AT Atlantic Power Corporation

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):  March 21, 2016

ATLANTIC POWER CORPORATION

(Exact name of registrant as specified in its charter)

(617) 977-2400

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o            Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o            Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o            Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o            Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01.                                        Regulation FD Disclosure.

Launch of Syndication of Proposed New Senior Secured Credit Facilities

On March 21, 2016, Atlantic Power Corporation (the “Company”)  issued a press release announcing that, as part of the Company’s ongoing plans to reshape its balance sheet and further reduce its near-term debt maturities, it intends to refinance 1) the existing senior secured term loan of Atlantic Power Limited Partnership (“APLP”), a wholly-owned, indirect subsidiary of the Company (the “APLP Term Loan”), and 2) APLP’s existing $210 million senior secured revolving credit facility (the “APLP Revolver”).  APLP Holdings Limited Partnership (“APLP Holdings”), a wholly-owned, direct and indirect subsidiary of the Company that directly and indirectly wholly owns APLP, launched the syndication of proposed new senior secured credit facilities, comprising up to $700 million in aggregate principal amount of senior secured term loan facilities (the “New Term Loan”) and up to $210 million in aggregate principal amount of senior secured revolving credit facilities (the “New Revolver” and, together with the New Term Loan, the “New Credit Facilities”).

The Company and its subsidiaries expect to use the New Credit Facilities, subject to entry into definitive documentation for the New Credit Facilities, satisfaction of the conditions to closing thereunder and the other matters more fully described below, to:

·               replace the APLP Revolver maturing in February 2018;

·               fund the optional prepayment of the APLP Term Loan, which has an outstanding principal amount of $473.2 million as of December 31, 2015 and matures in February 2021;

·               fund the optional prepayment or redemption, subject to the Company’s definitive determination to issue respective notices of redemption, of the Company’s outstanding Cdn$67.3 million 6.25% Convertible Unsecured Subordinated Debentures, Series A, maturing in March 2017, and the Company’s outstanding Cdn$75.8 million 5.60% Convertible Unsecured Subordinated Debentures, Series B, maturing in June 2017 (total US$ equivalent $103.4 million as of December 31, 2015);

·               provide for ongoing working capital needs of the Company and of APLP Holdings and its subsidiaries;

·               support APLP Holdings’ and its subsidiaries’ collateral support obligations to contract counterparties;

·               provide for general corporate purposes of APLP Holdings and its subsidiaries;

·               fund a debt service reserve for the new revolving credit facility;

·               pay transaction costs and expenses; and

·               (upon closing) make a distribution to the Company from remaining proceeds of the term loan, which the Company may use for any corporate purpose, which may include, at the discretion of the Company, taking into account available funds, market conditions and other relevant factors, repurchase of the Company’s $117 million of 5.75% Convertible Unsecured Subordinated Debentures, Series C, due June 2019 , the Company’s Cdn$90 million of 6.00% Convertible Unsecured Subordinated Debentures, Series D, due December 2019 and the Company’s preferred and common equity and other potential initiatives to reshape the Company’s capital structure.

The New Term Loan is expected to have a seven-year maturity (two years later than the maturity of the APLP Term Loan) and the New Revolver a five-year maturity (three years later that the maturity of the APLP Revolver).  Following completion of the refinancing, the Company will have no corporate debt maturities prior to 2019.  Although initially this refinancing will not result in a net reduction in debt, debt reduction is expected to occur over time through mandatory amortization of the new term loan and a 50% cash sweep.

Subject to and concurrent with the closing of this transaction, two other indirect, wholly-owned subsidiaries of the Company – Atlantic Power Transmission, Inc. (“APT”) and Atlantic Power Generation, Inc. (“APG”) – will be contributed to APLP Holdings.  Five of the six power generating assets owned by APT and APG will be added to the existing borrower’s collateral package of 17 power generating assets.  The collateral package for the New Credit Facilities will thus consist of a first lien on 16 of the 17 APLP projects, a pledge of the Company’s equity interest in the remaining APLP project, and a pledge of the Company’s equity interests in the five contributed projects at APT and APG.  In addition, the Company will provide a downstream guarantee of the New Credit Facilities.

APLP’s existing Cdn$210 million aggregate principal amount of 5.95% Senior Unsecured Medium Term Notes maturing in June 2036 (the “MTNs”) prohibit APLP (subject to certain exceptions) from granting liens over any of its assets (and those of its material subsidiaries) to secure any indebtedness, unless the MTNs are secured equally and ratably with such other indebtedness.  Accordingly, in connection with the execution of the New Credit Facilities, APLP will grant an equal and ratable security interest in the collateral package securing the New Credit Facilities in favor of the trustee for the benefit of the holders of the MTNs.

The closing of the New Credit Facilities is subject to syndication, the conclusion of negotiations, execution of definitive documentation, receipt of requisite approvals and satisfaction of customary closing conditions.  There can be no assurance that APLP Holdings will be successful in its syndication efforts or that APLP Holdings will be able to enter into the New Credit Facilities.

The Company has appointed Goldman Sachs Lending Partners LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated as joint lead arrangers for the New Credit Facilities.

Subject to the conclusion of negotiations and execution of definitive documentation and other matters noted above, the following is a summary of certain anticipated terms of the New Credit Facilities:

The New Credit Facilities will be subject to customary mandatory prepayment provisions, including:

·               1% of outstanding principal per annum;

·               50% of excess cash flow from APLP Holdings; and

·               from proceeds of asset sales, insurance proceeds, and incurrence of indebtedness, in each case subject to applicable thresholds and customary carve-outs.

The New Credit Facilities will require APLP Holdings and its subsidiary guarantors to maintain a maximum leverage ratio of total debt to Project Adjusted EBITDA and a minimum interest coverage ratio of Project Adjusted EBITDA to cash interest expense. The levels of these ratios have not yet been determined.  In addition, the New Credit Facilities will include customary restrictions and limitations on APLP Holdings’ and its subsidiary guarantors’ ability to (i) incur additional indebtedness; (ii) grant liens on any of their assets; (iii) change their conduct of business or enter into mergers, consolidations, reorganizations, or certain other corporate transactions; (iv) dispose of assets; (v) modify material contractual obligations; (vi) enter into affiliate transactions; (vii) incur capital expenditures, and (viii) make dividend payments or other distributions, in each case subject to customary carve-outs and exceptions and various negotiated thresholds.

If the Company experiences a change of control (as defined in the New Credit Facilities), unless the Company elects to make a voluntary prepayment of the term loan under the New Credit Facilities, it will be required to offer each electing lender to prepay such lender’s outstanding principal amount of term loans under the New Credit Facilities at a price equal to 101% of par, plus all accrued interest.

The New Credit Facilities will permit APLP Holdings to request one or more incremental term loan facilities in an aggregate principal amount not to exceed $120 million, which may be used (i) to repay indebtedness of the Company, APLP Holdings or any of APLP Holdings’ subsidiary guarantors; (ii) for general working capital purposes of the Company, APLP Holdings or any subsidiary of the Company, and (iii) other general corporate purposes of APLP Holdings and any of APLP Holdings’ subsidiary guarantors.  Such incremental term loan facility would be subject to syndication, the conclusion of negotiations, execution of definitive documentation, receipt of requisite approvals and satisfaction of customary closing conditions.  There can be no assurance that APLP Holdings will request one or more incremental term loan facilities nor, if requested, that it will be successful in its syndication efforts or that APLP Holdings will be able to enter into any such incremental term loan facilities.

A copy of the Company’s press release is attached as Exhibit 99.1 hereto and  is incorporated by reference herein.

Certain Information Provided to Prospective Lenders

Certain information that will be provided to prospective lenders in connection with the launch of the syndication of the Credit Facilities is attached as Exhibit 99.2 hereto and is incorporated by reference herein. The information in Exhibit 99.2 should be read in conjunction with the information contained in the Company’s filings under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

The information in this Item 7.01, including Exhibits 99.1 and 99.2, is being furnished and shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liability of that Section, nor shall such information be deemed to be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as otherwise stated in that filing.

Item 9.01.                                        Financial Statements and Exhibits.

(d)  Exhibits

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

EXHIBIT INDEX

Exhibit 99.1

Atlantic Power Corporation Announces Launch of Syndication of New Senior Secured Credit Facilities by APLP Holdings Limited Partnership

DEDHAM, MASSACHUSETTS – March 21, 2016 – Atlantic Power Corporation (NYSE: AT) (TSX: ATP) (“Atlantic Power” or the “Company”) announced today the next step in its plan to reshape its balance sheet and further reduce its near--term debt maturities.  The Company intends to refinance the existing term loan and revolving credit facility at its Atlantic Power Limited Partnership (“APLP”) subsidiary.  The new term loan, to be raised by APLP Holdings Limited Partnership (“APLP Holdings”), an intermediate holding company for APLP and a wholly-owned subsidiary of the Company, is expected to be increased in size to up to $700 million, with excess proceeds expected to be utilized for the redemption of the Company’s convertible debentures maturing in 2017 as well as other potential initiatives to reshape the Company’s capital structure (as described below).  The new term loan is expected to have a seven-year maturity (two years later than the maturity of APLP’s existing term loan) and the new revolver a five-year maturity (three years later than the maturity of APLP’s existing revolver).  Following completion of the refinancing, the Company will have no corporate debt maturities prior to 2019.  Although initially this refinancing will not result in a net reduction in debt, debt reduction is expected to occur over time through mandatory amortization of the new term loan and a 50% cash sweep.

Details of this announcement are as follows:

APLP Holdings today launched the syndication of proposed new senior secured credit facilities, comprising up to $700 million in aggregate principal amount of senior secured term loan facilities and up to $210 million in aggregate principal amount of senior secured revolving credit facilities (collectively, the “New Credit Facilities”).  Subject to entry into definitive documentation for the New Credit Facilities, satisfaction of the conditions to closing thereunder and the other matters more fully described below, the Company and its subsidiaries expect to use the New Credit Facilities to:

·                  replace APLP’s existing $210 million senior secured revolving credit facility maturing in February 2018;

·                  fund the prepayment of the APLP senior secured term loan, which had an outstanding principal amount of $473.2 million as of December 31, 2015 and which matures in February 2021;

·                  fund the optional prepayment or redemption of the Company’s outstanding Cdn$67.3 million 6.25% Convertible Unsecured Subordinated Debentures, Series A, maturing in March 2017, and the Company’s outstanding Cdn$75.8 million 5.60% Convertible Unsecured Subordinated Debentures, Series B, maturing in June 2017 (total US$ equivalent $103.4 million as of December 31, 2015);

·                  provide for ongoing working capital needs of the Company and of APLP Holdings and its subsidiaries;

·                  support APLP Holdings’ and its subsidiaries’ collateral support obligations to contract counterparties;

·                  provide for general corporate purposes of APLP Holdings and its subsidiaries;

·                  fund a debt service reserve for the new revolving credit facility;

·                  pay transaction costs and expenses; and

·                  (upon closing) make a distribution to the Company from remaining proceeds of the term loan, which the Company may use for any corporate purpose, including, at the discretion of the Company, repurchase of convertible debentures maturing in 2019 and repurchase of preferred and common equity.

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Subject to and concurrent with the close of this transaction, two other subsidiaries of the Company – Atlantic Power Transmission, Inc. (“APT”) and Atlantic Power Generation, Inc. (“APG”) – will be contributed to APLP Holdings.  Five of the six power generating assets owned by APT and APG will be added to the existing borrower’s collateral package of 17 power generating assets.  The collateral package for the New Credit Facilities will thus consist of a first lien on 16 of the 17 APLP projects, a pledge of the Company’s equity interest in the remaining APLP project, and a pledge of the Company’s equity interests in the five contributed projects at APT and APG.  In addition, the Company will provide a downstream guarantee of the New Credit Facilities.

APLP’s existing Cdn$210 million aggregate principal amount of 5.95% Senior Unsecured Medium Term Notes maturing in June 2036 (the “MTNs”) prohibit APLP (subject to certain exceptions) from granting liens over any of its assets (and those of its material subsidiaries) to secure any indebtedness, unless the MTNs are secured equally and ratably with such other indebtedness.  Accordingly, in connection with the execution of the New Credit Facilities, APLP will grant an equal and ratable security interest in the collateral package securing the New Credit Facilities in favor of the trustee for the benefit of the holders of the MTNs.

The closing of the New Credit Facilities is subject to syndication, the conclusion of negotiations, execution of definitive documentation, receipt of requisite approvals and satisfaction of customary closing conditions.  There can be no assurance that APLP Holdings will be successful in its syndication efforts or that APLP Holdings will be able to enter into the New Credit Facilities.

The Company has appointed Goldman Sachs Lending Partners LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated as joint bookrunners for the New Credit Facilities.

For a summary of the anticipated terms of the New Credit Facilities, please see the Company’s Current Report on Form 8-K dated March 21, 2016 filed with the Securities and Exchange Commission.

About Atlantic Power

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

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

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

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

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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

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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 successful syndication, negotiation (including the definitive terms of relevant covenants) and execution of the New Credit Facilities;

·                  the Company’s general expectations regarding the use of proceeds;

·                  the Company’s expectations regarding corporate debt maturities following entry into the New Credit Facilities; and

·                  the Company’s expectations regarding the impact of the New Credit Facilities on debt reduction efforts.

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.  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.

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Exhibit 99.2

Certain Information to be Provided to Prospective Lenders

in Connection with the Launch of Syndication of the Credit Facilities

On March 21, 2016, APLP Holdings Limited Partnership (“APLP Holdings”), a wholly-owned direct and indirect subsidiary of Atlantic Power Corporation (the “Company”), launched the syndication of new senior credit facilities (the “Credit Facilities”).  The following includes certain information that will be provided to prospective lenders in connection with the launch of the syndication of the Credit Facilities. Such information includes, among other things, information about the terms of certain contracts, including power purchase and supply agreements, to which APLP Holdings and its subsidiaries are parties.  Prospective lenders are being provided with such information because those contracts may form part of the collateral security package for, and otherwise be important to, the repayment of the loans to be made under the Credit Facilities.  No assurance can be provided that APLP Holdings will be successful in the syndication of the Credit Facilities or that APLP Holdings will be able to enter into and close the Credit Facilities, or if APLP Holdings is able to enter into the Credit Facilities, the timing of closing of the Credit Facilities.  The information in this Exhibit 99.2 should be read in conjunction with the information contained in the Company’s filings under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  Unless otherwise stated, dollar amounts are presented in U.S. dollars.

Certain financial measures used herein, including EBITDA, are not measures recognized under generally accepted accounting principles in the United States (“GAAP”) and do not have standardized meanings prescribed by GAAP. As used herein, EBITDA has the same meaning as Project Adjusted EBITDA as disclosed by the Company in its filings under the Exchange Act with the Securities and Exchange Commission.  The Company defines Project Adjusted EBITDA as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. The following information contains EBITDA based on numbers presented in accordance with GAAP.  Management believes that such measures are relevant supplemental measures of the Company’s ability to earn and distribute cash returns to investors.  The Company has not reconciled non-GAAP financial measures relating to individual projects or the APLP Holdings projects to the directly comparable GAAP measures due to the difficulty in making the relevant adjustments on an individual project basis.  The Company has not reconciled 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.

The Credit Facilities

The Credit Facilities are expected to comprise of up to $700 million in aggregate principal amount of senior secured term loan facilities (the “Term Loan Facility”) and up to $210 million in aggregate principal amount of senior secured revolving credit facilities (the “Revolving Credit Facility”).  The Term Loan Facility is expected to have a seven-year tenor.  The Revolving Credit Facility is expected to have a five-year tenor.

The Credit Facilities are expected to include a traditional project finance-style cash use waterfall and a sweep of 50% of excess cash flows; however, no assurance can be given that any cash flows will, in fact, be realized.  Assuming a sweep of 50% of excess cash flows and mandatory amortization, APLP Holdings is forecasted to repay more than 65% of the outstanding principal of the proposed term loans available under the Credit Facilities by maturity, leaving an unpaid amount of approximately $223 million ($155/kW) at maturity. The Company projects an average debt service coverage ratio (which is defined as cash available for debt service divided by the sum of mandatory debt amortization and interest expense) of 3.3x with respect to the loans under the Credit Facilities.

The creditors under the Credit Facilities are expected to have a security interest in substantially all assets of APLP Holdings, other than Cadillac, Chambers, Frederickson, Koma Kulshan, Orlando and Selkirk, and are expected to have mortgages over the real property of all of APLP Holdings’ projects, other than Cadillac, Chambers, Frederickson, Koma Kulshan, Naval Station, Naval Training Center, North Island, Orlando and Selkirk. The creditors under the Credit Facilities are expected to have a pledge on the equity of the following projects: Cadillac, Chambers, Frederickson, Koma Kulshan, Orlando and Selkirk.

The Piedmont facility will be excluded from the collateral package and will not provide a pledge of equity/ assets.

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The following table reflects the estimated sources and uses of funds from the Credit Facilities, and may vary at closing of the Credit Facilities (in millions).

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The following table reflects the pro forma capitalization of APLP Holdings as a result of the Credit Facilities and the Restructuring, as defined below (in millions).

Note: CAD debt balances calculated to $USD assuming the 10-year average forward exchange rate of $0.76 CAD / USD.

Note: Capitalization shown excludes $94.8 million of 4.85% preferred shares, $44.3 million of 5.57% preferred shares and $31.5 million of 5.09% preferred shares.

(1) Represents proportionally consolidated project-level debt at Cadillac (100%), Chambers (40%) and Epsilon Power Partners based on APC’s ownership interest as of 31-Dec-2015.

(2) Term Loan balance represents 2015 year-end balance and excludes cash sweep expected to occur on March 31, 2016, the amount of which is to be determined.

2016E APC Corporate EBITDA based on mid-point of Management’s guidance for FY2016.

Restructuring

Subject to and concurrent with the close of this transaction, two other indirect, wholly-owned subsidiaries of the Company – Atlantic Power Transmission, Inc. (“APT”) and Atlantic Power Generation, Inc. (“APG”) – will be contributed to APLP Holdings (the “Restructuring”).  Five of the six power generating assets owned by APT and APG will be added to the existing borrower’s collateral package of 17 power generating assets.  The collateral package for the Credit Facilities will thus consist of a first lien on 16 of the 17 APLP projects, a pledge of the Company’s equity interest in the remaining APLP project, and a pledge of the Company’s equity interests in the five contributed projects at APT and APG.  In addition, the Company will provide a downstream guarantee of the Credit Facilities.

APLP Holdings Limited Partnership

The following description of APLP Holdings and its Projects is presented on a pro forma basis to reflect the Restructuring.

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APLP Holdings, a wholly-owned direct and indirect subsidiary of the Company, operates a well-diversified portfolio of assets in the United States and Canada. APLP Holdings’ 23 operating projects are: Cadillac, Chambers, Kenilworth, Curtis Palmer, Selkirk, Calstock, Kapuskasing, Nipigon, North Bay, Tunis, Orlando, Morris, Mamquam, Moresby Lake, Williams Lake , Frederickson, Koma Kulshan, Naval Station, Naval Training Center, North Island, Oxnard, Manchief, and Piedmont. The Piedmont facility will be excluded from the collateral package and will not provide a pledge of equity/ assets. Additional information with respect to each of these projects is provided in the Company’s periodic reports filed with the Securities and Exchange Commission.

APLP Holdings’ contracts for its assets included in the collateral package are expected to have a remaining weighted average life of 7.7 years based on 2016E EBITDA. APLP Holdings’ power generation projects included in the collateral package total 1,446 MW of net generating capacity. The portfolio consists of interests in 22 operational power generation projects across 8 states in the United States and 2 provinces in Canada. These assets consist of 14 natural gas-fired generation facilities, 4 hydroelectric generation facilities, 3 biomass facilities, and one coal-burning facility.

The following table includes the percent of average projected contracted EBITDA attributable to each of APLP Holdings’ top ten largest counterparties. 90.7% of APLP Holdings’ 2015A EBITDA for the projects included in the collateral package is generated by the top 10 (of the 17 total) individual counterparties, with no single counterparty accounting for more than 22% of average annual projected EBITDA.

Agency ratings are subject to change, and there can be no assurance that a ratings agency will continue to rate our customers, and/or maintain their current ratings. A security rating may be subject to revision or withdrawal at any time by the rating agency, and each rating should be evaluated independently of any other rating. We cannot predict the effect that a change in the ratings of the customers will have on their liquidity or their ability to pay their debts or other obligations.

The financial outlook information provided above is subject to numerous risks and uncertainties.  This information should not be read as guarantees of future performance or results and the Company cannot provide any assurances

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regarding whether or not, or at the times at, or by which, such future performance or results will be achieved.  See “Cautionary Note Regarding Forward-Looking Statements” included herein and under the sections entitled “Forward-Looking Information” and “Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.

The following table represents the capacity weighted average availability factor for the APLP Holdings projects.

Capacity-Weighted Average Fleet-Wide Availability Factor

Post-PPA Prospects

Prospective lenders were provided with the following updates regarding certain markets in which the Power Purchase Agreements (“PPAs”) at certain APLP Holdings facilities will need to be recontracted.  The information provided herein relates only to certain of the Company’s projects and markets in which the Company operates, and does not address other projects owned by the Company and markets in which such projects are located.  Such other projects and markets may be experiencing conditions different, and in some cases, more adverse, than those described herein.  This information should be read in conjunction with the information provided in the Company’s filings under the Exchange Act with respect to the Company’s projects and the markets in which the Company operates.

The following description of APLP Holdings and its Projects is presented on a pro forma basis to reflect the Restructuring.

With a geographic footprint spanning 10 power markets across 8 US states and 2 Canadian provinces, APLP Holdings’ portfolio is exposed to a diversity of market fundamentals and unique supply-demand dynamics. As such, as APLP Holdings’ assets approach PPA maturity, the Company expects the portfolio to benefit from a diversity of merchant market fundamentals which ultimately shape recontracting economics, with recontracting prospects not reliant on a single market, counterparty or timeframe.

The cash flows of APLP Holdings’ projects are projected to provide approximately $1.0 billion of Cash Flow Available for Debt Service (“CFADS”) through maturity and are diversified across highly-rated counterparties.

APLP Holdings’ portfolio is diversified across fuel types (75% gas; 10% biomass; 8% hydro; 7% coal), generating technologies, counterparties, and power markets. APLP Holdings’ assets have consistently delivered strong operational performance and maintained a high fleetwide availability factor of approximately 93-96% over the past five years.

1,210 MW (86%) of the 1,446 MW net generating capacity of APLP Holdings’ Projects included in the collateral package is contracted through 2017 while 802 MW  expires before 2022. However, 373 MW (47%) of this capacity is expected to be recontracted based on discussions with counterparties. Refinancing risk is mitigated by the fact that approximately 1.9 billion of contracted revenues are to occur after 2022 and post the maturity of the Credit Facilities. The Curtis Palmer PPA, for example, is expected to expire in March 2025 (max 2027) and provided approximately 15% of 2015A EBITDA. The Curtis Palmer PPA expires at the earlier of 2027 or 10,000 GWh of generation (expected Mar-2025).

The 802 MW of PPAs expiring before 2022 are comprised of the following: (1) 66 MW relate to the Williams Lake biomass facility which is one of the lowest-cost thermal power generation facilities in its market; (2) 114 MW relate to gas-fired assets in California where the inherent permitting difficulties for new-build facilities plus the shutdown of the San Onofre Nuclear Generating Station are expected to generate demand for baseload / intermediate dependable generation capacity (California has also implemented greenhouse gas regulation that offtaker San Diego Gas & Electric (“SDG&E”) must comply with, and SDG&E can make significant progress towards regulation compliance if it recontracts with the three San Diego assets (Naval Station, Naval Training Center, and North Island)

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for which recontracting proposals have been submitted); (3) 29 MW relate to Kenilworth, a gas-fired facility co-located at Merck, Sharme & Dohme Corp.’s (“Merck”) recently relocated global headquarters in New Jersey, which is PJM’s most capacity constrained zone and offers premium payments and what the Company expects to be strong energy margin prospects.

Lastly, the Company believes Tunis (40 MW), North Bay (40 MW) and Kapuskasing (40 MW) facilities to be strategically located adjacent to compressor stations on TransCanada Corporation’s  (“TransCanada”) Northern Ontario Pipeline (“Northern Ontario Pipeline”), which allows the facilities to benefit from waste heat power generation. Tunis, whose PPA originally matured in December 2014, will operate under a 15-year agreement with the Independent Electricity System Operator (the “IESO”) commencing between November 2017 and June 2019, subject to meeting certain technical modifications. TransCanada has publicly announced its intent to move forward with the $12 billion Energy East Project which entails converting one of the natural gas transportation pipelines that are part of the Canadian Mainline into an oil transportation pipeline. The Northern Ontario Pipeline is targeted as one of the key elements of this conversion. Depending on the final selection of route and equipment chosen, the Company believes this may positively impact the regional electricity requirements as new pumping equipment is introduced to transport the oil.

Atlantic Power has viewed the potential recontracting ability of the following plants to be low in the current market environment: Calstock, Kapuskasing, Kenilworth Manchief, Nipigon, North Bay, Orlando and Oxnard.

Curtis Palmer

Hydroelectric generation is one of the most cost effective and environmentally friendly generation technologies. Curtis Palmer was originally constructed in 1913 and has consistently been recontracted by local utilities. Given the long-lived nature of hydro assets and low variable costs of producing power, the Company believes that Curtis Palmer is well positioned to renew its PPA at attractive terms or to participate in the New York merchant market. In addition, hydroelectric power is an important component of New York’s fuel mix, particularly because it contributes to the state’s RPS requirements.

Frederickson

The Company believes that significant value exists at the Frederickson facility beyond the expiry of its PPAs in 2022 as the asset is expected to have a useful life in excess of 40 years. The Northwest Power Pool Corporation (“NWPP”) is heavily reliant on intermittent generation resources (68% hydro and wind capacity) with limited gas fired generation. Increased volatility from intermittent generation and recovering load growth has caused several local utilities to recognize the need for responsive and flexible gas-fired units to support system reliability. As these dynamics develop, the Company believes efficient combined-cycle gas turbine (“CCGT”) facilities such as Frederickson are well-positioned to take advantage of future recontracting opportunities. Finally, the Company believes Frederickson is strategically located from a transmission perspective to meet the load requirements of Puget Sound Energy Inc. (“PSE”), Atlantic Power’s co-owner in the facility.

Kenilworth

Discussions have been held with Merck about a new contract or an extension of the current contract at Kenilworth. Both sides have agreed that the best alternative would be either a replacement or repowering of the existing facility with a new, more efficient, more reliable facility. Atlantic Power is currently analyzing the feasibility of building a new larger unit on the site. Alternatively, there could be an extension of the current contract with improvements to the current equipment. The Company believes there is uncertainty surrounding the recontracting ability of this plant in the current market environment.

Mamquam

With an expected useful life in excess of 75 years, the Company believes Mamquam possesses substantial economic value beyond the expiry of its Electricity Purchase Agreement (“EPA”) in 2027 and offers a favorable recontracting outlook. As a result of the facility’s strategic location in the lower mainland load center of British Columbia and its

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low cost operating profile, the Company believes Mamquam is a critical power generation resource to British Columbia Hydro & Power Authority (“BC Hydro”).

Moresby Lake

With an expected useful life in excess of 75 years, the Company believes Moresby Lake possesses substantial economic value beyond the expiry of its EPA in 2022 and offers a favorable recontracting outlook. As a result of the cost competitiveness of the hydroelectric facility and its strategic location in the Haida Gwaii Islands, the Company believes Moresby Lake serves a critical role in its local market.

The South Haida Gwaii Islands’ grid is not physically connected to the main BC Hydro grid, thereby requiring the Island to remain self-sufficient for its generation supply. As such, the region is reliant upon local generation facilities such as the Moresby Lake facility as well as substantial diesel-fired capacity. In fact, the facility is the only non-diesel generation facility serving the South Haida Gwaii Islands’ grid and it is anticipated that diesel generation will be phased out over time, thereby increasing reliance on hydroelectric and wind generation. As such, the Company believes the Moresby Lake facility will continue to play an important role as part of the local electricity supply. Finally, the facility has the support of the Haida Gwaii First Nations.

Naval Station, Naval Training Center and North Island

While Atlantic Power’s agreements with the U.S. Navy at the Naval Station facility, Naval Training Center and North Island expire in February 2018, Atlantic Power has initiated discussions to extend the tenor of these agreements.

In 2010, the three major utilities in California reached a settlement with combined heat and power producers (the “CHP Settlement”) that established goals for contracting with existing and/or new CHP, including conversion of existing CHP to utility prescheduled facilities (“UPF”), under dispatchable tolling contracts. The CPUC established goals for each utility, in terms of MW’s and for the resulting GHG reduction amounts. SDG&E has approximately 100 MW remaining to reach its MW goal and has achieved very little of its GHG goal. SDG&E published a request for CHP offers (“CHP RFO”) on July 24, 2015 and Applied Energy (“AE”) submitted proposals prior to the due date of August 31, 2015 for all three of its San Diego facilities to convert to UPF. The facilities not selected in the July 24, 2015 RFO will be re-proposed in an RFO that was issued on February 19, 2016 and responses to which are due April 24, 2016.  In the CHP RFO, SDG&E stated a preference for resources that contribute SDG&E’s local capacity requirement (“LCR”). Other than the AE facilities, there are very few CHP in San Diego that could provide LCR that have not converted already to UPF. Also, due to the high historical capacity factors of AE’s facilities, the GHG reduction achieved is maximized when converted to UPF and dispatched less. Recontracting with the three AE facilities would allow SDG&E to meet its MW goal and to achieve approximately one third of its GHG goal.

The Company cannot provide any assurances that these discussions will be successful, nor the terms upon which such agreements will be executed, if any.

Williams Lake

Atlantic Power has been in discussions with BC Hydro for approximately 12 months with respect to Williams Lake. BC Hydro has indicated they would not exercise the option to extend under the terms as provided in the EPA, but has engaged in bilateral negotiations of alternative extension terms. The negotiating teams have reached agreement on a term sheet that lays out the commercial terms of a 10-year extension. BC Hydro has received senior management and Board approval of the extension but is seeking further price concessions. BCH has commissioned an independent review of capital and operations and maintenance cost projections used in establishing pricing for the extension period. The parties continue to negotiate and execution of an amendment providing the 10-year extension is targeted for Q3 2016. The Company cannot provide any assurances that the extension agreement will be executed and implemented, nor the terms upon which such extension agreement will be executed, if at all.

These PPA recontracting prospects are subject to numerous risks and uncertainties.  See “Cautionary Note Regarding Forward-Looking Statements” included herein and under the sections entitled “Forward-Looking Information” and “Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.  The Company cannot provide any assurances regarding whether it will be successful in recontracting these, or any of its PPAs, on economically favorable terms or at all.

Major Overhauls

Prospective lenders were provided with the following updates regarding major overhauls at certain APLP Holdings’ facilities. The information provided herein relates only to certain of the Company’s projects.  Such other projects may be experiencing conditions different than those described herein.  This information should be read in conjunction with the information provided in the Company’s filings under the Exchange Act with respect to the Company’s projects in which the Company operates.

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The below descriptions summarize certain information related to major overhauls at APLP Holdings’ projects on a pro forma basis.

Cadillac

As part of the Company’s scheduled maintenance program, Atlantic Power completed a major overhaul of Cadillac’s steam turbine, generator and stoker grate in early 2014. As is typical for biomass facilities, Atlantic Power maintains an eight to ten year major overhaul schedule.

Calstock

Major overhauls on the once through heat recovery steam generator (“OTSG”) and associated equipment are completed at the Calstock facility approximately every 5 to 10 years and are condition-based. The most recent overhaul took place in 2012 when the steam turbine and generator were overhauled. The next major overhaul is expected to occur in 2022.

Chambers

Chambers is on an approximately 5-year major maintenance schedule. 2014 and 2015 major maintenance included boiler overhauls, maintenance on the cooling tower, turbine and turbine valves overhaul, as well as a generator overhaul. Chambers will also undergo feedwater heater maintenance in 2015.

Asset management services are provided pursuant to a Management Services Agreement between Power Plant Management Services, LLC (“PPMS”) and Chambers. PPMS is paid a base annual fee and a fee for services on a cost reimbursable basis and is eligible for management performance bonuses and incentive fees. Operations and maintenance services are provided by NAES Corporation (“NAES”) pursuant to an O&M Services agreement. NAES is paid a base annual fee and a fee for services on a cost reimbursable basis and is eligible for management performance bonuses and incentive fees.

Curtis Palmer

All seven of the generating units are inspected annually. The Palmer and Curtis units undergo major overhauls approximately every ten and twenty-five years, respectively. The next scheduled overhauls are for Curtis 1 (2020) and Curtis 2 (2040). Curtis 4’s replacement was completed in 2013 and Curtis 5 was completed in 2014. The new Toshiba units at Palmer 1 and Palmer 2 will be overhauled in 2018 and 2019, respectively.

Frederickson

Hot section refurbishments and turbine overhauls at the Frederickson facility are performed every 25,000 factored fired hours for hot section refurbishments on the gas turbines and approximately every 50,000 factored fired hours for turbine overhauls. As the Frederickson facility is normally dispatched only during periods of peak power demand or low hydroelectric product, it operates under reduced operating hours each year, which consequently increases the timing interval between major overhauls. Inspections are performed at the plant on a more regular basis. The most recent overhaul took place in 2009 and consisted of a hot gas path section inspections on the gas turbine and inspection of the steam turbine. The next major overhaul is planned for 2017.

Kapuskasing

Major overhauls at the Kapuskasing facility are performed approximately every 25,000 operating hours or roughly every three years for hot section refurbishments on the gas turbines and approximately 50,000 operating hours or every six years for the entire turbine overhauls, including the power turbine. A spare power turbine and gas turbine are owned and shared between the Kapuskasing and North Bay facilities and costs of all scheduled overhauls on the spare turbines from either site are shared with both. It is expected that the heat recovery steam generators will require re-tubing, or at a minimum header and some tube replacements, approximately once every 20 years. The header on the fired OTSG1 unit in Kapuskasing was replaced in March 2013. The most recent steam turbine generator (“STG”)  overhaul took place in 2007 and consisted of an overhaul and repair of the steam turbine and both the gas turbine and steam turbine generator. A power turbine overhaul is planned for 2016.

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Kenilworth

Major overhauls at the Kenilworth facility are performed approximately every 25,000 operating hours or roughly every three years for hot section refurbishments on the gas turbines and approximately 50,000 operating hours or every six years for turbine overhauls. A hot section overhaul is scheduled for 2016, and was last performed in 2011.

Koma Kulshan

Major overhauls are completed approximately every ten years and are based on the condition of the facility. The last major overhaul was completed in 2013.

Mamquam

Major overhauls are completed at Mamquam approximately every ten years and are based on the condition of the facility. Atlantic Power performed the last overhaul on one of the turbines in 2014. The Company performed a tunnel inspection and recoating in 2015, and consequently does not anticipate another tunnel inspection for ten years.

Manchief

Hot section refurbishments and major inspections at the Manchief facility are performed every 25,000 equivalent operating hours. The plant has historically operated 1,700 hours per year. The most recent overhaul took place in the spring of 2015, with the next major overhaul expected in 2017.

Moresby Lake

Major overhauls are completed at the Moresby Lake facility approximately every 10 to 15 years and are based on the condition of the facility. The most recent overhaul took place in 2014 with the replacement of Generators 1 and 3. The next major maintenance is planned for 2018, with replacement of all runners.

Morris

Hot section refurbishments on the gas turbines are performed approximately every 25,000 equivalent operating hours or roughly every four years and major gas turbine overhauls are performed approximately 50,000 equivalent operating hours or every eight years. Two major CT overhauls and a steam turbine overhaul are scheduled for 2016.

Naval Station Facility

Major overhauls at the Naval Facilities are performed on a regular basis. The most recent complete overhaul for the Naval Station facility took place in November 2012. Further, in the same month a generator inspection occurred. The hot gas path inspection occurred in February 2016. The next major turbine overhauls are scheduled for 2018. In 2019, the frame unit rotator is scheduled for replacement.

Naval Training Center Facility

Major overhauls at the Naval Facilities are performed on a regular basis. The most recent overhaul for the Naval Training Center facility took place in 2013 and consisted of the installation of the extended life hot section and power turbine. The next maintenance event, scheduled for 2018, will include both gas turbine overhaul and hot gas path inspection.

Nipigon

Major overhauls at the Nipigon facility are performed approximately every 50,000 operating hours for hot section refurbishments on the gas turbines and approximately 50,000 operating hours or every six years for the entire turbine overhauls. Steam turbine and generator overhauls are expected to occur on 10 year intervals. The gas turbine was overhauled and had an extended life hot section installed in mid-2013 and a new OTSG with duct burners was installed in 2014 to replace the smaller, aging unit. An overhaul of the gas turbine and generator is next scheduled for 2018. The steam turbine is expected to be next overhauled in 2019.

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North Bay

Major overhauls at North Bay are performed approximately every 25,000 operating hours or roughly every three years for hot section refurbishments on the gas turbines and approximately 50,000 operating hours or every six years for the entire turbine overhauls, including the power turbine. A spare power turbine and gas turbine are owned and shared between the Kapuskasing and North Bay facilities and costs of all scheduled overhauls on the gas generators (“GG”) and power turbines (“PT”) are shared. The most recent STG overhaul took place in May 2008 and consisted of an overhaul and repair of the steam turbine and both the gas turbine and steam turbine generator. A gas turbine overhaul occurred in 2015 and a power turbine overhaul occurred in 2014.

North Island

Major overhauls at the Naval Facilities are performed on a regular basis. An overhaul of the gas turbine occurred in 2014. The unit has been performing as expected. An overhaul of the steam turbines is scheduled for 2016, and the next hot gas inspection is expected to occur in 2019.

Orlando

The Orlando facility operates on a three year maintenance cycle. The upcoming inspection cycle includes B inspection GT in 2016 and C inspection GT and major inspection STG in 2017.

Oxnard

Gas turbine hot section refurbishments are performed every 25,000 operating hours and turbine overhauls are performed every 50,000 operating hours. As the Oxnard facility is normally dispatched only during periods of peak power demand, it operates under reduced operating hours each year, which consequently increases the timing interval between major overhauls; however, inspections are performed at the plant on a more regular basis. The most recent overhaul took place in 2010 as part of a turbine replacement. An overhaul, including a hot section repair, is next scheduled for 2016.

Selkirk

The gas turbines are typically overhauled every 48,000 operating hours, approximately every ten years. Major maintenance on turbine 1 is scheduled for 2018. Combustion inspection is scheduled every three to four years (12,000 hours) and hot gas path inspection every five years (24,000 hours). The steam turbines are also typically overhauled every 48,000 operating hours.

Tunis

The plant was laid up following a shutdown on January 1, 2015. When the plant is restarted, it will operate in simple cycle; the gas turbine and generator will be overhauled prior to startup and other major maintenance work will also be completed in order to comply with the contract requirements.

Williams Lake

Major overhauls are completed at the Williams Lake facility approximately every five years. The most recent overhaul took place in 2013 with repairs and maintenance performed on the turbine, generator, boiler and cooling tower. The next overhaul is scheduled for 2018.

Power Purchase and Supply Arrangements

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Prospective lenders under the Credit Facilities will receive a range of information about the terms of certain contracts to which APLP Holdings and its subsidiaries are parties, among other things, because those contracts may form part of the collateral security package for, and otherwise be important to, the repayment of the loans to be made under the Credit Facilities.  This includes the information below concerning certain power purchase and supply agreements. This information should be read in conjunction with the information provided in the Company’s filings under the Exchange Act.

The below descriptions summarize certain information related to power purchase and supply arrangements at APLP Holdings’ projects.

Cadillac

Cadillac sells up to 34 MW of its capacity and energy under a PPA with Consumers Energy Company (“Consumers Energy”) which expires in 2028. The PPA includes a capacity payment based on 34 MW of committed capacity, an energy payment based on escalating on and off peak rates as well as a variable energy charge. In 2007, Cadillac entered into a Reduced Dispatch Agreement with Consumers Energy. Under the agreement, the project shares in the economics when Consumers Energy reduces Cadillac’s dispatch level (when replacement power in the wholesale market is less than Cadillac’s variable cost of production). Any excess generation is sold into the Midcontinent Independent System Operator, Inc. (the “MISO”) merchant market when economically attractive.

The project generates Renewable Energy Credits (“RECs”) of which 80% of all RECs are passed on to Consumers Energy under the PPA and 20% are retained by the Company. Cadillac sold its 2014 RECs to FirstEnergy at $1.50 each. Forecasted 2015 through 2018 RECs have been pre-sold to Wisconsin Electric Power Company for a price that escalates over time. In addition, the project benefits from the provisions of Michigan Public Act 286 that allows for certain fuel and variable maintenance costs incurred by biomass plants to be passed through Consumers Energy to Michigan rate payers.

Biomass facilities typically have long useful lives assuming maintenance is performed on an adequate schedule. The ongoing importance of regional forest resources is expected to create a long-lasting and diverse supply of woody waste that will allow the facility to continue being a competitive source of power generation. In addition, Michigan has adopted a Renewable Portfolio Standards (“RPS”) mandate with increasing requirements for renewable power as part of Michigan’s energy resource plan. Atlantic Power also owns the site on which the facility is located, further reinforcing the long-term prospects of the asset.

Cadillac procures biomass from approximately 40 local suppliers, approximately 50% of which have provided fuel to the plant since inception. Atlantic Power categorizes its suppliers into two tiers – Tier 1 containing approximately twelve preferred suppliers and Tier 2 with the remaining, small suppliers. The majority of the fuel is purchased within a 75 mile radius of the project.

The top ten suppliers accounted for more than 70% of total fuel supply, a ratio consistent with historical averages. This diverse mix of suppliers allows Cadillac to procure fuel on a cost effective basis. Cadillac is located in strategic proximity to abundant fuel resources in Michigan. Whole tree chips are approximately 55% of biomass fuel, which are predominantly a by-product of the forest products industry and forest management programs in the State. This includes the tops of trees, limbs, cull trees, logs and unused wood, such as windblown, insect infested and fire damaged wood. The balance consists of sawdust residue (approximately 35%) and recycled wood and grindings (approximately 10%).

Calstock

Electrical output from the Calstock facility is sold to the Ontario Electricity Financial Corporation (“OEFC”) under a PPA that was executed on April 29, 1994 and whose term expires on June 16, 2020. The PPA requires the facility to sell all of its output to the OEFC at contracted electricity rates which are comprised of separate capacity and energy payments that are subject to annual escalation. Under the PPA, the facility must achieve a target average net capacity output of at least 73% to receive its full capacity payment.

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The Calstock facility has historically consumed an average of 230,000 green metric tonnes (“GMT”) per year of wood waste. Approximately 120,000 GMT of the Calstock facility’s wood waste requirement is provided on a contracted basis by several local mills, which are located between 10 to 34 kilometers from the facility. The supply agreements are scheduled to expire in March 2019 which APLP Holdings will seek to extend with the same counterparties after expiration. However, no assurance can be given that APLP will be able to do this on terms that it considers economically attractive or at all. In addition, the Project has access to a wood waste landfill site, located approximately 15 kilometers from the facility that has been used to provide supplemental fuel for the site when the mills were idled in 2011. The remainder of wood waste is procured ad hoc.

Waste heat is an intermittent resource provided to the facility from compressor stations on the TransCanada pipeline. The amount of waste heat received is dependent on gas flows along the pipeline. As a result, waste heat availability is generally seasonal, with the majority provided during the winter months, and total amounts may vary from year to year. APLP Holdings forecasts waste heat by evaluating a combination of historical average availability and TransCanada’s annual projections.

Chambers

Atlantic Power indirectly owns a 40% interest in Chambers, equivalent to 105 MW of generation capacity. The remaining 60% interest is held by Ares Energy Investors Fund Group.

Chambers sells electricity to Atlantic City Electric (“ACE”) under a PPA that expires in March 2024 and a power sales agreement (“PSA”) that is renewed annually unless terminated by either party. Under the PPA, ACE controls dispatch and is able to purchase all deliverable energy from the plant operating at specified minimum dispatch levels for its 184 MW share of capacity. Energy rates are escalated using the Mid Atlantic Coal Price Index. Payments from ACE pursuant to the PPA represented approximately 64% of Chambers’ revenues in 2014. The PPA requires that Chambers maintain a Qualifying Facility (QF”) status, with provisions if QF status is not maintained. This requirement is fulfilled with the DuPont steam arrangement.

The PSA provides that Chambers may, at its discretion, sell and ACE must purchase excess capacity and undispatched PPA energy from the facility. PSA payments include an excess capacity payment based on 70% of the facility’s Reliability Pricing Model Capacity Clearing Price, undispatched PPA energy payments, and excess energy payments. PSA payments from ACE represented approximately 14% of revenues in 2014. A new PSA letter agreement was executed on January 1, 2015.

The facility provides energy and steam to Chemours Co. (“Chemours”), which was spun off from DuPont in July 2015, under a Steam and Electricity Purchase Contract (“SEPA”) previously held by Dupont through March 2024. Chambers is obligated to deliver peak cogenerated steam to DuPont on a continuous and uninterrupted basis in amounts up to 650,000 lb/hour for the months between June – September, 700,000 lb/hour in May and October, and 1,000,000 lb/hour in all other months. It is also obligated to deliver peak electricity on a continuous and uninterrupted basis of up to 40 MW. Chambers supplies all of DuPont Chambers Works’ electricity requirements, which currently average approximately 16 MW. DuPont/Chemours SEPA payments represented approximately 19.8% of Chambers’ total revenues for 2015.  DuPont supplies, at no cost to Chambers, untreated fresh water that is used as makeup water by the facility. In addition, DuPont must take and dispose of, at no cost to Chambers, wastewater from the facility.

Coal facilities of this type traditionally have a useful life in excess of 60 years, implying a useful life through at least 2054. The Chambers facility has long-dated offtake agreements in effect through 2024 for the majority of its output. In addition, the facility has also been selling excess generation into the premium PJM East market.

Chambers currently provides 100% of the DuPont-Chambers Works electricity and the Company expects that DuPont will have ongoing energy requirements well into the future.

Chambers has a coal supply agreement with Consol Energy through December 2019. Fuel supply price exposure is mitigated through Chambers’ PPA and Energy Service Agreement (“ESA”) pass-through structures. If dispatch is greater than expected and contract amounts, Chambers will purchase coal at spot prices.

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Chambers operates under a Title V air permit, which is currently being modified in preparation for renewal. Chambers also holds New Jersey Pollutant Discharge Elimination System (“NJPDES”) permits to discharge to groundwater and to surface water, and it has a Resource Conservation and Recovery Act (“RCRA”) small quantity generator permit. In 2013, Chambers experienced 3 excess air emission incidents and has closed all three with the New Jersey Department of Environmental Protection (“NJDEP”). The facility has been in compliance with its environmental permits with only intermittent emissions excursions and minor violations, all of which have been addressed.

The air pollution control technology employed is compliant with all the permits required to operate the facility and with expected future regulatory requirements of the NJDEP and the Environmental Protection Agency, including the Mercury Air Toxics Standard (“MATS”). Chambers is equipped with a dry scrubber for SO2 control, low NOx burners and selective catalytic reduction for NOx control, and a baghouse for particulate control.

Under the PPA and SEPA, Chambers has limited merchant exposure to the PJM market, however, under the PSA, the project benefits from PJM merchant revenues; in particular given the facility’s location in PSNorth, PJM’s most constrained capacity zone.

Curtis Palmer

All of the electricity produced by Curtis Palmer is sold to Niagara under a PPA that was executed in 1984. The PPA ends on the earlier of December 31, 2027 or the delivery of a cumulative 10,000 GWh of electricity (currently expected March 2025).

The Curtis Palmer PPA sets out 11 different prices for electricity sold to Niagara, with the applicable price to be paid at any given time being dependent upon the cumulative GWh of electricity which have been delivered under the PPA. In December 2008, after having achieved a cumulative GWh threshold of 4,344 GWh, the pricing increased as the plant moved into its next pricing block. Over the remaining term of the PPA, the price increases with each additional 1,000 GWh of electricity delivered. The plant requires approximately three years to move through each 1,000 GWh block, depending upon river flow.

The Curtis Palmer facilities operate under a 40 year water license granted by FERC on April 27, 2000.

Frederickson

Frederickson is currently jointly owned by Atlantic Power (50.15%) and PSE (49.85%).

APLP Holdings’ portion (50.15% or approximately 125 MW) of the Frederickson facility’s gross 250 MW generating capacity is sold under PPAs to three Washington State Power Utility Districts (“PUDs”) (Benton County, Grays Harbor and Franklin County) for a term of 20 years ending in August 2022. Under the PPAs, APLP Holdings provides generating capacity and associated energy to each PUD, and the PUDs pay APLP Holdings: (i) a capacity charge; (ii) a fixed operations and maintenance charge; (iii) a variable operations and maintenance charge; (iv) a fuel charge based on a fixed heat rate; and (v) start charges. APLP Holdings is responsible for any fixed and variable cost increases above those recoverable under the PPAs, other than costs that result from the effects of material changes to environmental and tax laws (subject to certain thresholds).

The facility also has 20 MW (10 MW net to APLP Holdings) of duct-fired capacity which is used intermittently. Duct burner capacity can be used to fulfill the contract capacity requirement when the plant is short due to ambient conditions and / or normal turbine degradation.

Under the PPAs, the PUDs must supply their proportionate share of natural gas to APLP Holdings at Huntington, British Columbia. APLP Holdings guarantees a heat rate and pays for gas needed above the guaranteed heat rate. APLP Holdings is responsible for contracting firm transportation for natural gas from Huntington to the Frederickson facility which is contracted with Northwest Pipeline GP through September 2018, with a bi-lateral evergreen provision extension.

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Kapuskasing

Electrical output from the Kapuskasing facility is sold to the OEFC under a PPA that was executed on February 1, 1994 and whose term expires on December 31, 2017. The PPA is designated as a NUG contract. The PPA requires the facility to sell all of its output to the OEFC at contracted electricity rates which are comprised of separate capacity and energy payments, which are subject to annual escalation. Under the PPA, the OEFC also pays APLP Holdings a fixed gas price adjustment rate to offset its fuel costs. The OEFC may curtail a limited amount of power during off-peak periods under the PPA. The PPA does not restrict the curtailment of power generation for the purposes of gas diversion sales, but does require the facility to achieve a minimum monthly capacity target for on-peak hours to receive a monthly capacity payment.

APLP Holdings has a natural gas supply agreement with TransCanada for a firm quantity of natural gas at a firm price each year. The contract expires in the fourth quarter of 2016. Upon expiry of the gas supply agreement, there is a potential opportunity to optimize gas transportation agreements. APLP Holdings anticipates purchasing gas on a forward basis from the Ontario market upon expiry of the natural gas supply agreement to bridge the gap with the expiry of the PPA. Current forward gas prices for the November 2016 to December 2017 period are substantially below the prices under the existing long term contract.

Waste heat is an intermittent resource provided to the facility from compressor stations on the TransCanada pipeline. The amount of waste heat received is dependent on gas flows along the pipeline. As a result, waste heat availability is generally seasonal, with the majority provided during the winter months, and total amounts may vary from year to year. APLP Holdings forecasts waste heat by evaluating a combination of historical average availability and TransCanada’s annual projections.

Kenilworth

The Kenilworth facility sells electrical energy to Merck, under an Amended and Restated ESA that expires in September 2018 with three extension options for Merck occurring in one year increments. Pursuant to the ESA, Merck pays a fixed capacity price based on plant operating hours and tiered energy rates based on Merck’s energy usage. The energy rates include a fuel passthrough and a fixed dollar per MWh component. The fuel pass through is based on a contractual plant heat rate that escalates by 0.5% annually. The ESA imposes a minimum take or pay obligation on Merck. Incurred fuel expenses are passed through to Merck as part of the contracted rate. Excess generation above the Merck loads are sold to Public Service Enterprise Group Incorporated (“PSE&G”) at current market prices under a contract entered into in 2009.

The Kenilworth facility sells steam to Merck under the amended and restated ESA. The ESA provides for the greater of (i) instantaneous thermal requirement of the Merck facilities, (ii) minimum required for the Kenilworth plant to maintain its QF status, and (iii) 12,000lbs each hour. The steam price is calculated using two tiers - up to 15,000lbs per hour and above 15,000lbs per hour - and is calculated assuming 80% boiler efficiency and a steam enthalpy of 1.1147 mmbtu / KLB. EF Kenilworth, LLC purchases natural gas from J. Aron at the direction of Merck. Fuel costs are passed through to Merck utilizing a heat rate derived formula to determine steam and electricity pricing.

Koma Kulshan

All of the power generated by the facility is sold to PSE pursuant to a PPA that was entered into in 1998 and expires in December 2037. The PPA provides for an energy rate comprised of a capital component and a variable charge component. The base capital component is supplemented by a variable capital component that escalates over time. The variable charge is determined each year, and is comprised of an O&M charge and a tax and insurance charge on a pass-through basis. Property tax and insurance are designed as straight pass-through costs, while other O&M charges are adjusted annually for price inflation.

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The project holds two FERC hydro licenses that both expire in 2037, co-terminal with the PPA. The Koma Kulshan Sulpher Creek license was renewed in April 1987, and the Koma Kulshan Rocky Creek license was renewed in April 1990.

Mamquam

Electricity produced by Mamquam is sold to BC Hydro under an EPA that was executed on August 29, 1990 and ends on September 30, 2027. BC Hydro has an option, exercisable in 2021 and every five years thereafter, to either purchase the Mamquam facility at fair market value or to extend the Mamquam EPA. To date, BC Hydro has not expressed interest in exercising this option. Energy rates payable under the EPA consist of: (i) a fixed energy component (up to certain output thresholds); (ii) an operations and maintenance component (adjusted annually for inflation); and (iii) a reimbursable cost component which covers costs such as property taxes, water and land use fees as well as comprehensive liability insurance costs.

APLP Holdings holds a conditional water license for the Mamquam facility, which was granted on May 26, 1994 and amended on March 31, 1999, that authorizes the diversion of and use of water on the Mamquam River. The water license has no expiration date and allows for a maximum diversion of 23.45 Cubic meters per second (“cms”) year-round for a power plant with 50 MW of authorized capacity. Under the water license, the Mamquam facility incurs a water rental charge, which is reimbursed by BC Hydro under the terms of the EPA.

In July 2007, a short term license for 6.55 cms of additional water diversion was issued to increase the maximum total diversion to 30.0 cms. This additional license was made permanent on March 5, 2009 for a period of 40 years.

Manchief

The Manchief power plant operates under an ESA with Public Service Company of Colorado (“PSCo”) that expires in 2022 pursuant to a 10-year extension agreed to in 2006. Under the ESA, PSCo purchases: (i) the electricity capacity consisting of 300 MW of net generating capacity per hour, or the actual net generating capacity that is available in any given hour, whichever is less; and (ii) the electrical energy which is actually dispatched by PSCo and associated with such capacity. In accordance with the ESA, Manchief is paid capacity and energy payments. Capacity payments are made on a monthly basis, regardless of whether the plant is actually dispatched by PSCo.  Energy payments are also made on a monthly basis and are comprised of tolling fees, start-up fees, dispatch payments, heat rate adjustment payments (payable either to or by Manchief) and natural gas transportation charges.

APLP Holdings and PSCo have signed an Option Agreement under which PSCo has the right to acquire the Manchief facility, which may be exercised in May 2020 or May 2021.

The Manchief facility runs under a tolling arrangement in place through the ESA with PSCo. PSCo has customarily arranged for all fuel gas commodity and interstate transportation for the full dispatched output, even though the ESA calls for Manchief to provide and manage the fuel gas for the incremental energy delivered out of Manchief and then seek reimbursement for those costs from PSCo.

APLP Holdings is party to an O&M Services Agreement with Colorado Energy Management, LLC (“CEM”), who provides all aspects of O&M for the Manchief facility. CEM has been the operator of the Manchief facility since it commenced commercial operations. The agreement was executed in July 2007. The contract will renew annually unless notice is provided to terminate the contract. The agreement includes fuel scheduling and management services.

Moresby Lake

Substantially all of the electricity produced by the Moresby Lake facility is sold to BC Hydro under an EPA that was executed on December 9, 1988 and is scheduled to expire on August 31, 2022. Energy rates payable under the EPA consist of: (i) a fixed energy component (up to certain output thresholds); (ii) an operations and maintenance component (adjusted annually for inflation); and (iii) a reimbursable cost component. The balance of power generated by the facility (approximately 1%) is sold to NAV Canada under a PPA executed in July 2010. The PPA is coterminous with the EPA and expires in August 2022.

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APLP Holdings holds two conditional water licenses (#67528 and #67529) for the Moresby Lake facility which were granted on September 8, 1987. Water license #67528 representing 5.6 MW of capacity authorizes a maximum storage of 16,200 acre-feet/year on Moresby Lake and a maximum diversion of 300 cfs (no flow restrictions). Works that are authorized include the dam, reservoir, intake, tunnel, penstock, powerhouse, tailrace, access road and transmission line to Sandspit. Water license #67529, representing 0.4 MW of capacity, authorizes a maximum diversion of 16 cfs (no flow restrictions). Works that are authorized include the intake, pipe, powerhouse, trailrace and valve to permit water to be directed to a spawning channel.

Morris

Morris sells electrical energy to Equistar Chemicals, LP (“Equistar”) under an ESA that expires in 2034. Pursuant to the ESA, the facility earns capacity and energy payments from Equistar based on a maximum capacity of 77 MW. On average Equistar takes approximately 50 MW. The capacity rate is fixed and escalates at materials and labor indices. Energy payments are based on electricity and steam delivered and tiered rates which are adjusted monthly for natural gas prices. Under the energy payment formula, a small portion of energy costs are not recovered through the energy payments. This non-recoverable amount fluctuates with the price of natural gas. Equistar has a right to purchase the Morris facility at fair market value at the end of 2013, 2018 and 2023. Equistar did not exercise this right at the end of 2013.

Morris currently sells 107 MW of energy capacity, and ancillary services, into the PJM market. The plant’s PJM capacity rating has been approved to increase from 107 MW to 120 MW in June 2017 and to 135 MW for the Base Residual Auction (“BRA”) in June 2018. The facility also sells ancillary services to the market, such as regulation.

Morris sells steam to Equistar up to a maximum of 720 mmlbs / hour under its ESA through 2023. Normal usage is approximately 320 mmlbs / hour. The ESA charge for steam is calculated on the basis of a tiered pricing schedule depending on quantity of average monthly steam demand. The agreement provides for the option to renegotiate pricing if steam demand falls outside a set range for a stipulated period of time.

Morris procures the majority of its required fuel with J. Aron at a price indexed to Chicago City Gate. Gas transportation is contracted with Nicor Gas Company through the term of the ESA, the cost of which is passed through to LyondellBasell. Additionally, J. Aron manages the facility’s gas storage, associated with its gas transportation agreement, as a seasonal hedge, maximizing operational efficiency. The new agreements will be reviewed on an annual basis.

Naval Station Facility, Naval Training Center Facility and North Island

Electrical output from the Naval Station facility is sold to SDG&E under the Standard Offer 4 (“SO4”) PPA, with SDG&E purchasing energy at the Short Run Avoided Costs (“SRAC”) rate. Under the SO4 PPA, substantially all of the electricity produced by the Naval Training Center facility is sold to SDG&E. The remaining electricity, which is produced by the facility’s 2.5 MW steam turbine, is sold to SDG&E under the Standard Offer No. 1 for Power Purchase and Interconnection from Qualifying Facilities.

All of North Island’s electrical output, with the exception of 4 MW, is sold to SDG&E under the SO4 PPA, under which SDG&E purchases energy prices at the SRAC rate and compensates the facility for capacity. All of the output from the remaining 4 MW of capacity, which is generated from the facility’s steam turbine, is sold to the U.S. Navy at a discount to SDG&E’s retail rates.

The repowered gas turbine at the North Island facility can generate an additional 2 MW of power that is currently being delivered to the SDG&E grid.

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Fuel is purchased at the Naval Station facility, the Naval Training Center facility and North Island on a monthly basis with a month-end true-up. Noble Energy is the purchasing agent. 

The agreement was recently renegotiated to optimize working capital.

Steam generated from the Naval Station facility, the Naval Training Center facility and North Island is sold to the U.S. Navy pursuant to the Negotiated Utility Style Service (“NUSC”), with the Navy assuming fuel risk via pass-through mechanisms under the contract. In addition to providing the facility with a steam host, the U.S. Navy also leases land to the facility.

Nipigon

Electrical output from the Nipigon facility is sold under a PPA that was executed on April 25, 1990 and was set to expire on December 31, 2012; however, Atlantic Power exercised its extension option and the PPA is now set to expire on December 31, 2022. The PPA requires the facility to sell all of its output at contracted electricity rates which are comprised of separate capacity and energy payments, each subject to annual escalation.

Atlantic Power executed a 10-year fixed price gas supply agreement with BP through December 2022, co-terminus with the PPA’s expiry.

Waste heat is an intermittent resource provided to the facility from compressor stations on the TransCanada pipeline. The amount of waste heat received is dependent on gas flows along the pipeline. A new OTSG with duct burners was installed in 2014 to replace the smaller, aging unit. Several improvements were realized as the result of the new OTSG such as unfired boiler efficiency improvements, greater steam turbine generation as a result of greater boiler steam output from the new duct burners and an additional optimization project which consisted of adding a feedwater booster pump and an HP/LP letdown station which was completed in August 2015.

North Bay

Electrical output from the North Bay facility is sold to the OEFC under a PPA that was executed in February 1994 and expires in December 2017. The PPA requires the facility to sell all of its output at contracted electricity rates which are comprised of separate capacity and energy payments, each subject to annual escalation. Under the PPA, the OEFC also provides a fixed gas price adjustment payment to offset the Company’s fuel costs. The PPA requires the facility to achieve a minimum capacity target for onpeak hours to receive the monthly capacity payment. The OEFC has the right to curtail a limited amount of power during off-peak periods.

The existing natural gas supply agreement with TransCanada provides for annual quantities of natural gas at an indicated price for each year until the contract expiry in October 2016. There are no restrictions on diversion or re-sale of natural gas under the existing contract, which has allowed for optimization activities in the past.

Atlantic Power anticipates purchasing gas on a forward basis from the Ontario market upon expiry of the current agreement as current forward gas prices are substantially below those within the existing contract.

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Waste heat is an intermittent resource provided to the facility from compressor stations on the TransCanada pipeline. The amount of waste heat received is dependent on gas flows along the pipeline.  As a result, waste heat availability is generally seasonal, with the majority provided during the winter months, and total amounts may vary from year to year. APLP Holdings forecasts waste heat by evaluating a combination of historical average availability and TransCanada’s annual projections.

Orlando

Capacity and energy production of up to 115 MW is sold to Progress Energy Florida (“PEF”) based on a PPA that expires in 2023. Pursuant to the PPA, Orlando receives monthly capacity payments based on achieving a specified onpeak capacity factor and an energy payment based on the total amount of electric energy delivered to PEF. In 2009, Orlando executed an agreement with Rainbow Energy Marketing Corporation (‘‘Rainbow’’) to market certain amounts of energy.

Under an agreement with a subsidiary of Air Products, Orlando supplies chilled water produced using steam from the project to Air Products’ cryogenic air separation facility. Due to reduced demand for chilled water at the facility, Orlando procured and installed water distiller units in 2009 and entered into contracts to provide the distilled water to unaffiliated third parties to ensure maintenance of its QF status. 

Atlantic Power has historically hedged its portion of Orlando’s fuel requirements with arrangements at the Atlantic Power level with 2016 and 2017 gas volumes hedged. While the project is exposed to current gas prices, Orlando uses BP’s services for fuel procurement under a 10 year agreement.

Oxnard

Oxnard provides all of its electrical output to Southern California Edison (“SCE”) under a PPA that expires in 2020. The facility is required to operate throughout the term of the PPA to meet QF efficiency standards. The price paid under the PPA includes a capacity payment and an energy payment based on SCE’s SRAC rate. Capacity payments are based on achieving availability performance targets, requiring at least 80% facility availability during specified on-peak hours during summer peak demand months. An additional performance bonus is applied when on-peak forced outage rates are less than 15%. The Oxnard facility has historically achieved its firm capacity revenue and near-maximization of availability bonus revenues.

SRAC energy prices are published monthly. The SCE SRAC pricing provision in the PPA recovers the month-to-month natural gas costs related to electricity production and substantially passes through the fuel cost to SCE in the variable energy charge. Time of use factors are applied to the SCE SRAC energy rate to value the electricity delivered during on-peak hours relative to electricity delivered during off-peak hours. The Oxnard facility typically operates to maximize its production margin. Generally, the facility operates in mid-peak and on-peak periods in order to take advantage of higher electricity prices provided from on-peak time of use rates and because the majority of the capacity payment is earned during these time periods.

Oxnard supplies steam to an anhydrous ammonia absorption refrigeration plant (“AAARP”) owned by Boskovich Farms Inc. for a monthly hosting fee, thereby maintaining QF status.. The agreement will run through the term of the PPA (2020).

The facility purchases fuel on a monthly basis with a month-end true-up. Noble Energy is the purchasing agent. No resale is required under normal operations.

Selkirk

Selkirk sells all of its output into Zone F of the New York Independent System Operator (“NYISO”) as a merchant facility. The project sells capacity energy and ancillary services.

The project sells steam to the Saudi Arabia Basic Industries Corporation (“SABIC”) plant under an agreement expiring on August 31, 2034, by which SABIC pays two different steam prices depending on whether steam is generated by the cogeneration plant or the auxiliary boilers. The cogeneration steam price is adjusted monthly based on current natural gas prices.

Selkirk purchases gas on a monthly or daily basis from Shell Energy. The project maintains firm gas transportation on Tennessee Gas Pipeline from Wright, NY to the facility, totaling 55,000 dekatherms / day.

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Tunis

Atlantic Power reached a deal with the IESO which enables the Company to execute on a contract option starting between November 2017 and June 2019 for a 15 year term.

The long term gas supply contracts for Tunis expired in 2010 and Atlantic Power has been purchasing gas from the forward market since that time. A Precedent Agreement has been signed with TransCanada for gas transportation starting around 2018.

Waste heat is an intermittent resource associated with existing compressor stations in operation on the TransCanada Mainline. The amount of waste heat received is seasonal and dependent on the volume of gas transported along the pipeline. As such, the occurrence of waste heat is predominantly in the winter months and varies from year to year. Atlantic Power forecasts waste heat by evaluating a combination of historical average availability and TransCanada’s annual projections. 

Williams Lake

Electricity generated by the Williams Lake facility is sold to BC Hydro under an EPA that commenced on April 2, 1993 and whose initial term expires on March 31, 2018. Under the EPA, the facility sells its output to BC Hydro under two tranches with two respective generation and pricing provisions: a firm energy tranche committed to BC Hydro (approximately 82% of total generation); and a surplus energy tranche (approximately 18% of total generation). The firm energy tranche price consists of: (i) a fixed energy component; (ii) an O&M cost component; and (iii) a reimbursable cost component,  which includes fuel costs, ash disposal costs and certain insurance, property tax and other expenses. As a result of the fuel cost pass-through, the facility does not face fuel cost recovery risk for its generation up to the amount of annual firm energy.

The amount of firm energy sold to BC Hydro under the firm energy tranche is fixed at 445 GWh (82% of total energy), except in years when major overhauls are performed (approximately every five years). Revenues remain constant in major overhaul years due to higher firm energy pricing and the firm energy commitment to BC Hydro is reduced to 401 GWh. Cost recovery components are escalated annually for inflation. In January 2012, BC Hydro entered into a curtailment agreement with Williams Lake. This agreement is effective through 2014. BC Hydro also purchases all of the facility’s energy output above the annual firm energy tranche, which is referred to as surplus energy. Williams Lake is under no obligation to provide surplus energy.

Williams Lake has historically consumed 540,000 to 640,000 GMTs per year of wood waste. Wood waste is provided on a contracted basis by Tolko Industries Ltd.’s Lakeview, Creekside and Soda Creek mills; as well as West Fraser Mills Ltd.’s Williams Lake lumber mill, plywood mill and 100 Mile lumber mill. These saw mills are located in close proximity to the Williams Lake and Caribou regions of British Columbia.

Historical Financial and Operations Data

The following table provides summary historical financial information for APLP Holdings, pro forma for the Restructuring. Note that these financials have not been audited and are presented proportionally consolidated for the Company’s ownership interest in partially-owned projects. The Piedmont facility has been excluded from these historical financials because it will not be part of the pro forma APLP Holdings collateral package. 2012 and 2013

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APLP EBITDA is inclusive of certain corporate G&A allocations and development costs, which are not reflected in the asset level details above. In addition, APLP Holdings is not a separately reporting entity and financial and operational information for APLP Holdings is not otherwise attributable to the Company.

Cautionary Note Regarding Forward-Looking Statements

To the extent any statements made herein 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 Exchange Act, and under Canadian securities law (collectively, “forward-looking statements”).

Certain statements made herein may constitute “forward-looking statements”, which reflect the expectations of management regarding the future growth, results of operations, PPA recontracting expectations, maintenance schedule and requirements, 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,” “forecast”, “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.

Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance, results or outcomes and will not necessarily be accurate indications of whether or not or the times at or by which such performance, results or outcomes will be achieved.  Please refer to the factors discussed under “Risk

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Factors” 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.  Although the forward-looking statements contained herein 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 hereof, except as expressly required by applicable law, the Company assumes no obligation to update or revise them to reflect new events or circumstances.

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