included a $35 million increase in the second quarter of 2014, which more than offset the decline in the first quarter of 2014. 

Significant increases in the six months ended June 30, 2014 relative to the year-ago period occurred at (i) the Navy projects in California and were 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; (ii) Meadow Creek, Canadian Hills, Rockland and Idaho Wind, due to the release of construction-related blade and credit reserves and increased wind generation; (iii) 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; and (iv) Nipigon and Tunis, due to the timing of revenue receipts.

These increases were partly offset by decreases at (i) 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, with distributions next expected to occur in December; (ii) Williams Lake, due to costs associated with a January 2014 forced outage; and (iii) Selkirk, due to use of working capital to support credit requirements, although a distribution from the project is expected in August. 

Cash Flow from Operating Activities

As previously reported, during the first quarter of 2014 the Company incurred significant costs in conjunction with its refinancing and debt repurchase transactions, which included entry into the new credit facilities, debt redemptions and repurchases, and the Piedmont term loan conversion.  These costs, which totaled approximately $100 million and included prepayment premiums and make-wholes, accrued interest expense, swap termination costs and financing expenses and fees, are detailed in Table 4 to the first quarter 2014 earnings release dated May 12, 2014.  Approximately $49.4 million of these costs were recorded in interest expense and another $4 million to terminate gas swaps at the Orlando project were included in fuel expense.  Together these reduced cash flows from operating activities and Free Cash Flow by approximately $54 million in the first quarter of 2014, $0 million in the second quarter of 2014 and $54 million in the first six months of 2014.  With the exception of the Orlando gas swap termination cost, these transaction costs did not affect Project income or Project Adjusted EBITDA. 

Three Months Ended June 30, 2014

Cash flows from operating activities increased by $26.8 million to $34 million compared to $7.2 million for the same period in 2013.  The increase is primarily due to the $19.1 million increase in Project Adjusted EBITDA for the quarter and a $7.0 million benefit from changes in working capital. 

Six Months Ended June 30, 2014

Cash flows from operating activities decreased by $91.4 million to $5.5 million compared to $96.9 million for the same period in 2013.  The decrease is primarily due to the $54 million of refinancing transaction costs incurred in the first quarter and described previously, a $32.8 million decrease in loss from discontinued operations (projects sold in 2013) and a $29.3 million decrease in working capital from the comparable 2013 period.  The decrease in working capital is due to a $31.6 million decrease in prepaid and other assets due to the collection of security deposits related to recently completed construction projects, such as Piedmont, Canadian Hills and Meadow Creek, in the first quarter of 2013.

Free Cash Flow

Three Months Ended June 30, 2014

Free Cash Flow decreased by $7.6 million to $(15.1) million compared to $(7.5) million for the same period in 2013.  The decrease is primarily due to $37.5 million of term loan facility repayments by APLP, partially offset by $28.6 million of higher operating cash flows.  The $37.5 million of term loan repayments in the second quarter included $1.5 million of 1% mandatory amortization ($6.0 million annually) and $36.0 million of debt repaid pursuant to the 50% sweep of APLP's cash flow after debt service and capex.  The Company expects term loan repayments for the full year to total approximately $52 to $55 million.

Six Months Ended June 30, 2014

Free Cash Flow decreased by $135.5 million to $(61.0) million compared to $74.5 million for the same period in 2013.  The decrease is primarily due to $37.5 million of term loan facility repayments by APLP and a $91.4 million decrease in operating cash flows as described previously.

The Company's full year 2014 Free Cash Flow guidance excludes (i) $49.4 million of interest expense related to the refinancing and debt repurchase transactions and (ii) the $8.1 millionPiedmont construction debt repayment.  On that basis, Free Cash Flow for the first six months of 2014 is approximately $(3.5) million compared to $74.5 million for the same period in 2013. 

Results of Discontinued Operations

Results of discontinued operations are discussed beginning on page 9 of this press release. 

Reaffirming 2014 Guidance





•Annual Project Adjusted EBITDA guidance of $280 to $305 million•Annual Free Cash Flow guidance of $0 to $25 million

Project Adjusted EBITDA

The Company is reaffirming its previous guidance for 2014 Project Adjusted EBITDA in the range of $280 to $305 million.  Results for the first six months of 2014 totaled $149.6 million, or approximately 51% of the full-year guidance.  In the second quarter, favorable maintenance cost comparisons due to fewer planned outages, increased waste heat, higher levels of wind generation, and increased water levels at Curtis Palmer mostly offset the impact on first-quarter results of plant outages, lower water levels at Curtis Palmer and a $4 million termination cost for certain gas swaps at Orlando. 

The Company is also reaffirming its expectation for APLP's 2014 Project Adjusted EBITDA in the range of $165 to $175 million

The Company has not reconciled non-GAAP financial measures relating to the APLP projects to the directly comparable GAAP measures due to the difficulty in making the relevant adjustments on an individual project basis.

Free Cash Flow

The Company is reaffirming its previous guidance for 2014 Free Cash Flow in the range of $0 to $25 million.  This guidance excludes (i) approximately $49.4 million in expenses associated with the first quarter refinancing and debt repurchase transactions and (ii) the $8.1 million repayment of Piedmont construction debt made to facilitate the term loan conversion in February, together totaling $57.5 million.  The Company's Free Cash Flow guidance is net of planned capital expenditures totaling $16 million and debt repayments under the APLP term loan of approximately $52 to $55 million in 2014. 

In the first six months of 2014, Free Cash Flow excluding the $57.5 million of transaction-related costs and Piedmont debt repayment (consistent with full-year guidance) was $(3.5) million.  However, this was after $37.5 million of term loan repayment.  The amount of term loan repayment in the second half of this year is expected to be lower than in the first half because of the timing of APLP cash flows, which are typically stronger in the winter and spring months at the Ontario projects (waste heat) and Curtis Palmer (hydro generation), and the timing of APLP capital expenditures, which are expected to be higher in the second half.  The Company expects that Free Cash Flow will benefit in the second half from distributions from minority-owned projects, some of which were deferred from the first half, and lower parent interest expense.

See Table 3 for full-year 2014 guidance and year-to date 2014 actual results.

Atlantic Power Corporation

Table 3 – 2014 Annual Guidance and YTD 2014 Actual

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

Unaudited



2014 Annual Guidance

 YTD 2014 Actual

Project Adjusted EBITDA



$280 - $305

$149.6

Free Cash Flow(1)



$0 - $25

$(61.0)

APLP Project Adjusted EBITDA (2)



$165 - $175

$88.8

(1) Free Cash Flow is defined as cash flows from operating activities less capex; project-level debt repayments, including amortization of the Senior Secured Term Loan Facility; and distributions to

noncontrolling interests, including preferred share dividends.  Note that 2014 guidance excludes $54 million of refinancing and debt repurchase transaction costs in first quarter 2014 and $8 million of

Piedmont debt repayment in February 2014. 


(2) 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.  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.


 

Note: Project Adjusted EBITDA, APLP Project Adjusted EBITDA 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.  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.






 

Financial Update

Liquidity 

As can be seen from Table 4, the Company's liquidity increased from approximately $246 million at March 31, 2014 to approximately $261 million as of June 30, 2014, including $158 million of unrestricted cash.  The Company plans to use $41 million of this cash to repay its Cdn$45 million convertible debentures due in October 2014.

The increase in liquidity in the quarter resulted from a reduction in letters of credit outstanding to $107 million from $144 million, which increased revolver availability by $37 million.  This was partly offset by a $22 million reduction in unrestricted cash, which was attributable to debt repayment and other uses of cash during the quarter. 

 

Atlantic Power Corporation

Table 4 – Liquidity (in millions of U.S. dollars)



Unaudited



 

March 31, 2014

 June 30, 2014

Revolver capacity



$210.0

$210.0

Letters of credit outstanding



(144.1)

(107.0)

Unused borrowing capacity



65.9

103.0

Unrestricted cash (1)



180.0

157.6

Total Liquidity



$245.9

$260.6

(1) Includes project-level cash for working capital needs of $16.4 million at June 30, 2014 and $17.6 million at March 31, 2014.





 

Covenant Update

Due to the aggregate impact of the up-front costs resulting from the prepayments and repurchases of the Company's indebtedness incurred in the first quarter of 2014 and as previously disclosed in the first quarter earnings release dated May 12, 2014, the Company is not in compliance with the fixed charge coverage ratio test included in the restricted payments covenant of the indenture governing its 9.0% senior unsecured notes.  The fixed charge coverage ratio must be at least 1.75 to 1.00 and is measured on a rolling four quarter basis, so the costs associated with debt prepayments and repurchases incurred in the first quarter of 2014 would no longer be included in the calculation beginning in the second quarter of 2015. 

As a consequence of the non-compliance, common dividend payments, which are declared and paid at the discretion of the Company's board of directors, in the aggregate cannot exceed the restricted payments "basket" provision of the greater of $50 million and 2% of consolidated net assets (approximately $61 million at June 30, 2014), until such time that the Company satisfies the fixed charge coverage ratio test.  The Company has declared seven monthly dividends in January through July totaling approximately $25.6 million that are subject to the basket provision. 

The Company expects to be in compliance with the financial maintenance covenants governing (i) the Company's 9.0% senior unsecured notes; (ii) APLP's senior secured credit facilities, including the term loan; and (iii) APLP's 5.95% Medium-Term Notes, for at least the next twelve months. 

Piedmont

During the first quarter of 2014, Piedmont underwent several forced maintenance outages that resulted in the project not meeting its debt service coverage ratio covenant as of June 30, 2014.  The Company does not expect Piedmont to pass its debt service coverage ratio covenant for at least the next twelve months.  As a result, the project is not expected to make distributions for at least the next twelve months, which is at least six months beyond the Company's previous expectation. 

Tunis Impairment

The Company's Tunis project in Ontario has a PPA with the Ontario Power Authority (OPA) that is scheduled to expire on December 31, 2014.  Consistent with its accounting policy of reviewing its projects for potential impairment six months prior to the expiration of an existing PPA, the Company conducted an impairment analysis of Tunis in the second quarter of 2014.  Based on the results of this analysis, the Company recorded a $14.8 million non-cash impairment charge for Tunis, including $9.6 million associated with the carrying value of the project's property, plant and equipment and $5.2 million for all of the project's goodwill. 

Business Update

Project Operating Performance

Three Months Ended June 30, 2014

Availability declined to 91.2% from 92.9% in the second quarter of 2013 due to extended scheduled maintenance outages at Cadillac, Orlando, and Naval Station, partly offset by fewer forced outage hours at Williams Lake and Naval Station than in the year-ago period.  Generation increased 0.7% due to higher generation at Curtis Palmer, Williams Lake, Meadow Creek and Rockland, partially offset by the outages at Cadillac, Orlando and Naval Station and reduced dispatch at Manchief and Selkirk.

Six Months Ended June 30, 2014

Availability declined to 91.9% from 93.9% in the first six months of 2013 due to both scheduled and forced outages in the first quarter of 2014, some of which were related to extreme weather, and extended scheduled maintenance outages at Cadillac, Orlando and Naval Station in the second quarter.  Generation increased 5.7% in the first six months of 2014 due to the addition of Piedmont in April 2013, increased dispatch at Chambers, higher generation at Frederickson, and higher wind generation at Meadow Creek and Rockland, partially offset by reduced dispatch at Manchief.  

Capex and Optimization Update

The Company now expects to have major maintenance and capital expenditures in 2014 of approximately $35 to $40 million.  This estimate is down slightly from the previous expectation of $38 to $43 million, because of an insurance recovery at Piedmont, timing of expenditures and cost savings on certain purchases, partly offset by increases at other projects.  In the first six months of 2014, the Company invested $12.5 million, or about one-third of the total expected for the year. 

Included in this forecast are certain expenditures designed to improve the operating performance and enhance the efficiency or lower the costs of the Company's existing portfolio.  The Company views these investments as an attractive use of its available cash as it believes that the risk-adjusted returns are compelling and the capital requirements are relatively modest.  The level of planned spending associated with these optimization initiatives is approximately $17 million in 2014.  The largest of these projects is the steam generator replacement and upgrade at Nipigon, which will occur during an outage scheduled to begin later this month and be completed this fall.  Total estimated cost of the Nipigon project is approximately $11 million, including $8 million to be spent in 2014.  Other projects already completed this year include the repowering of two turbines at Curtis Palmer and capacity uprates at North Island, Mamquam and Calstock.  A project designed to boost output at Morris during peak periods is under way, with the major equipment installed and performance testing scheduled for this month. 

Together with investments made in 2013 totaling $10 million, the Company expects that optimization-related spending over the two-year period totaling $27 million will produce incremental cash flow of at least $8 million annually on a run-rate basis beginning in 2015.  The Company is already realizing a portion of this benefit this year from investments completed to date. 

Going forward, the Company expects that major maintenance and routine capex will average approximately $25 million annually (versus approximately $19 million in 2014).  Although the level of optimization investments will vary from year to year, the Company has a target of identifying approximately $5 to $10 million of such investments annually. 

Supplementary Financial Information

For further information, attached to this news release is a summary of Project Adjusted EBITDA by segment for the three and six months ended June 30, 2014 and 2013 (Table 8) with a reconciliation to Project income (loss); a bridge from Project Adjusted EBITDA to Cash Distributions from Projects by segment for the six months ended June 30, 2014 (Table 9A) and the six months ended June 30, 2013 (Table 9B); a reconciliation of Cash Distributions from Projects and Project Adjusted EBITDA to Net income (loss) and of Free Cash Flow to cash flows from operating activities for the three and six months ended June 30, 2014 and 2013 (Table 10); 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 three and six months ended June 30, 2014 and 2013 (Table 11). 

Financial Results of Discontinued Operations

Financial results for the three and six month periods ended June 30, 2014 and June 30, 2013 are affected by the classification of the Company's interests in its divested assets as discontinued operations; accordingly, the revenues, project income, Project Adjusted EBITDA and Cash Distributions from Projects classified as discontinued operations are excluded from results from continuing operations.  The results of discontinued operations have been separately stated in the Consolidated Statements of Operations as "Net income (loss) from discontinued operations, net of tax".  The divested assets included in discontinued operations for these periods are the Auburndale, Lake, Pasco and Greeley projects and the Company's interests in Rollcast and Path 15.

The cash flow attributable to discontinued operations is included in cash flows from operating activities as shown on the Consolidated Statement of Cash Flows; therefore, the Company's calculation of Free Cash Flow as shown herein also includes cash flow from discontinued operations.

Project income (loss) from discontinued operations was $0.0 million and $(0.1) million, respectively, for the three and six months ended June 30, 2014, compared to $(5.0) million and $(4.1) million, respectively, for the same periods in 2013. •Project Adjusted EBITDA from discontinued operations was $0.0 million and $(0.1) million, respectively, for the three and six months ended June 30, 2014, compared to $6.6 million and $38.3 million, respectively, for the same periods in 2013. •Cash Distributions from Projects from discontinued operations was $0.0 million and $0.0 million, respectively, for the three and six months ended June 30, 2014, compared to $22.5 million and $22.6 million, respectively, for the same periods in 2013.

Delta-Person was sold in July 2014, resulting in a gain on sale of approximately $8.6 million, of which the Company received net cash proceeds of $7.2 million for its 40% interest in the project, with an additional $1.4 million currently held in escrow, which the Company expects will be released 12 months after the close of the transaction.  The Gregory project was sold in August 2013.  Gregory and Delta-Person are both accounted for under the equity method of accounting and therefore are included in the Company's financial results from continuing operations for the relevant reporting periods rather than being included in discontinued operations. 

The Company has not reconciled non-GAAP financial measures relating to discontinued operations to the directly comparable GAAP measures due to the difficulty in making the relevant adjustments on an individual project basis.

Investor Conference Call and Webcast

A telephone conference call hosted by Atlantic Power's management team will be held on Friday, August 8, 2014 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 3658548 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 10049145.  The replay will be available 1 hour after the end of the conference call through November 7, 2014 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 our Company and our projects.  These statements, which are based on certain assumptions and describe our 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:  

•2014 Project Adjusted EBITDA will be in the range of $280 to $305 million; •2014 APLP Project Adjusted EBITDA will be in the range of $165 to $175 million; •2014 Free Cash Flow will be in the range of $0 to $25 million, excluding refinancing and debt repurchase transaction costs and principal repayment of Piedmont construction debt; •the Company's Free Cash Flow will improve in the remainder of the year; •the Company will have positive Free Cash Flow generation in the second half of the year; •the Company will reduce total debt on a net basis by approximately $80 million this year; •the Company will repay the Cdn$44.8 million aggregate principal amount of convertible debentures due October 2014 at maturity using cash; •the Company will be in compliance with the financial maintenance covenants governing its 9.0% senior unsecured notes, APLP's senior secured credit facilities and APLP's 5.95% Medium-Term notes, for at least the next twelve months; •the impact of the fixed charge coverage ratio included in the restricted payments "basket" provision of the indenture governing the Company's 9.0% senior unsecured notes; •Piedmont will be unable to pass its debt service coverage ratio covenant for at least the next twelve months and as a result, will not make distributions for at least the next twelve months; •APLP term loan repayments for the full year will total approximately $52 to $55 million, including repayments in the second half that are less than first half repayments of $37.5 million, because of the timing of cash flows from APLP projects, which are typically stronger in the winter and spring months at certain projects, and the timing of APLP capital expenditures, which are expected to be higher in the second half of the year; •an additional $1.4 million of net cash proceeds from the sale of Delta-Person will be released to the Company 12 months after the close of the transaction; •the Company will have project capital expenditures and major maintenance expenses of approximately $35 to $40 million in 2014, including optimization initiatives of approximately $16 million; •major maintenance expense and maintenance capex will average approximately $25 million annually, versus approximately $19 million in 2014; •the level of optimization investments will be approximately $17 million in 2014, for a two-year (2013 and 2014) total of approximately $27 million, and that these investments will produce a cash flow run-rate contribution of approximately $8 million beginning in 2015, with a portion of that realized in 2014 from investments completed to date; •the Company will have annual optimization capex on average of approximately $5 to $10 million; and •the results of operations and performance of the Company's projects, business prospects, opportunities and future growth of the Company will be as described herein.

Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not or the times at or by which such performance or results will be achieved.  Please refer to the factors discussed under "Risk Factors" and "Forward-Looking Information" in the Company's periodic reports as filed with the Securities and Exchange Commission from time to time for a detailed discussion of the risks and uncertainties affecting our Company, including, without limitation, the Company's ability to evaluate and/or implement a broad range of potential options, including further selected asset sales or joint ventures to raise additional capital for growth or potential debt reduction, the acquisition of assets, the dividend level, as well as broader strategic options, including a sale or merger of the Company, and the impact any such potential options may have on the Company or the Company's stock price.   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.  Readers are cautioned that such information may not be appropriate for other purposes.

 

Atlantic Power Corporation

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











June 30,

December 31,









2014

2013

Assets







Unaudited

Current assets:









Cash and cash equivalents







$157.6

$158.6

Restricted cash







17.8

96.2

Accounts receivable







61.5

64.3

Current portion of derivative instruments asset







1.7

0.2

Inventory







18.6

16.0

Prepayments and other current assets







15.4

16.1

Refundable income taxes







2.1

4.0

Total current assets







274.7

355.4













Property, plant and equipment, net







1,751.2

1,813.4

Equity investments in unconsolidated affiliates







368.5

394.3

Other intangible assets, net







420.6

451.5

Goodwill







291.1

296.3

Derivative instruments asset







6.3

13.0

Other assets







98.3

71.1

Total assets







$3,210.7

$3,395.0













Liabilities and Shareholder's Equity











Current liabilities:











Accounts payable







$10.5

$14.0

Accrued interest







6.3

17.7

Other accrued liabilities







48.9

58.8

Current portion of long-term debt







26.4

216.2

Current portion of convertible debentures







42.0

42.1

Current portion of derivative instruments liability







28.4

28.5

Dividends payable







3.8

6.8

Other current liabilities







8.1

5.3

Total current liabilities







174.4

389.4













Long-term debt







1,436.0

1,254.8

Convertible debentures







362.4

363.1

Derivative instruments liability







58.2

76.1

Deferred income taxes







95.7

111.5

Power purchase and fuel supply agreement liabilities, net







36.9

38.7

Other non-current liabilities







63.2

65.4

Commitments and contingencies







-

-

Total liabilities







2,226.8

2,299.0













Equity











Common shares, no par value, unlimited authorized shares; 120,712,916

and 120,205,813 issued and outstanding at June 30, 2014 and December

31, 2013, respectively








1,286.5

1,286.1

Preferred shares issued by a subsidiary company







221.3

221.3

Accumulated other comprehensive loss







(24.1)

(22.4)

Retained deficit







(754.3)

(655.4)

Total Atlantic Power Corporation shareholders' equity







729.4

829.6

Noncontrolling interests







254.5

266.4

Total equity







983.9

1,096.0

Total liabilities and equity







$3,210.7

$3,395.0























 







Atlantic Power Corporation

Table 6 – Consolidated Statements of Operations

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

Unaudited





















Three months ended

 June 30,



Six months ended

 June 30,



2014

2013



2014

2013

Project revenue:









Energy sales

$82.4

$76.9



$164.7

$153.8

Energy capacity revenue

41.3

42.9



74.8

77.2

Other

19.5

16.3



49.0

42.6



143.2

136.1



288.5

273.6













Project expenses:











Fuel

50.4

50.0



110.2

97.7

Operations and maintenance

34.5

46.4



67.2

73.9

Development

1.1

1.8



1.8

3.5

Depreciation and amortization

40.9

41.8



81.5

82.7



126.9

140.0



260.7

257.8

Project other income (expense):











Change in fair value of derivative instruments

(2.8)

24.3



11.9

36.9

Equity in earnings of unconsolidated affiliates

3.3

8.7



11.9

15.9

Interest expense, net

(5.8)

(8.8)



(20.4)

(16.8)

Impairment

(14.8)

-



(14.8)

-



(20.1)

24.2



(11.4)

36.0

Project (loss) income

(3.8)

20.3



16.4

51.8













Administrative and other expenses (income):











Administration

10.2

11.8



17.5

20.1

Interest, net

27.7

25.3



94.1

51.2

Foreign exchange loss (gain)

15.3

(14.5)



(1.5)

(22.0)

Other income, net

-

(9.5)



(2.1)

(9.5)



53.2

13.1



108.0

39.8

(Loss) income from continuing operations before income taxes

(57.0)

7.2



(91.6)

12.0

Income tax (benefit) expense

(0.6)

0.6



(12.9)

(1.9)

(Loss) income from continuing operations

(56.4)

6.6



(78.7)

13.9

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

-

(5.4)



(0.1)

(4.9)

Net (loss) income

(56.4)

1.2



(78.8)

9.0

Net (loss) income attributable to noncontrolling interest

(0.3)

1.1



(6.7)

(0.8)

Net income attributable to preferred share dividends of a subsidiary company

3.1

3.1



5.9

6.3

Net (loss) income attributable to Atlantic Power Corporation

$(59.2)

$(3.0)



$(78.0)

$3.5













Basic earnings per share:











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

$(0.49)

$0.02



$(0.65)

$0.07

Loss from discontinued operations, net of tax

-

(0.05)



-

(0.04)

Net (loss) income attributable to Atlantic Power Corporation

$(0.49)

$(0.03)



$(0.65)

$0.03

 

Diluted earnings per share:











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

$(0.49)

$0.02



$(0.65)

$0.07

Loss from discontinued operations, net of tax

-

(0.05)



-

(0.04)

Net (loss) income attributable to Atlantic Power Corporation

$(0.49)

$(0.03)



$(0.65)

$0.03

(1) Includes contributions from the Sold Projects and Path 15, which are a component of discontinued operations.



 

Atlantic Power Corporation

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

Unaudited









Six months ended June 30,





2014

2013

Cash flows from operating activities:







Net (loss) income



$(78.8)

$9.0

Adjustments to reconcile to net cash provided by operating activities







Depreciation and amortization



81.5

92.8

Loss of discontinued operations



-

32.8

Gain on sale of asset



(2.1)

(4.4)

Long-term incentive plan expense



0.9

1.2

Impairment charges



14.8

4.9

Equity in earnings from unconsolidated affiliates



(11.9)

(15.9)

Distributions from unconsolidated affiliates



37.8

18.0

Unrealized foreign exchange gain



(1.4)

(8.7)

Change in fair value of derivative instruments



(11.9)

(47.7)

Change in deferred income taxes



(15.5)

(6.5)

Change in other operating balances







Accounts receivable



2.8

(3.6)

Inventory



(2.6)

(1.3)

Prepayments, refundable income taxes and other assets



14.7

46.3

Accounts payable



(4.6)

(9.4)

Accruals and other liabilities



(18.2)

(10.6)

Cash provided by operating activities



5.5

96.9









Cash flows provided by investing activities







Change in restricted cash



78.4

(19.4)

Proceeds from sale of asset, net



1.0

148.3

Proceeds from treasury grant



-

53.7

Biomass development costs



-

(0.1)

Construction in progress



(1.5)

(28.5)

Purchase of property, plant and equipment



(2.5)

(2.7)

Cash provided by investing activities



75.4

151.3









Cash flows used in financing activities







Proceeds from senior secured term loan facility



600.0

-

Proceeds from project-level debt



-

20.8

Repayment of corporate and project-level debt



(608.0)

(64.2)

Payments for revolving credit facility borrowings



-

(67.0)

Deferred financing costs



(38.8)

-

Equity contribution from noncontrolling interest



-

44.6

Offering costs related to tax equity



-

(1.0)

Dividends paid to common shareholders



(20.9)

(43.2)

Dividends paid to noncontrolling interests



(14.2)

(9.3)

Cash used in financing activities



(81.9)

(119.3)









Net (decrease) increase in cash and cash equivalents



(1.0)

128.9

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

Cash and cash equivalents at end of period



$157.6

$195.6









Supplemental cash flow information







Interest paid



$114.7

$65.3

Income taxes paid, net



$1.0

$1.4

Accruals for construction in progress



$8.2

$8.6















 

Regulation G Disclosures

Project Adjusted EBITDA, Cash Distributions from Projects and Free Cash Flow are not measures recognized under GAAP and do not have standardized meanings prescribed by GAAP.  Management believes that Free Cash Flow and Cash Distributions from Projects are relevant supplemental measures of the Company's ability to earn and distribute cash returns to investors.  Reconciliations of Free Cash Flow to cash flows from operating activities and of Cash Distributions from Projects to Project income (loss) are provided in Table 10 on page 17 of this release.  Investors are cautioned that the Company may calculate these measures in a manner that is different from other companies.

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.

Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments.  Project Adjusted EBITDA is not a measure recognized under GAAP and is therefore unlikely to be comparable to similar measures presented by other companies and does not have a standardized meaning prescribed by GAAP.  Management uses Project Adjusted EBITDA at the project level to provide comparative information about project performance and believes such information is helpful to investors.  A reconciliation of Project Adjusted EBITDA to project income (loss) and a bridge to Cash Distributions from Projects are provided in Table 8 below and Tables 9A and 9B on page 16, respectively.  Investors are cautioned that the Company may calculate this measure 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 June 30,

Six months ended June 30,



2014

2013

2014

2013

Project Adjusted EBITDA by segment









East (1)

$38.5

$29.4

$84.0

$78.5

West (2)

22.9

14.1

34.1

34.7

Wind

17.2

15.5

35.1

30.5

Un-allocated corporate (3)

(3.6)

(3.1)

(3.6)

(7.6)

Total

$75.0

$55.9

$149.6

$136.1











Reconciliation to project income









Depreciation and amortization

52.3

50.5

104.7

102.3

Interest expense, net

8.6

9.5

24.7

19.7

Change in the fair value of derivative instruments

3.1

(26.8)

(11.0)

(38.3)

Other (income) expense

14.8

2.4

14.8

0.6

Project income (loss)

$(3.8)

$20.3

$16.4

$51.8

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

(2) Excludes Greeley and Path 15, which are components of discontinued operations.

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

 

Note: 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)

Six months ended June 30, 2014 (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













  Consolidated

$60.3

$(9.4)

$(9.9)

$(0.6)

$24.2

$64.6

  Equity method

23.7

(3.3)

(5.4)

(0.6)

1.7

16.1

  Total

84.0

(12.7)

(15.3)

(1.2)

25.9

80.7

West













  Consolidated

26.6

-

-

(0.8)

(1.7)

24.1

  Equity method

7.5

(1.0)

-

-

0.3

6.8

  Total

34.1

(1.0)

-

(0.8)

(1.4)

30.9

Wind













  Consolidated

29.7

(3.5)

(7.1)

(0.3)

2.5

21.3

  Equity method

5.4

(2.9)

(2.3)

0.2

2.4

2.8

  Total

35.1

(6.4)

(9.4)

(0.1)

4.9

24.1

  Total consolidated

116.6

(12.9)

(17.0)

(1.7)

25.0

110.0

  Total equity method

36.6

(7.2)

(7.7)

(0.4)

4.4

25.7

Un-allocated corporate

(3.6)

-

-

(0.9)

4.5

-

Total

$149.6

$(20.1)

$(24.7)

$(3.0)

$33.9

$135.7

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)

Six months ended June 30, 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

$53.8

$(2.7)

$(8.1)

$(1.3)

$14.9

$56.6

  Equity method

24.7

(7.0)

(1.2)

-

2.6

19.1

  Total

78.5

(9.7)

(9.3)

(1.3)

17.5

75.7

West













  Consolidated

26.2

-

-

(0.8)

(12.0)

13.4

  Equity method

8.5

(1.6)

(0.1)

(0.4)

0.1

6.5

  Total

34.7

(1.6)

(0.1)

(1.2)

(11.9)

19.9

Wind













  Consolidated

25.5

(4.9)

(7.4)

(2.3)

(4.2)

6.7

  Equity method

5.0

(1.1)

(2.4)

(0.1)

0.3

1.7

  Total

30.5

(6.0)

(9.8)

(2.4)

(3.9)

8.4

  Total consolidated

105.5

(7.6)

(15.5)

(4.4)

(1.3)

76.7

  Total equity method

38.2

(9.7)

(3.7)

(0.5)

3.0

27.3

Un-allocated corporate

(7.6)

-

(1.3)

-

8.9

-

Total

$136.1

$(17.3)

$(20.5)

$(4.9)

$10.6

$104.0

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

 June 30,



Six months ended

June 30,



2014

2013



2014

2013

Cash Distributions from Projects

$85.3

$50.1



$135.7

$104.0

Repayment of long-term debt

(8.4)

(11.7)



(20.1)

(17.3)

Interest expense, net

(8.5)

(11.1)



(24.7)

(20.5)

Capital expenditures

(1.3)

(2.7)



(3.0)

(4.9)

Other, including changes in working capital

28.5

19.7



33.9

10.6

Project Adjusted EBITDA

$75.0

$55.9



$149.6

$136.1

Depreciation and amortization

52.3

50.5



104.7

102.3

Interest expense, net

8.6

9.5



24.7

19.7

Change in the fair value of derivative instruments

3.1

(26.8)



(11.0)

(38.3)

Other (income) expense

14.8

2.4



14.8

0.6

Project (loss) income

$(3.8)

$20.3



$16.4

$51.8

Administrative and other expenses (income)

53.2

13.1



108.0

39.8

Income tax (benefit) expense

(0.6)

0.6



(12.9)

(1.9)

Net loss from discontinued operations, net of tax

-

(5.4)



(0.1)

(4.9)

Net (loss) income

$(56.4)

$1.2



$(78.8)

$9.0

Adjustments to reconcile to net cash provided by operating

activities


95.6

18.1



92.2

66.5

Change in other operating balances

(5.2)

(12.1)



(7.9)

21.4

Cash flows from operating activities

$34.0

$7.2



$5.5

$96.9

Term loan facility repayments (1)

(37.5)

-



(37.5)

-

Project-level debt repayments

(5.5)

(7.9)



(15.4)

(10.5)

Purchases of property, plant and equipment (2)

0.1

(1.7)



(2.5)

(2.7)

Distributions to noncontrolling interests (3)

(3.1)

(2.0)



(5.2)

(2.9)

Dividends on preferred shares of a subsidiary company

(3.1)

(3.1)



(5.9)

(6.3)

Free Cash Flow

$(15.1)

$(7.5)



$(61.0)

$74.5

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

(2) Excludes construction costs related to our Canadian Hills project in 2014 and 2013 and our 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 10 presents Cash Distributions from Projects, Project Adjusted EBITDA and Free Cash Flow, which are not recognized measures under GAAP and do not have any standardized meanings

prescribed by GAAP; therefore, these measures may not be comparable to similar measures presented by other companies.








 











Atlantic Power Corporation

Table 11 – Project Adjusted EBITDA by Project (for Selected Projects)

(in millions of U.S. dollars) 

Unaudited













Three months ended

June 30,

Six months ended

June 30,







2014

2013

2014

2013

East



Accounting









Cadillac



Consolidated

$1.2

$2.4

$3.2

$4.6

Curtis Palmer



Consolidated

12.1

11.4

18.7

18.7

Morris



Consolidated

2.8

1.0

6.6

2.1

Nipigon



Consolidated

2.8

2.3

8.7

8.6

North Bay



Consolidated

1.2

(0.8)

6.1

4.5

Piedmont



Consolidated

2.2

0.1

0.8

0.1

Tunis



Consolidated

1.0

(0.8)

5.8

4.1

Other (1)



Consolidated

3.4

2.8

10.4

11.1

Chambers



Equity method

4.0

4.3

9.8

10.2

Selkirk



Equity method

4.2

4.4

9.1

10.1

Orlando



Equity method

3.6

2.3

4.8

4.4

Total





38.5

29.4

84.0

78.5

West













Manchief



Consolidated

3.5

3.9

7.2

7.9

Naval Station



Consolidated

3.5

3.1

4.8

4.5

Williams Lake



Consolidated

2.8

(0.3)

6.8

8.4

Other (2)



Consolidated

9.5

3.0

7.8

5.4

Frederickson



Equity method

2.6

2.8

5.9

5.9

Other (3)



Equity method

1.0

1.6

1.6

2.6

Total





22.9

14.1

34.1

34.7

Wind













Canadian Hills



Consolidated

8.1

7.8

13.8

14.5

Meadow Creek



Consolidated

4.2

3.5

10.2

6.5

Rockland



Consolidated

2.3

2.0

5.7

4.5

Other (4)



Equity method

2.6

2.2

5.4

5.0

Total





17.2

15.5

35.1

30.5

Totals













Consolidated projects





60.6

41.4

116.6

105.5

Equity method projects





18.0

17.6

36.6

38.2

Un-allocated corporate





(3.6)

(3.1)

(3.6)

(7.6)

Total Project Adjusted EBITDA





$75.0

$55.9

$149.6

$136.1















Reconciliation to project income (loss)













Depreciation and amortization





$52.3

$50.5

$104.7

$102.3

Interest expense, net





8.6

9.5

24.7

19.7

Change in the fair value of derivative instruments





3.1

(26.8)

(11.0)

(38.3)

Other (income) expense





14.8

2.4

14.8

0.6

Project income (loss)





$(3.8)

$20.3

$16.4

$51.8





(1) Kenilworth, Calstock, and Kapuskasing

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

(3) Q2 and YTD June 2013: Koma Kulshan, Gregory, and Delta-Person; Q2 and YTD June 2014:  Koma Kulshan

and Delta-Person


(4) Idaho Wind and Goshen North

 

Notes: Table 11 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. 



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SOURCE Atlantic Power Corporation


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