DEDHAM, Mass., March 2, 2017 /PRNewswire/ -- Atlantic Power Corporation (NYSE: AT) (TSX: ATP) ("Atlantic Power" or the "Company") today reported its financial results for the three months and year ended December 31, 2016.  For additional information regarding the Company's 2016 performance, 2017 guidance and certain operational updates, including the status of certain upcoming Power Purchase Agreement (PPA) renewals, please consult Management's prepared remarks and the accompanying presentation, which will be available on the Conference Calls page of the Company's website (www.atlanticpower.com). 

Fourth Quarter 2016 Financial Results (vs. 2015)

• Cash provided by operating activities of $19.9 million vs. $19.7 million
• Net loss of $(6.6) million vs. $(88.6) million; 2015 included a $127.8 million impairment charge
• Project income of $13.3 million vs. project loss of $(104.3) million, including impairment charges
• Project Adjusted EBITDA of $42.3 million vs. $50.4 million; decline was attributable to lower water flows at Curtis Palmer, lower waste heat, and a scheduled maintenance outage at Oxnard

Full Year 2016 Financial Results (vs. 2015)

• Cash provided by operating activities of $111.8 million vs. $87.4 million
• Net loss of $(122.4) million vs. $(62.4) million; both years included significant impairment charges
• Project income of $10.1 million vs. project loss of $(41.4) million
• Project Adjusted EBITDA of $202.2 million vs. $208.9 million; results were below the Company's guidance of $205 to $215 million due to lower water flows at Curtis Palmer, lower waste heat and severance costs at three Ontario projects

Other Highlights

• Achieved net reduction in debt in 2016 of $22 million, despite upsizing term loan in April; now have significantly improved debt maturity profile
• Repurchased 8.1 million common shares at an average price of $2.42 since December 2015
• Reduced total overhead costs by 28% to $23 million in 2016 from $32 million in 2015
• Initiated 2017 Project Adjusted EBITDA guidance (see page 4 of this release)
• Expect to repay another $150 million or more of debt in 2017

"During 2016, we refinanced our existing term loan and revolver with a larger $700 million term loan and a $200 million revolver, both with extended maturity dates.  We also paid down $288 million of debt, ending the year with a reduction in consolidated debt of approximately $22 million, net of the term loan upsizing.   Since year end 2013, we have reduced consolidated debt by more than $800 million and improved our maturity profile considerably.  We also made further progress in reducing our interest payments and corporate overhead costs, which are now $60 million and $31 million lower than 2013 levels, respectively," said James J. Moore, Jr., President and CEO of Atlantic Power.  "In addition, we have lowered our share count by 6.6% since December 2015 by repurchasing and canceling approximately 8.1 million common shares at an average price of $2.42 per share."

"By strengthening our balance sheet, addressing our near-term maturities and reducing our fixed costs, we believe that we have positioned the Company to take a disciplined approach on renewals of PPAs and withstand an extended downturn in a very cyclical business," said Mr. Moore.  "We are enthusiastic about our strengthened financial position, expected 2017 operating cash flow and the uses of capital that we have available which are consistent with our objective of increasing intrinsic value per share." 

Mr. Moore continued, "After two years of dramatic change, the Company is now in a position to pay down an additional $150 million or more of debt in 2017; continue to repurchase shares when they trade at a significant discount to our estimates of intrinsic value per share, as they do today; work toward PPA renewals without financial pressure to transact quickly in a down market, and begin to implement a growth strategy, with efforts currently focused on industrial customers."

Financial Results

Three Months Ended December 31, 2016

The primary operational factors that affected the Company's results for the fourth quarter of 2016 included lower water flows at Curtis Palmer, lower waste heat at the Company's Ontario plants, a scheduled maintenance outage at Oxnard, turbine maintenance expense at Kapuskasing and North Bay and severance cost at Kapuskasing, North Bay and Nipigon.  These negative drivers were partially offset by higher water flows at Mamquam. 

Net loss attributable to Atlantic Power Corporation for the fourth quarter of 2016 of $(6.6) million included a $1.2 million non-cash impairment of the remaining goodwill at Moresby Lake and a $12.7 million charge for the non-cash accelerated amortization of intangible assets related to the PPAs at Kapuskasing and North Bay, which were terminated early as described in the Company's January 9, 2017 press release.  Net loss for the fourth quarter of 2015 of $(88.6) million included a $127.8 million non-cash impairment of long-lived assets and goodwill, primarily at Williams Lake.  The $82.0 million reduction in net loss in 2016 was primarily attributable to the reduction in impairment expense and an increase in the fair value of derivative instruments, partially offset by higher amortization expense, a reduction in largely unrealized foreign exchange gain, lower income tax benefit and the operational factors described previously.      

Project income for the fourth quarter of 2016 was $13.3 million versus project loss for the year-ago period of $(104.3) million.  The $117.6 million improvement from project loss in 2015 to project income in 2016 was primarily attributable to lower impairment expense and an increase in the fair value of derivative instruments as described previously, partially offset by higher amortization expense and the operational factors described previously. 

Project Adjusted EBITDA for the fourth quarter of 2016 was $42.3 million, a decline of $8.1 million from $50.4 million in the year-ago period.  Primary contributors to the decline were a $3.3 million reduction at Curtis Palmer due to lower water flows; a $5.0 million decrease at Kapuskasing and North Bay due to lower waste heat, turbine maintenance expense, and severance expense; and a $2.2 million decrease at Oxnard due to the scheduled maintenance outage.  Results for Kapuskasing, Nipigon and North Bay included $1.1 million of severance expense related to the revised operational status of and contractual arrangements for these plants announced in the Company's January 9, 2017 press release.  These decreases were partially offset by a $2.2 million increase at Mamquam due to favorable water flows and lower maintenance expense.    

Cash provided by operating activities of $19.9 million was in line with the $19.7 million reported for the year-ago period.  Significant uses of cash provided by operating activities during the fourth quarter of 2016 included $15.0 million of term loan amortization, $3.0 million of project debt amortization and $2.1 million of preferred dividend payments.    

Year Ended December 31, 2016

The primary operational factors that affected the Company's results for the year ended December 31, 2016 included an extended planned outage at Morris in the third quarter, lower water flows at Curtis Palmer, lower waste heat and fuel price escalation at some of the Company's Ontario plants, a contractual price adjustment at Calstock, and a scheduled maintenance outage at Oxnard.  These negative drivers were partially offset by the absence of an outage at Manchief (compared to 2015) and higher water flows at Mamquam. 

Net loss attributable to Atlantic Power Corporation of $(122.4) million for the year ended December 31, 2016 increased $60.0 million from a net loss of $(62.4) million in 2015.  The increased net loss was the result of a $32.8 million non-cash write-off of deferred financing costs in the second quarter attributable to the Company's refinancing activities (included in interest expense), $12.7 million of accelerated amortization expense in the fourth quarter related to the Kapuskasing and North Bay PPAs, a $13.9 million largely unrealized foreign exchange loss as compared to a $60.3 million unrealized foreign exchange gain in 2015, and the absence of income from the discontinued Wind business ($19.5 million in 2015).  The operational factors described previously had a net negative impact.  These negative factors affecting the 2016 net loss were partially offset by reduced impairment expense ($85.9 million in 2016, mostly in the third quarter, as compared to $127.8 million in 2015) and a $22.5 million positive variance in the fair value of derivatives.  Another positive factor was that corporate general and administrative costs declined $6.8 million in 2016 from 2015. 

Project income of $10.1 million for the year compared favorably to project loss of $(41.4) million for 2015.  The 2016 result benefited from lower impairment expense as previously described, a favorable change in the fair value of derivative instruments, higher project income at Manchief, which had a scheduled maintenance overhaul in the second quarter of 2015, partially offset by lower project income at Morris, which had an extended planned outage in the third quarter of 2016, lower project income at Curtis Palmer due to lower water flows, a contractual price adjustment at Calstock, a scheduled maintenance outage at Oxnard and increased amortization expense. 

Project Adjusted EBITDA of $202.2 million for the year decreased $6.7 million from $208.9 million for 2015.  Primary contributors to the decline were a $10.1 million reduction at Morris due to lower revenues and higher maintenance expense resulting from the extended outage in 2016, a $3.3 million decrease at Curtis Palmer due to lower water flows, and a decrease of $7.6 million at the Ontario projects due to lower waste heat, fuel escalators and a contractual price adjustment at Calstock.  The stronger U.S. dollar had a negative non-cash translation impact of approximately $2.9 million, almost all of which was in the first quarter.  These negative factors were partially offset by a $7.2 million increase at Manchief, which had a major gas turbine outage in 2015, and a $6.7 million increase at Mamquam due to higher water flows.      

Cash provided by operating activities of $111.8 million increased $24.4 million from the 2015 level of $87.4 million.  The increase was primarily attributable to a $29.3 million reduction in cash interest payments due to debt repayment in 2015 and 2016 and the absence of make-whole premiums associated with the redemption of the 9.0% Senior Unsecured Notes in 2015, a $6.8 million reduction in corporate G&A expense and a positive variance in changes in working capital.  These positive drivers were partially offset by the loss of $21.9 million of operating cash flow from the Wind businesses, which were included in the 2015 result.  The $6.7 million decrease in Project Adjusted EBITDA described previously also had a negative impact on operating cash flow in 2016.  In 2016, the Company used its $111.8 million of cash provided by operating activities to amortize $96.5 million of term loan and project debt, make capital expenditures of $7.2 million and pay preferred dividends of $8.5 million.           

2017 Guidance

The Company has not provided guidance for Project income or Net income because of the difficulty of making accurate forecasts and projections without unreasonable efforts with respect to certain highly variable components of these comparable GAAP metrics, including changes in the fair value of derivative instruments and foreign exchange gains or losses.  These factors, which generally do not affect cash flow, are not included in Project Adjusted EBITDA.    

The Company has initiated guidance for 2017 Project Adjusted EBITDA in the range of $225 to $240 million.  The increase from the 2016 level of $202.2 million is primarily attributable to the expiration on December 31, 2016 of an above-market gas supply contract for two of the Company's Ontario projects.  Other positive factors include an expected full year cash return on completed optimization investments; an expected return to average water flows, particularly at Curtis Palmer and Mamquam; and revised operational and contractual arrangements for Kapuskasing and North Bay as described in the Company's January 9, 2017 press release, net of the cost of putting those plants into a non-operational status.   Morris is also expected to have a positive comparison because of the extended outage it underwent in 2016, but this is expected to be more than offset by a planned maintenance outage at Frederickson in 2017 and expenses associated with preparing Tunis for a return to service in 2018 under the new PPA. 

Table 2 provides a bridge of the Company's 2017 Project Adjusted EBITDA guidance to Cash provided by operating activities.  For purposes of providing this bridge to a cash flow measure, the impact of changes in working capital is assumed to be nil.

Liquidity and Balance Sheet

Liquidity

As shown in Table 3, the Company's liquidity at December 31, 2016 was $204.1 million, essentially unchanged from $205.1 million at September 30, 2016.  An $8.2 million reduction in the unrestricted cash balance was mostly offset by a $7.2 million increase in borrowing capacity resulting from a reduction in letters of credit outstanding.  The unrestricted cash of $85.6 million includes approximately $60 million at the parent, of which the Company considers approximately $50 million to be discretionary cash available for general corporate purposes.   

Balance Sheet

Repayment of Term Loan and Project Debt

During the fourth quarter of 2016, the Company amortized $15.0 million of the APLP Holdings term loan and $3.0 million of project-level debt.  For the full year, the Company amortized $85.5 million of term loan debt, including $25.3 million in the first quarter related to the previous term loan, and $11.1 million of project-level debt.

Redemptions and Repurchases of Convertible Debentures

There were no redemptions or repurchases of convertible debentures in the fourth quarter of 2016.  For the year, the Company redeemed or repurchased a total of $191.5 million principal amount of convertible debentures.  This was done under the normal course issuer bid (NCIB) in the first quarter ($18.8 million), through the redemption at par of both 2017 issues in the second quarter ($110.1 million) using proceeds from the term loan refinancing, and under a substantial issuer bid in the third quarter ($62.7 million), also using proceeds from the refinancing.    

Debt Balance and Leverage at December 31, 2016

Although the refinancing of the Company's previous term loan in April 2016 resulted in a net increase in debt of $252 million, the allocation of a majority of the net cash proceeds from the refinancing to debt redemptions and repurchases in the second and third quarters of this year, together with ongoing amortization of the new term loan and project debt, as described previously, offset all but $10 million of this increase.  At December 31, 2016, the Company's consolidated debt was $996.5 million, excluding unamortized discounts and deferred financing costs, as compared to $1,018.7 million at year end 2015.  The Company's consolidated leverage ratio (consolidated gross debt to trailing 12-month consolidated Adjusted EBITDA) was 5.6 times at December 31, 2016. 

Debt Maturity Profile

As a result of refinancing and discretionary repurchases to date, the Company has no bullet maturities at the corporate level prior to June 2019, when the remaining $42.6 million of Series C convertible debentures will mature.  In addition, the Company has $60.3 million (U.S. dollar equivalent) of Series D convertible debentures maturing in December 2019.  The reshaping of the Company's maturity profile is further improved by the later maturity dates for the new term loan (2023 versus 2021 previously) and the new revolver (2021 versus 2018 previously).  The Company also has one project debt bullet maturity during this period – the term loan at its Piedmont project totaling $54 million at its maturity date of August 2018.  In addition to these bullet maturities, the Company has amortizing debt at various projects through 2025 and required amortization of the APLP Holdings term loan per a targeted debt schedule through the 2023 maturity date.          

2017 Debt Repayment Plans

The Company expects to amortize $100 million of its APLP Holdings term loan and $11.8 million of project debt in 2017 using cash flow.  In addition, the Company plans to allocate $40 million or more of its discretionary cash to additional debt reduction (which could include convertible debentures, further paydown of term loan and project debt maturities).  Thus, in total, the Company expects to repay approximately $150 million or more of debt in 2017.      

Normal Course Issuer Bid (discretionary repurchases of debt and equity)

The NCIB implemented by the Company in December 2015 expired on December 28, 2016.  Under this program, the Company repurchased $18.8 million principal amount of convertible debentures, all in the first quarter of 2016.  The Company also repurchased a total of slightly less than 8.1 million common shares, including 8.0 million in 2016, at a total cost including commissions of approximately $19.6 million (average price of $2.42 per share).  Share repurchases in the fourth quarter of 2016 totaled 2.4 million at a total cost of $5.8 million (average price of $2.44 per share). 

The Company implemented a new NCIB on December 29, 2016.  Under this NCIB, the Company may purchase up to 10% of the public float of the Company's outstanding common shares and convertible debentures and up to 5% of the amount issued and outstanding of Atlantic Power Preferred Equity Ltd.'s preferred shares.  Details of the program can be found in the Company's December 20, 2016 press release. 

Other Financial Updates

PPA Expirations and Negotiations

The Company has PPAs or other contractual arrangements scheduled to expire for nine of its projects in the next five years.  Together these represent 25% of the Company's capacity and 30% of 2016 Project Adjusted EBITDA.  In January 2017, the Company put the Kapuskasing, North Bay and Nipigon projects in Ontario into a non-operational state, under arrangements that provide a fixed monthly payment to the projects until December 2017 for Kapuskasing and North Bay and October 2018 for Nipigon.  Another Ontario project, Tunis, has not been operating since the expiration of its previous PPA in December 2014, but has a 15-year PPA that will commence between November 2017 and June 2019, at the Company's option.  The Company plans to return Tunis to service under the new PPA in 2018.  In San Diego, the Company's three plants (Naval Station, North Island and Naval Training Center) have expiring PPAs in December 2019, but these PPAs are dependent on the Company's right to use the underlying sites under agreements with the Navy that expire in February 2018.  The Company is currently considering negotiating, extending or entering into new agreements or arrangements for certain of the Ontario, San Diego and other projects for which the PPAs expire during this period.  For information on the status of these negotiations or arrangements, please consult the Company's 2016 Annual Report on Form 10-K. 

Optimization Investments

The Company made approximately $3.4 million of optimization-related investments in its projects in 2016, with the majority of those for upgrades to a boiler and two combustion turbines at Morris and a spillway upgrade project at Curtis Palmer, all of which were completed in 2016.  The Company expects to complete the upgrade of the third combustion turbine at Morris during an outage in the spring of this year.  Although the Company will continue to evaluate the potential for additional such investments, they are expected to be relatively modest.  The Company has begun an evaluation of its operation and maintenance costs and expects that to be a major focus in 2017.        

The Company realized a cash flow benefit of approximately $8 million in 2016 from optimization investments made in 2013 through 2016 totaling approximately $25 million, which was below the original expectation primarily because high levels of waste heat at Nipigon reduced the need for the duct burners and booster pump that were installed as optimization projects in 2014 and 2015, respectively.  In addition, lower water flows at Curtis Palmer in 2016 reduced the contribution from the turbine upgrades completed in 2013 and 2014.  The Company expects to realize a cash flow benefit of approximately $12 million in 2017 from these investments and those made in 2017, assuming average water conditions. 

Maintenance and Capex

In 2016, for its consolidated projects only, the Company incurred $37.9 million of maintenance expense versus $36.2 million in 2015.  In addition to maintenance expensed in the period, the Company made $7.2 million of capital expenditures versus $11.3 million in 2015.  Including the Company's share of projects in which it has an equity ownership interest, maintenance expense was $46.2 million in 2016 versus $55.6 million in 2015, and capital expenditures were $7.5 million versus $11.6 million in 2015.  For 2017, including its share of equity-owned projects, the Company expects to incur maintenance expenses of approximately $45 million (in line with the 2016 level) and make capital investments of between $5 million and $6 million (slightly lower than the 2016 level).  The maintenance expenditures in 2017 include an estimate of the cost to prepare Tunis for a return to service in 2018 under the new PPA. 

Material Weakness Remediated

As previously disclosed in the Company's 2015 Annual Report on Form 10-K, the Company had identified a material weakness in its internal controls over financial reporting because its internal controls over its long-lived asset and goodwill impairment tests where not designed effectively.  During 2016, management developed and implemented new control procedures to remediate this material weakness.  Upon completion of the testing of the design and operating effectiveness of these new control procedures in the annual goodwill impairment analysis it conducted in the fourth quarter of 2016, management concluded that as of December 31, 2016, it had remediated the previously identified material weakness.

Subsequent Event

As disclosed in the Company's 2016 Annual Report on Form 10-K, on February 27, 2017, the Company received notice from the Ontario Electricity Financial Corporation (OEFC) that the Company will be receiving a payment of approximately Cdn$8.4 million for its Kapuskasing and North Bay plants representing the application of the price escalator calculation under their respective PPAs for power sold to OEFC in 2016.  This payment stems from the Global Adjustment litigation brought by a group of Non-Utility Generators against the OEFC, which was decided in favor of the plaintiffs by the Superior Court of Canada.  The OEFC was denied leave to appeal this ruling by the Supreme Court of Canada in January 2017.

The Company was not a party to the litigation, but did enter into a standstill agreement with the OEFC in 2015, with respect to its Kapuskasing, North Bay and Tunis projects.  Under the standstill the Company reserved its right to bring claims against the OEFC with respect to the calculation of the price escalator provision in the PPAs for these three plants. 

The OEFC payment of Cdn$8.4 million is for Kapuskasing and North Bay only during 2016 and does not cover any prior period.  The Company has notified the OEFC that it reserves its right to contest the payment amount.  The amount will be included in the Company's revenue only when the matter is settled and all contingencies have been resolved.  The Company's 2017 financial guidance does not include any current or retroactive payments with respect to this matter.     

Supplementary Financial Information

Results for project income and Project Adjusted EBITDA exclude discontinued operations, which consist primarily of the Wind businesses that were sold in June 2015.  Results of discontinued operations are summarized on page 13 of this release.

A discussion of non-GAAP disclosures and schedules reconciling Project Adjusted EBITDA, a non-GAAP measure, to the comparable GAAP measure, can be found on pages 13 to 14 of this release.

Investor Conference Call and Webcast

Atlantic Power's management team will host a telephone conference call on Friday, March 3, 2017 at 8:30 AM ET.  Management's prepared remarks and an accompanying presentation will be available on the Conference Calls page of the Company's website prior to the call.   

Conference Call / Webcast Information:

Date:  Friday, March 3, 2017 

Start Time:  8:30 AM ET

Phone Number:  U.S. (Toll Free) 1-855-239-3193; Canada (Toll Free) 1-855-669-9657; International (Toll) 1-412-542-4129.

Conference Access:  Please request access to the Atlantic Power conference call.

Webcast:  The call will be broadcast over Atlantic Power's website at www.atlanticpower.com.

Replay/Archive Information:

Replay:  Access conference call number 10100699 at the following telephone numbers:  U.S. (Toll Free) 1-877-344-7529; Canada (Toll Free) 1-855-669-9658; International (Toll) 1-412-317-0088.  The replay will be available one hour after the end of the conference call through April 2, 2017 at 11:59 PM ET.     
Webcast archive:  The conference call will be archived on Atlantic Power's website at www.atlanticpower.com for a period of 12 months. 

About Atlantic Power

Atlantic Power owns and operates a diverse fleet of twenty-three power generation assets across nine states in the United States and two provinces in Canada.  The Company's power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices.  The aggregate gross electric generation capacity of this portfolio is approximately 2,138 megawatts (MW), and the Company's aggregate net ownership interest is approximately 1,500 MW.  Nineteen of the projects are currently operational, totaling 1,975 MW on a gross capacity basis and 1,337 MW on a net ownership basis.  The remaining four projects, all in Ontario, are not operational, three due to revised contractual arrangements with the offtaker and the other, Tunis, has a forward-starting 15-year contractual agreement that will commence between November 2017 and June 2019. 

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

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

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

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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 views of its debt maturity profile;
• the Company's views of its ability to take a disciplined approach on PPA expirations and to withstand an extended downturn in the business;
• the Company's view of the uses of capital available to it; the Company's expectation that it will repay $150 million or more of debt in 2017;
• the Company's view that its shares trade at a significant discount to its estimates of intrinsic value per share;
• the Company's view of its ability to implement a growth strategy;
• the Company's estimation that 2017 Project Adjusted EBITDA will be in the range of $225 to $240 million, and its expectations with respect to the drivers of 2017 Project Adjusted EBITDA;
• the Company's estimation that 2017 cash flows provided by operating activities will be in the range of $130 to $145 million, assuming for this purpose that working capital changes are nil;
• the Company's estimate of discretionary cash (approximately $50 million), and its plans to allocate approximately $40 million or more to discretionary debt repayment in 2017;
• the Company's expectation that it will realize a cash flow benefit of approximately $12 million in 2017 from discretionary investments made in 2013 through 2016 totaling approximately $25 million;
• the Company's expectation that in 2017, including its share of equity-owned projects, capital expenditures will total approximately $5 to $6 million and maintenance expense will total approximately $45 million; and
• the results of operations and performance of the Company's projects, business prospects, opportunities and future growth of the Company will be as described herein.

Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not or the times at or by which such performance or results will be achieved.  Please refer to the factors discussed under "Risk Factors" and "Forward-Looking Information" in the Company's periodic reports as filed with the Securities and Exchange Commission from time to time for a detailed discussion of the risks and uncertainties affecting the Company, including, without limitation, the outcome or impact of the Company's business strategy to increase the intrinsic value of the Company on a per-share basis through disciplined management of its balance sheet and cost structure and investment of its discretionary cash in a combination of organic and external growth projects, acquisitions, and repurchases of debt and equity securities; the Company's ability to enter into new PPAs on favorable terms or at all after the expiration of existing agreements, and the outcome or impact on the Company's business of any such actions.  Although the forward-looking statements contained in this news release are based upon what are believed to be reasonable assumptions, investors cannot be assured that actual results will be consistent with these forward-looking statements, and the differences may be material.  These forward-looking statements are made as of the date of this news release and, except as expressly required by applicable law, the Company assumes no obligation to update or revise them to reflect new events or circumstances.  The Company's ability to achieve its longer-term goals, including those described in this news release, is based on significant assumptions relating to and including, among other things, the general conditions of the markets in which it operates, revenues, internal and external growth opportunities, its ability to sell assets at favorable prices or at all and general financial market and interest rate conditions.  The Company's actual results may differ, possibly materially and adversely, from these goals.

 

 

Results of Discontinued Operations

The Wind projects, which were sold in June 2015, had no impact on financial results in 2016.  For the year ended December 31, 2015, the Wind projects had Project income of $52.6 million and cash provided by operating activities of $21.9 million, as shown in Table 7.

Non-GAAP Disclosures

Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP, and is therefore unlikely to be comparable to similar measures presented by other companies.  Investors are cautioned that the Company may calculate this non-GAAP measure in a manner that is different from other companies.  The most directly comparable GAAP measure is Project income (loss).  Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in the fair value of derivative instruments.  Management uses Project Adjusted EBITDA at the project level to provide comparative information about project performance and believes such information is helpful to investors.  A reconciliation of Project Adjusted EBITDA to Project income (loss) and to Net loss on a consolidated basis is provided in Table 8 on page 14 of this release. 

Cash Distributions from Projects is the amount of cash distributed by the projects to the Company out of available project cash flow after all project-level operating costs, interest payments, principal repayment, capital expenditures and working capital requirements.  A bridge of Project Adjusted EBITDA to Cash Distributions from Projects, previously included in this release, can be found in the fourth quarter and year end 2016 presentation on the Company's website.

Project income (loss) and Project Adjusted EBITDA by project, previously included in this release, can be found in the fourth quarter and year end 2016 presentation on the Company's website.

 

SOURCE Atlantic Power Corporation