Exhibit 99.1

Certain Information to be Provided to Prospective Lenders

in Connection with the Launch of Syndication of the Credit Facilities

As previously disclosed, on January 30, 2014, Atlantic Power Limited Partnership (“APLP”), a wholly-owned 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 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 will be successful in the syndication of the Credit Facilities or that APLP will be able to enter into and close the Credit Facilities, or if APLP is able to enter into the Credit Facilities, the timing of closing of the Credit Facilities.  The information in this Item 7.01, including Exhibit 99.1 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 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 and EBITDA based on numbers presented in accordance with International Financial Reporting Standards (“IFRS”).  The difference between EBITDA based on numbers presented in accordance with GAAP and EBITDA based on numbers presented in accordance with IFRS is due to the differences in the respective accounting principles, primarily including the fact that certain operation and maintenance (“O&M”) expenses are capitalized under IFRS but expensed under GAAP, as well as certain foreign currency impacts.  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 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

As previously disclosed by the Company, the Credit Facilities are expected to comprise of up to $600 million in aggregate principal amount of senior secured term loan facilities (the “Term Loan Facility”) and up to $200 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 four-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 is forecasted to repay 76.6% of the outstanding principal of the proposed term loans available under the Credit Facilities by maturity, resulting in a reduction of the term loan debt from $512/kW at inception to $119/kW (or $140.0 million aggregate principal amount) outstanding as of December 2020.  Assuming, hypothetically, the Term Loan Facility were not repaid by maturity, the Term Loan Facility would be forecasted to be fully repaid by December 2022.  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 3.8x with respect to the loans under the Credit Facilities.

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The creditors under the Credit Facilities are expected to have a security interest in substantially all assets of APLP, other than Frederickson, and are expected to have mortgages over the real property of all of APLP’s projects, other than Frederickson, North Island, Naval Station and Naval Training Center.  For the Frederickson project, only APLP’s equity interest in the subsidiary of APLP that owns 50.15% of the Frederickson project will be pledged.  APLP expects to use commercially reasonable efforts to obtain leasehold mortgages with respect to the leasehold interests of North Island, Naval Station and Naval Training Center.  The Greeley project, whose PPA expired in August 2013, is currently non-operational and is not expected to be pledged.

The following table reflects the estimated sources and uses of funds from the Credit Facilities, and may vary at closing of the Credit Facilities.  The sources exclude a $17.6 million Revolving Credit Facility letter of credit posting to support a six-month debt service reserve account (as will be defined in the Credit Facilities).

The following table reflects the pro forma capitalization of APLP as a result of the Credit Facilities.  A six-month debt service reserve is expected to be put in place at closing of the Credit Facilities, and will be funded by  a letter of credit under the Revolving Credit Facilities.

LTM Sept-2013 EBITDA:

$141 million (on an IFRS basis)

2013E EBITDA (Midpoint of Guidance):

$160 million (on a GAAP basis)

Net Operating Capacity (MW): 1,173

(1) Calculated on an IFRS basis.

(2) Calculated on a GAAP basis.

Atlantic Power Limited Partnership

APLP, a wholly-owned indirect subsidiary of the Company, owns and operates a fleet of 17 generating projects totaling 1,298 MW, in which its aggregate wholly-owned ownership interest is approximately 1,173 MW of net generating capacity, across six U.S. states and two Canadian provinces.  As of January 1, 2014, approximately 1,073

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MW of APLP’s net generating capacity was contracted under long-term power purchase agreements (“PPAs”) and/or energy off-take agreements (“Energy Off-Take Agreements”), with a remaining weighted average contract life of 7.1 years.  Of the 415 MW of APLP’s net generating capacity expiring before 2020, 96 MW have offtake extension options.

APLP’s operating projects are: North Bay, Tunis, Calstock, Kapuskasing, Nipigon, Moresby Lake, Williams Lake, Mamquam, Frederickson, Manchief, Curtis Palmer, Morris, North Island, Kenilworth, Oxnard, Naval Training Center and Naval Station.  Additional information with respect to each of these projects is provided in the Company’s periodic reports filed with the Securities and Exchange Commission.

For the twelve month period (“LTM”) ended September 30, 2013, over 91% of APLP’s generation capacity was contracted and 96% of APLP’s fuel exposure was mitigated.  For the LTM period ended September 30, 2013, APLP’s EBITDA was $141.0 million (on an IFRS basis), while operationally, APLP’s generating assets had an average availability factor of 93.4% and an average capacity factor of 47.0%.  The Company expects APLP to generate EBITDA of $155.0 —$165.0 million (on a GAAP basis) for the year ended December 2013.  The Company estimates that APLP’s cash flows should provide over $1.0 billion of EBITDA (on a GAAP basis) through maturity of the Credit Facilities.

The following table includes the percent of average projected contracted EBITDA attributable to each of APLP’s eleven counterparties.

(1)   Calculated on a GAAP basis.  Based on management’s projections for the financial performance of the contracted assets between 2014 and the maturity of the Term Loan Facility, reflecting forecasted dispatch and operating costs.

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 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, 2012.

The following table represents the capacity weighted average availability factor for the APLP projects.  The below table includes information for 2010 and 2011, which is prior to the Company’s acquisition of APLP and the projects to which the information relates.   The Company reviewed this information, which was supplied by the seller of APLP, only in the context of its due diligence investigation prior to the acquisition of APLP in 2011.  This information has not been audited or reviewed by the Company’s independent public accountants.  This information does not necessarily reflect the results of operations that would have been or could have been achieved if APLP had owned and operated the same assets during that period.  The Company was not involved in the preparation of the financial statements of APLP in 2010 and 2011 and there can be no assurance that the seller defined and calculated

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historical EBITDA and other financial measures in the same way that the Company or APLP calculated such measures.  In addition, APLP is not a separately reporting entity and financial and operational information for APLP is not otherwise attributable to the Company.

Capacity-Weighted Average Fleet-Wide Availability Factor

Post-PPA Prospects

Prospective lenders were provided with the following updates regarding certain markets in which the PPAs at certain APLP 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.

With a geographic footprint spanning seven power markets across six U.S. states and two Canadian provinces, the APLP portfolio is exposed to a diversity of market fundamentals and unique supply-demand dynamics.  As such, as the APLP assets approach PPA maturity, the Company expects the portfolio to benefit from a diversity of merchant market fundamentals which ultimately shape recontracting economics.

Of the 415 MW of APLP’s PPAs expiring prior to maturity of the Term Loan Facility, 101 MW relate to the Williams Lake and Calstock biomass facilities, which the Company believes are strategically located near significant biomass wood supplies in British Columbia and Ontario, respectively.  Biomass plays an important role in the power supply for both provinces, given that these facilities operate constantly, thereby contributing to each province’s baseload supply requirements.  The Company believes that Calstock’s location near significant biomass wood reserves is strategically important for achieving Ontario’s renewable energy goals.

Additionally, 161 MW of the PPAs that expire prior to maturity of the Term Loan Facility relate to gas fired assets in California (Naval Station, Naval Training, North Island and Oxnard), where the Company believes inherent permitting difficulties for new-build facilities, once-through cooling retirements and the shutdown of the San Onofre Nuclear Generating Station are expected to increase demand for dependable baseload/ intermediate generation capacity.  With carbon costs supporting higher power prices, the Company believes low heat rate combined cycle gas turbines (“CCGTs”) like those of certain of the APLP facilities are advantageously positioned, when compared to high heat rate peakers that have a significantly higher emission profile.

Additionally, 30 MW of the PPAs that expire prior to maturity of the Term Loan Facility 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 offering premium payments and what the Company expects to be strong energy revenue prospects.  As a result of the relocation, the Company expects that Merck will have an ongoing need for power, which the Company believes may lead Merck to exercise its three consecutive one-year extension options under the Kenilworth PPA.  In addition, the Company believes that Merck will likely need power beyond its maximum PPA term end-date in 2021.

In addition, as a participant in the PJM ancillary market, the Company expects that the Morris facility will benefit from the market fundamentals supporting what the Company believes to be an attractive outlook for ancillary services.

The Company believes the Tunis, North Bay and Kapuskasing facilities to be strategically located adjacent to compressor stations on TransCanada Corporation’s Northern Ontario Pipeline (the “Northern Ontario Pipeline”), which allows the facilities to benefit from waste heat power generation.  The Tunis PPA, maturing in December 2014, is the first of the PPAs to expire and APLP is currently in negotiations with the Ontario Power Authority to re-

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contract the facility.  Additionally, TransCanada Corporation (“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.  The Company believes that power facilities sitting along the TransCanada mainline, such as those in the APLP fleet, may serve a critical role in supporting the operations and future development of the Northern Ontario Pipeline.

In addition, many of Ontario’s non-utility generators (“NUGs”) have PPAs originally arranged under contract with the former Ontario Hydro and now administered by the Ontario Electricity Financial Corporation (the “OEFC”).  Contracts representing 75% of that capacity will expire by the end of 2018.  The Ontario Power Authority has been directed by the Provincial Government to enter into new contracts with certain NUGs, including all of APLP’s assets, after the current ones expire, but only if the contract results in cost and reliability benefits to Ontario ratepayers.

At the request of the Provincial Government of British Columbia, the British Columbia Hydro and Power Authority (“BC Hydro”) prepared an updated integrated resource plan, which was approved on November 25, 2013.  The Company believes that this plan highlighted the intention of BC Hydro to enter into renewals of existing PPAs with Independent Power Producers where they are deemed to be cost effective and as part of its overall clean energy strategy.

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, 2012.  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.

Power Purchase and Supply Arrangements

Prospective lenders under the Credit Facilities will receive a range of information about the terms of certain contracts to which APLP 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.

Approximately 96% of APLP’s fuel risk is contained through contracts through the earlier of the fuel arrangements expiry or the PPA expiry.  The Company often employs (i) tolling structures, whereby an offtaker is responsible for fuel procurement, (ii) long term fuel contracts, whereby the Company locks in a set quantity of fuel at a predetermined price or (iii) passthrough arrangements, whereby the cost of fuel is borne by the ultimate offtaker.

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

Calstock

Electrical output from the Calstock facility is sold to the OEFC under a PPA that was executed on April 29, 1994 and whose term expires on June 16, 2020.  The Calstock 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 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.

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

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agreements are scheduled to expire in March 2017 and APLP expects to seek to extend such supply agreements 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, which has been used to provide supplemental fuel for the site when the mills were idled in 2011. The remainder of wood waste is procured on an ad hoc basis.

For the Calstock facility and the Kapuskasing, North Bay, Nipigon and Tunis facilities (further discussed below), 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 totals may vary from year to year.  APLP forecasts waste heat by evaluating a combination of historical average availability and TransCanada’s annual projections.

Kapuskasing and North Bay

Electrical output from the Kapuskasing and North Bay facilities is sold to the OEFC under PPAs that were executed on February 1, 1994 and whose terms expire on December 31, 2017.  The Kapuskasing and North Bay PPAs are designated as NUG contracts.  Both PPAs require the respective facility to sell all of its output to the OEFC at contracted electricity rates, which are comprised of separate capacity and energy payments and which are subject to annual escalation.  Under each PPA, the OEFC also allows APLP a fixed gas price adjustment rate to offset its fuel costs.  Under the Kapuskasing PPA, the OEFC may curtail a limited amount of power during off-peak periods.  Under the North Bay PPA, the facility has the flexibility to maximize its profit from either power generation or gas diversion sales through curtailment. Neither PPA restricts the curtailment of power generation for the purposes of gas diversion sales, but each requires the respective facility to achieve a minimum monthly capacity target for on-peak hours to receive a monthly capacity payment.

APLP has natural gas supply agreements with TransCanada Power Corp. for a firm quantity of natural gas at a firm price each year for each of Kapuskasing and North Bay. The contracts expire on October 31, 2016. There are no restrictions on diversion or resale of natural gas under the contracts. Upon expiry of the gas supply agreements, there is a potential opportunity to optimize gas transportation agreements. APLP anticipates purchasing gas on a forward basis from the Ontario market upon expiry of the natural gas supply agreements to bridge the gap with the expiry of the PPAs at these projects. However, no assurance can be given that APLP will be able to do this on terms that it considers economically attractive or at all. Current forward gas prices for the November 2016 to December 2017 period are substantially below the prices under the existing long term contracts; however, gas prices are subject to fluctuation and may be higher or lower when the PPA expires.

Nipigon

Electrical output from the Nipigon facility is sold to the OEFC under a PPA that was executed on April 25, 1990 and whose original term expired on December 31, 2012. The PPA contained a ten-year renewal option, which APLP exercised, thereby extending the PPA to 2022. 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, both of which are subject to annual escalation. The Company believes that the PPA offers strong incentives for the plant to operate at base load, including off-peak hours.

APLP executed a 10-year fixed price gas supply agreement with BP for the January 2013 to December 2022 period, which matches the term of the Nipigon PPA.

Tunis

Electrical output from the Tunis facility is sold to OEFC under a PPA that was executed on August 10, 1992 and whose term expires on December 31, 2014. The PPA requires the facility to sell all of its output to OEFC at contracted electricity rates, which are comprised of separate capacity and energy payments.  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.

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The long term gas supply contracts for Tunis expired in 2010 and APLP has been purchasing gas from the forward market using a combination of multi-month and monthly purchases since that time. APLP expects to revisit the gas purchasing strategy if new PPA terms are secured.

Mamquam

Electricity produced by Mamquam is sold to BC Hydro under an Electricity Purchase Agreement (“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. 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 holds a conditional water license for the Mamquam facility, which was granted on May 26, 1994 and amended on March 31, 1999, which 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.

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.

APLP 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 cubic feet per second (“cfs”) (no flow restrictions). Works that are authorized are 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.

Williams Lake

Electrical output from 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 and contains two corresponding generation and pricing tranches: (i) a firm energy tranche committed to BC Hydro, representing approximately 82% of total energy produced and (ii) a surplus energy tranche, representing approximately 18% of total energy produced. The firm energy tranche price consists of (i) a fixed energy component, (ii) an operations and maintenance 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 Gigawatt hours (“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 whereby the facility receives a curtailment bonus and incentive if it does not operate during pre-determined summer month periods.  Under the curtailment agreement, ash and fuel components are built into the surplus pricing

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which compensates the project for such costs. This agreement is effective through 2014 with both parties having an option to terminate annually with notification prior to September 2014.

The Williams Lake facility has historically consumed 540,000 to 640,000 GMT per year of wood waste. Wood waste is provided on a contracted basis by Tolko Industries Ltd.’s Lakeview, and Soda Creek mills and West Fraser Mills Ltd.’s Williams Lake lumber mill, Plywood mill and 100 Mile lumber mill. These saw mills are located nearby in the Williams Lake and Caribou regions of British Columbia. Under the wood waste supply contracts, the mills do not have an obligation to provide wood waste in the event that they scale back or shut down operations.

Frederickson

APLP’s portion (50.15%, or approximately 125 MW) of the Frederickson facility’s gross 249 MW generating capacity is sold under PPAs to three Washington state PUDs (Benton County, Grays Harbor and Franklin County) for a term of 20 years ending in August 2022. Under the PPAs, APLP provides generating capacity and associated energy to each PUD, and the PUDs pay APLP (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 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) 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. The duct-fired capacity also dispatches when profitable in the real-time market.

Under the PPAs, the three local Washington state PUDs must supply their proportionate share of natural gas to APLP at Huntington, British Columbia. APLP guarantees a heat rate and pays for gas needed above the guaranteed heat rate. APLP 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 bilateral evergreen provision extension.  Gas procurement related to duct-firing is the responsibility of the off-taker.

Manchief

The Manchief power plant operates under an Energy Services Agreement (“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 301 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 and PSCo have signed an Option Agreement under which PSCo has the right to acquire the Manchief facility, which may be exercised in April 2020 or April 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.

Naval Station, Naval Training Center and North Island

All of the electrical output from the Naval Station, Naval Training Center and North Island facilities, except 2.5 MW of electrical output from the Naval Training Center and 4 MW of electrical output from North Island, is sold to San Diego Gas & Electric (“SDG&E”) under the Standard Offer 4 (“SO4”) PPA. SDG&E purchases energy priced at the Short Run Avoided Cost (“SRAC”) and compensates the facility for capacity.

The remaining 2.5 MW of capacity generated at the Naval Training Center facility is sold to SDG&E under the Standard Offer 1 (“SO1”) PPA.  The energy rates under the SO1 PPA are the SDG&E SRAC rates.  Capacity payments are paid on an as-available basis under rates that are reviewed by the California Public Utilities

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Commission periodically.  The SO1 PPA does not have expiration date provisions, but the Company anticipates it will terminate on the same date as the SO4 PPA.

The remaining 4 MW of capacity generated at North  Island, 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 recently repowered gas turbine at the North Island facility can generate an additional 4 MW of power that is not currently being delivered to the grid. The Company believes that amending the SO4 PPA to allow for delivery of additional power will not result in any cost increase and expects that it should result in additional EBITDA.

Fuel is purchased on a monthly basis with a month-end true-up.  J.P. Morgan is the purchasing agent.  Steam generated from the Naval Station, Naval Training Center and North Island facilities is sold to the U.S. Navy pursuant to a Negotiated Utility Style Service Contract (“NUSC”).  Both the U.S. Navy and SDG&E assume fuel risk for fuel use per the terms of each agreement. In addition to providing a steam host, the U.S. Navy also leases land to the facility. While this agreement expires in February 2018, discussions were recently initiated to extend the tenor of this agreement.

Oxnard

The Oxnard facility provides all of its natural gas turbine electrical output to Southern California Edison (“SCE”) under a PPA that expires in 2020. The Oxnard facility is required to operate throughout the term of the PPA to meet Qualifying Facility (“QF”) efficiency standards. The price paid under the PPA includes a capacity payment and an energy payment based on SCE’s SRAC. Capacity payments are based on achieving availability performance targets. These performance requirements require that contract capacity for the facility is to be at least 80% during specified on-peak hours during the 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 capacity 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 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.

The Oxnard facility supplies steam to an anhydrous ammonia absorption refrigeration plant owned by EF Oxnard LLC, which then provides refrigeration services to Boskovich Farms Inc., a food processing and cold storage facility, for a monthly hosting fee, thereby maintaining the Oxnard facility’s QF status. This fee is currently in the final stages of renegotiation and there can be no assurance that APLP will be able to negotiate the fee on terms that it considers economically attractive, or at all. The new agreement would run through the term of the PPA.  Fuel is purchased on a monthly basis and sold on off-peak and weekends as Oxnard runs on-peak only at current market conditions. J.P. Morgan is the purchasing agent.

Curtis Palmer

All of the electricity produced by Curtis Palmer is sold to Niagara Mohawk Power Corporation (“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.  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 that 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 the Federal Energy Regulatory Commission on April 27, 2000.

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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 pass through and a fixed dollar per megawatt hour (“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 Inc. 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) 12,000 lbs each hour. The steam price is calculated using two tiers (up to 15,000 lbs per hour and above 15,000 lbs per hour) and is calculated assuming 80% boiler efficiency and a steam enthalpy of 1.1147 million British thermal units per kilopound.

APLP purchases natural gas from J. Aron or PPL EnergyPlus at the direction of Merck, the purchaser of a majority of electricity and all of the steam produced by the facility. Fuel costs are passed through to Merck utilizing a heat rate derived formula to determine steam and electricity pricing.

Morris

The Morris facility sells electrical energy to Equistar under an ESA that expires in 2023. Pursuant to the ESA, Equistar pays a tiered energy rate based on the amount of energy consumed up to a maximum of 77 MW. Equistar also pays a capacity fee that escalates with materials and labor indices and expires in 2023. In addition, the Morris facility earns energy payments based on electricity and steam delivered that is adjusted monthly for natural gas prices. Based on the energy payment formula, there is a portion of energy costs that are not recovered through the energy payments, and 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 each of 2013, 2018 and 2023.  Equistar did not exercise this right at the end of 2013.  The Morris Facility currently sells 100MW of energy capacity, and ancillary services, into the PJM market.  The plant’s PJM capacity rating has been approved to be increased to 107 MW in 2016/2017 and 120 MW in 2017/2018. Regulation, a PJM ancillary service, is also a revenue source for the plant.

The Morris facility sells steam to Equistar up to a maximum of 720 million pounds per hour (“mmlbs/hr”) under its ESA through 2023. Normal usage is approximately 320 mmlbs/hr. 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.

The Morris facility obtains the majority of its required natural gas through a Purchase and Sale Agreement with Tenaska Marketing Ventures (“Tenaska”) which expires in April 2014 at a price indexed to the Chicago City Gate market. Under the agreement, Tenaska also provides power market trading services through a year-to-year agreement that may be cancelled on 60-days’ notice. Additionally, the Morris facility has gas storage associated with its gas transportation agreement with Nicor Gas Company. Tenaska manages this gas storage as a seasonal hedge and to maximize operational efficiency. This agreement will be reviewed on an annual basis.

Historical Financial and Operations Data

The below tables include information for 2010 and 2011, which is prior to the Company’s acquisition of APLP and the projects to which the information relates.   The Company reviewed this information, which was supplied by the seller of APLP, only in the context of its due diligence investigation prior to the acquisition of APLP in 2011.  This information has not been audited or reviewed by the Company’s independent public accountants.  This information does not necessarily reflect the results of operations that would have been or could have been achieved if APLP had owned and operated the same assets during that period.  The Company was not involved in the preparation of the financial statements of APLP in 2010 and 2011 and there can be no assurance that the seller defined and calculated

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historical EBITDA and other financial measures in the same way that the Company or APLP calculated such measures.  In addition, APLP is not a separately reporting entity and financial and operational information for APLP is not otherwise attributable to the Company.

The following table provides summary historical financial information for APLP (on an IFRS basis).  APLP’s Greeley project, whose PPA expired in August 2013, is currently non-operational and has been excluded from all financial and operational data.

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The below tables provide certain historical financial and operations data for each of the APLP projects.

Historical EBITDA(1) (in millions of dollars)

(1)   Calculated on a GAAP basis.

(2)   2013 has seen an increase in EBITDA due to new pricing terms under the amended and restated ESA, which became effective in November 2013 and includes retroactive capacity  payments for part of 2013.

Availability Factor

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Capacity Factor

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, 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 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” 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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