ITEM 1. BUSINESS
GENERAL
Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. Our power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements (“PPAs”), which seek to minimize exposure to changes in commodity prices. As of December 31, 2015, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,138 megawatts (“MW”) in which our aggregate ownership interest is approximately 1,500 MW. Our current portfolio consists of interests in twenty-three operational power generation projects across nine states in the United States and two provinces in Canada. Eighteen of our projects are majority-owned.
The following charts show, based on generation capacity in MW, the diversification of our portfolio by segment and fuel type:
We sell the majority of the capacity and energy from our power generation projects under PPAs to a variety of utilities and other parties. Under the PPAs, which have expiration dates ranging from December 31, 2017 to December 31, 2037, we receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). We also sell steam from a number of our projects to industrial purchasers under steam sales agreements. Sales of electricity are generally higher during the summer and winter months, when temperature extremes create demand for either summer cooling or winter heating.
The majority of our natural gas, coal and biomass power generation projects have long-term fuel supply agreements, typically accompanied by fuel transportation arrangements. In most cases, the term of the fuel supply and transportation arrangements correspond to the term of the relevant PPAs and many of the PPAs and steam sales agreements provide for the indexing or pass-through of fuel costs to our customers. In cases where there is no pass-through of fuel costs, we often attempt to mitigate the market price risk of changing commodity costs through the use of hedging strategies.
We directly operate and maintain the majority of our power generation projects. We also partner with recognized leaders in the independent power industry to operate and maintain our other projects, including Colorado Energy Management (“CEM”) and Power Plant Management Services (“PPMS”). Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.
HISTORY OF OUR COMPANY
Atlantic Power Corporation is a corporation continued under the laws of British Columbia, Canada, which was incorporated in 2004. We used the proceeds from our initial public offering on the Toronto Stock Exchange (“TSX”) in November 2004 to acquire a 58% interest in Atlantic Power Holdings, LLC (now Atlantic Power Holdings, Inc., which we refer to herein as “Atlantic Holdings”) from two private equity funds managed by ArcLight Capital Partners, LLC
(“ArcLight”) and from Caithness Energy, LLC (“Caithness”). Until December 31, 2009, we were externally managed under an agreement with Atlantic Power Management, LLC, an affiliate of ArcLight, when we agreed to pay ArcLight an aggregate of $15 million to terminate its management agreement with us. In connection with the termination of the management agreement, we hired all of the then-current employees of Atlantic Power Management and entered into employment agreements with its three officers.
At the time of our initial public offering, our publicly traded security was an Income Participating Security (“IPS”), which was comprised of one common share and a subordinated note. In November 2009, our shareholders approved a conversion from the IPS structure to a traditional common share structure in which each IPS was exchanged for one new common share and each old common share that did not form a part of an IPS was exchanged for approximately 0.44 of a new common share. Our common shares trade on the TSX under the symbol “ATP”. On July 23, 2010, we also began trading on the New York Stock Exchange (“NYSE”) under the symbol “AT”.
On November 5, 2011, we directly and indirectly acquired all of the issued and outstanding limited partnership units of Capital Power Income L.P., which was renamed Atlantic Power Limited Partnership on February 1, 2012 (the “Partnership”). The Partnership’s portfolio consisted of 19 wholly-owned power generation assets located in both Canada and the United States, a 50.15% interest in a power generation asset in the state of Washington, and a 14.3% common ownership interest in Primary Energy Recycling Holdings, LLC which was later sold in 2012. At the acquisition date, the transaction increased the net generating capacity of our projects by 143% from 871 MW to approximately 2,116 MW.
On June 26, 2015, we sold our 100% ownership interest in Meadow Creek Project Company, LLC (“Meadow Creek”), 99% ownership in Canadian Hills Wind, LLC (“Canadian Hills”), 50% ownership interest in Rockland Wind Farm, LLC (“Rockland”), 27.6% ownership interest in Idaho Wind Partners 1, LLC (“Idaho Wind”) and 12.5% ownership interest in Goshen Phase II, LLC (“Goshen”) (collectively, the “Wind Projects”), totaling 521 MW net ownership to TerraForm AP Acquisition Holdings, LLC (“TerraForm”), an affiliate of SunEdison, Inc.
OUR BUSINESS STRATEGY
General
Our business strategy is to increase the intrinsic value of the Company on a per-share basis through disciplined management of our balance sheet and our cost structure and investment of our discretionary cash in a combination of organic growth projects, external acquisitions and repurchases of our debt and equity securities. In evaluating these potential investments we are guided by the price-to-value relationship. With respect to organic growth, we have been making optimization investments in our existing projects that have produced cash returns higher than those currently available externally. We may undertake additional investments to repower certain facilities in conjunction with extensions of existing Power Purchase Agreements. We evaluate external growth opportunities on a regular basis, and have a highly disciplined and opportunistic approach that favors capital-light projects in the United States and Canada. We will prioritize the use of discretionary cash for repurchases of our debt and equity securities when the price-to-value level is compelling, with a goal of increasing intrinsic value per share while also improving the Company’s financial flexibility and strengthening its balance sheet. We focus on generating stable operating margins via contracted cash flows from our existing assets, and we use our depth of asset management experience to enhance the operating, contractual and financial performance of our current portfolio of projects.
In 2015, we successfully executed on several key initiatives. Through consolidation of our corporate operations to a single location as well as a reduction in workforce, we lowered our corporate overhead expenses from $54 million in 2013 to $32 million in 2015. We have utilized proceeds from asset sales at attractive valuations, as well as cash flow from our existing projects, to pay down debt, including our highest-cost debt. In total, we have reduced debt by approximately $833 million in the past two years and reduced our annual cash interest payments by approximately $65 million or more than 50%. We invested $22 million in our existing fleet in 2013 through 2015 and realized a cash return on these investments of approximately $6 million in 2015, which is expected to grow to $10 million in 2016.
On February 9, 2016, the Board of Directors, consistent with management’s recommendation, eliminated the common share dividend, effective immediately. Previously, we paid a dividend of Cdn$0.03 per share quarterly, with the most recent payment on December 31, 2015. This change to our capital allocation strategy is designed to create value for shareholders in a tax-efficient manner, while also improving our financial flexibility and strengthening our balance sheet. As part of this strategy, we will prioritize allocation of our discretionary capital to equity and debt repurchases, each under the normal course issuer bid (“NCIB”) implemented in December 2015, with a goal of capturing value arising from price-to-value opportunities in our publicly traded securities. In addition, the additional liquidity can be used for organic growth through high-return investments in existing projects, as well as potential repowering of projects linked to extensions of PPAs.
Extending PPAs following their expiration
PPAs in our portfolio have expiration dates ranging from December 31, 2017 to December 31, 2037. We plan for PPA expirations by evaluating various options in the market. New arrangements may involve responses to utility solicitations for capacity and energy, direct negotiations with the original purchasing utility for PPA extensions, “reverse” request for proposals by the projects to likely bilateral counterparties, including traditional PPAs, tolling agreements with creditworthy energy trading firms or the use of derivatives to lock in value. When a PPA expires or is terminated, it is possible that the price received by the project for power under subsequent arrangements may be reduced and in some cases, significantly. Our projects may not be able to secure a new agreement and could be exposed to selling power at spot market prices. It is possible that subsequent PPAs or the spot markets may not be available at prices that permit the operation of the project on a profitable basis. See Item 1A.
ITEM 1A. RISK FACTORS
This section highlights specific risks that could affect our Company. You should carefully consider each of the following risks and all of the other information set forth in this Annual Report on Form 10-K. Based on the information currently known to us, we believe the following information identifies the most significant risk factors affecting our Company. However, the risks and uncertainties described below are not the only ones related to our business and are not necessarily listed in the order of their importance. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business, results of operations or financial condition.
If any of the following risks and uncertainties develops into actual events or if the circumstances described in the risks and uncertainties occur or continue to occur, these events or circumstances could have a material adverse
effect on our business, results of operations or financial condition. These events could also have a negative effect on the trading price of our securities.
Risks Related to Our Structure
We may not generate sufficient cash flow to service our debt obligations or implement our business plan, including financing internal or external growth opportunities
We continue to focus on executing our business plan, including the objectives of enhancing the value of our existing assets through discretionary capital investments and commercial activities, delevering our balance sheet to improve our cost of capital and ability to compete for new investments, improving our cost structure and reducing overhead. However, we may not generate sufficient cash flow to service our debt obligations or implement our business plan, including financing internal or external growth opportunities.
Our ability to make required payments under our outstanding indebtedness, including pursuant to the mandatory amortization feature of the Senior Secured Credit Facilities (as defined herein), as well as the 50% cash sweep, or to prepay or redeem any such indebtedness, will depend on our financial and operating performance, including our ability to generate cash flow from operations in the future. As a result, we may be required to refinance such indebtedness and/or obtain third-party financing in order to repay, redeem or refinance such indebtedness when it comes due. In particular, the Cdn$67.3 million aggregate principal amount of our 6.25% convertible debentures is due March 2017, the Cdn$75.8 million aggregate principal amount of our 5.60% convertible unsecured subordinated debentures is due June 2017, the $117.0 million aggregate principal amount of our 5.75% convertible unsecured subordinated debentures is due June 2019 and the Cdn$90.0 million aggregate principal amount of our 6.00% convertible unsecured subordinated debentures is due December 2019. There can be no assurance that our business will generate sufficient cash flow from operations or that future borrowings or refinancing opportunities will be available to us at an acceptable cost, in amounts sufficient, or at all, to enable us to service our debt obligations or to repay or redeem any such indebtedness at maturity, particularly because of our high levels of debt and the debt incurrence restrictions imposed by the various agreements governing our indebtedness. Steps taken to refinance our indebtedness or obtain other third-party financing, if any, may not be successful and may not permit us to meet our scheduled debt service obligations, which could have a material adverse effect on our liquidity and financial condition.
In addition, a payout of a significant portion of our cash flow to service our debt, including pursuant to the mandatory amortization feature of the Senior Secured Credit Facilities, as well as the 50% cash sweep, or through preferred dividends, may result in us not retaining a sufficient amount of cash to finance growth and reinvestment opportunities, including through the acquisition of additional projects, to the extent any such acquisitions are otherwise available to us. As a result, we may have to forego growth and reinvestment opportunities that would otherwise be desirable, if we do not find alternative sources of financing for such opportunities. In addition, even if we are able to find alternative sources of financing for such opportunities, we may be precluded from pursuing an otherwise attractive acquisition or investment if the projected short-term cash flow from the acquisition or investment is not adequate to service the capital raised to fund such acquisition or investment. This could also limit our flexibility in planning for, or reacting to, changes in our business and industry, placing us at a competitive disadvantage compared to our competitors. We cannot provide any assurance that we will be able to identify, finance or close any transactions associated with any such growth or reinvestment opportunities on acceptable terms or timing, or at all.
Further, if we are unable to generate sufficient cash flow from operations, our ability to support our liquidity needs, including, but not limited to servicing our debt obligations, including pursuant to the mandatory amortization feature of the Senior Secured Credit Facilities, as well as the 50% cash sweep, or financing internal or external growth opportunities, will depend on our ability to access the credit and capital markets, neither of which may be available to us on acceptable terms, or at all. Currently, because we no longer qualify as a “well-known seasoned issuer,” which previously enabled us to, among other things, file automatically effective shelf registration statements, even if we were able to access the capital markets, any attempt to do so could be more expensive or subject to significant delays. Further, access to the credit and capital markets and the cost and availability of credit may be adversely affected by factors beyond our control, including turmoil in the financial services industry, volatility in securities trading markets and
general economic conditions. We cannot provide any assurance that we will be able to access the credit or capital markets on acceptable terms or timing, or at all.
Our Senior Secured Credit Facilities contain certain terms, covenants and restrictions that could impact our available cash flow and restrict our ability to make acquisitions or investments or issue additional indebtedness
Our Senior Secured Credit Facilities contain certain terms, covenants and restrictions, including a mandatory amortization feature and customary prepayment provisions, including, among others, using 50% of the cash flow of the Partnership and its subsidiaries that remains after the application of funds, in accordance with customary priority, to certain items, including, but not limited to, the operations and maintenance expenses of the Partnership and its subsidiaries, debt service on the Senior Secured Credit Facilities and other specified indebtedness and funding of a debt service reserve account. Such terms, covenants and restrictions may impact our available cash flow and limit our ability to retain sufficient amounts of cash to service our debt obligations or finance internal or external growth opportunities. Our Senior Secured Credit Facilities are a primary source of our liquidity. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources”.
The covenants under the Senior Secured Credit Facilities include a requirement that the Partnership and its subsidiaries, maintain certain leverage and interest coverage ratios (each, as defined in the credit agreement governing the Senior Secured Credit Facilities). The Senior Secured Credit Facilities also contain customary restrictions and limitations on the Partnership’s and its subsidiaries’ 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 thresholds. Any such limitations could restrict our ability to, among other things, make acquisitions or investments or issue additional indebtedness.
Our indebtedness and financing arrangements, and any failure to comply with the covenants contained therein, could negatively impact our business and our projects and could render us unable to make preferred dividend payments, acquisitions or investments or issue additional indebtedness we otherwise would seek to do
The degree to which we are leveraged on a consolidated basis could have important consequences for our shareholders and other stakeholders, including:
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our ability in the future to obtain additional financing for, among other things, the repayment or redemption of indebtedness and other debt service obligations and investment in internal and external growth opportunities, including the acquisition of additional projects, to the extent any such acquisitions are otherwise available to us, or other purposes;
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our ability to refinance indebtedness on terms acceptable to us or at all;
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our ability to satisfy debt service and other obligations;
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our vulnerability to general adverse industry conditions and economic conditions, including but not limited to adverse changes in foreign exchange rates and commodity prices;
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the availability of cash flow to fund other corporate purposes and grow our business;
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our flexibility in planning for, or reacting to, changes in our business and the industry; and
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placing us at a competitive disadvantage to our competitors that are not as highly leveraged.
As of December 31, 2015, our consolidated long-term debt represented approximately 70% of our total capitalization, comprised of debt and balance sheet equity.
The agreements governing our indebtedness limit, but do not prohibit, the incurrence of additional indebtedness. Our current or future borrowings could increase the level of financial risk to us and, to the extent that the interest rates are not fixed and rise, or that borrowings are refinanced at higher rates, our available cash flow and results of operations could be adversely affected. Changes in interest rates do not have a significant impact on cash payments that are required on our debt instruments as approximately 77% of our debt, including our share of the project-level debt associated with equity investments in affiliates, either bears interest at fixed rates or is financially hedged through the use of interest rate swaps.
As of December 31, 2015, we had (i) no amount outstanding and $104.0 million issued in letters of credit under our revolving credit facility, (ii) $285.4 million of outstanding convertible debentures, and (iii) $733.3 million of outstanding senior secured term loan and non-recourse project-level debt.
In addition, some of our projects currently have non-recourse term loans or other financing arrangements in place with various lenders. These financing arrangements are typically secured by all of the project assets and contracts as well as our equity interests in the project. The terms of these financing arrangements generally impose many covenants and obligations on the part of the borrower. For example, some of these agreements contain requirements to maintain specified historical, and in some cases, prospective debt service coverage ratios before cash may be distributed from the relevant project to us, which would adversely affect our available cash flow. We have, in the past, failed to meet the cash flow coverage ratio tests at certain of our projects, which restricted those projects from making cash distributions. Although all of our projects with non-recourse loans, with the exception of Piedmont, are currently meeting their debt service requirements, we cannot provide any assurances that our projects will generate enough future cash flow to meet any applicable ratio tests in order to be able to make distributions to us. Currently we do not expect our Piedmont project to meet its debt service coverage ratio covenants or to make distributions before 2018 at the earliest, due to higher than forecasted maintenance and fuel expenses than initially expected.
In many cases, an uncured default by any party under key project agreements (such as a PPA or a fuel supply agreement) will also constitute a default under the project’s term loan or other financing arrangement. Failure to comply with the terms of these term loans or other financing arrangements, or events of default thereunder, may prevent cash distributions by the particular project(s) to us and may entitle the lenders to demand repayment and/or enforce their security interests, which could have a material adverse effect on our business, results of operations and financial condition. In addition, failure to comply with the terms, restrictions or obligations of any of our revolving credit facility, convertible debentures or Senior Secured Credit Facility, or the preferred shares of the Partnership, or any other financing arrangements, borrowings or indebtedness, or events of default thereunder, may entitle the lenders to demand repayment, accelerate related debt as well as any other debt to which a cross-default or cross-acceleration provision applies and/or enforce their security interests, which could have a material adverse effect on our business, results of operations and financial condition. In addition, if and for as long as we have failed to declare, or are in arrears on the payment of, dividends on the Series 1 Shares, the Series 2 Shares or the Series 3 Shares, the Partnership will not make any distributions on its limited partnership units. Additionally, if our lenders under our indebtedness demand payment, we may not, at that time, have sufficient cash and cash flows from operating activities to repay such indebtedness.
Our failure to refinance or repay any indebtedness when due could constitute a default under such indebtedness and restrict our ability to take certain actions, including paying dividends. In addition, any covenant breach or event of default could harm our credit rating and our ability to obtain additional financing on acceptable terms or at all. The occurrence of any of these events could have a material adverse effect on our business, results of operations, financial condition and liquidity.
Exchange rate volatility may affect our available cash flow and results of operations
Our dividend payments on our preferred shares and our interest payments on some of our corporate-level long-term debt and convertible debentures are denominated in Canadian dollars. Conversely, some of our projects’ revenues and expenses are denominated in U.S. dollars. Our Canadian dollar denominated debt instruments are revalued at each balance sheet date based on the U.S. dollar to Canadian dollar foreign exchange rate at the balance sheet date, with changes in the value of the debt recorded in the consolidated statements of operations. The U.S. dollar to Canadian dollar foreign exchange rate has been volatile in recent years, which in turn creates volatility in our results due to the
revaluation of our Canadian dollar-denominated debt. Although we currently generate sufficient revenues in Canadian dollars to fund our Canadian dollar obligations, future exchange rate volatility or changes to our Canadian dollar revenues could expose us to currency exchange rate risks, against which we do not typically hedge. Any arrangements to mitigate this exchange rate risk may not be sufficient to fully protect against this risk. If hedging transactions do not fully protect against this risk, changes in the currency exchange rate between U.S. and Canadian dollars could adversely affect our available cash flow and results of operations.
A downgrade in our credit rating or in the credit rating of our outstanding debt securities, or any deterioration in credit quality could negatively affect our ability to access capital and our ability to hedge, and could trigger termination rights under certain contracts
A downgrade in our credit rating, a downgrade in the credit rating of our outstanding debt securities, or any deterioration in credit quality could adversely affect our ability to renew existing, or obtain access to new, credit facilities and could increase the cost of such facilities, restrict access to our revolving credit facility and/or trigger termination rights or enhanced disclosure requirements under certain contracts to which we are a party. Any downgrade of our corporate credit rating could also cause counterparties to require us to post letters of credit or other additional collateral, make cash prepayments, or obtain a guarantee agreement, all of which would expose us to additional costs and/or could adversely affect our ability to comply with covenants or other obligations under any of our revolving credit facility, convertible debentures or unsecured notes or any other financing arrangements, borrowings or indebtedness (or could constitute an event of default under any such financing arrangements, borrowings or indebtedness that we may be unable to cure), any of which could have a material adverse effect on our business, results of operations and financial condition.
Changes in our creditworthiness may affect the value of our common shares
Changes to our perceived creditworthiness and ability to meet our required covenants on an on-going basis may affect the market price or value and the liquidity of our common shares.
The future issuance of additional common shares could dilute existing shareholders
From time to time, we may decide to issue additional common shares, redeem outstanding debt for common shares, or repay outstanding principal amounts under existing debt by issuing common shares. We may also, from time to time, decide to issue common shares to meet strategic objectives or in connection with acquiring assets or pursuing broader strategic options. We also have the option to convert our convertible debentures to common shares at their respective maturity dates. The issuance of additional common shares may have a dilutive effect on shareholders and may adversely impact the price of our common shares.
Volatile capital and credit markets may adversely affect our ability to raise capital on favorable terms and may adversely affect our business, results of operations, financial condition and cash flows
Disruptions in the capital and credit markets in the United States, Canada or abroad can adversely affect our ability to access the capital markets. Our access to funds under our credit facility is dependent on the ability of the banks that are parties to the facility to meet their funding commitments. Those banks may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. Longer-term disruptions in the capital and credit markets as a result of turmoil in the financial services industry, volatility in securities trading markets and general economic conditions could result in an inability to support our liquidity needs, including, but not limited to, the service of our debt obligations or financing of internal or external growth opportunities. Currently, because we no longer qualify as a “well-known seasoned issuer,” which previously enabled us to, among other things, file automatically effective shelf registration statements, even if we were able to access the capital markets, any attempt to do so could be more expensive or subject to significant delays. See “-We may not generate sufficient cash flow to service our debt obligations or implement our business plan, including financing internal or external growth opportunities.”
Our ability to arrange for financing on a recourse or non-recourse basis and the costs of such capital are dependent on numerous factors, some of which are beyond our control, including:
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general industry, economic and capital market conditions;
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the availability of bank credit;
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investor confidence;
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our financial condition, performance and prospects as well as companies in our industry or similar financial circumstances; and
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changes in tax and securities laws which are conducive to raising capital.
Should future access to capital not be available to us, either as a result of market conditions or our financial condition, we may not be able to service our debt obligations or finance internal or external growth opportunities, any of which would adversely affect our business, results of operations and financial condition.
We have guaranteed the performance of some of our subsidiaries, which may result in substantial costs in the event of non-performance
We have issued certain guarantees of the performance of some of our subsidiaries in certain situations, which obligates us to perform in the event that the subsidiaries do not perform. In the event of non-performance by the subsidiaries, we could incur substantial cost to fulfill our obligations under these guarantees. Such performance guarantees could have a material impact on our business, results of operations, financial condition and cash flows. See Notes 11 and 25 to the consolidated financial statements for information on our guarantee obligations.
We have anti-takeover protections that may discourage, delay or prevent a change in control that could benefit our shareholders.
The Business Corporations Act (British Columbia) and our Articles of Continuance contain provisions that could make it more difficult for a third party to acquire us without the consent of our Board of Directors (“Board”). These provisions include:
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As a notice of meeting is required to include certain particulars in the case where a shareholder meeting is being requisitioned by shareholders, our Board must be given advance notice regarding special business that is to be brought by such requisitioning shareholders before the shareholder meeting. For special business, advance notice describing the special business to be discussed at the meeting must be provided and that notice must include any documents to be approved or ratified as an addendum or state that such document will be available for inspection at our records office or other reasonably accessible location;
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Under the BCBCA, shareholders may make proposals for matters to be considered at the annual general meeting of shareholders, provided that such shareholders represent at least 1% of the voting shares of a company or such shares have a fair market value of at least Cdn$2,000. Such proposals must be sent to us in advance of any proposed meeting by delivering a timely written notice in proper form to our registered office. The notice must include information on the business the shareholder intends to bring before the meeting. These provisions could have the effect of delaying until the next shareholder meeting shareholder actions that are favored by the holders of a majority of our outstanding voting securities; and
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Casual vacancies on our Board can be approved prior to the next annual meeting of shareholders by the directors of our Board of Directors.
If we experience a change of control, unless we elect to make a voluntary prepayment of the term loan under the Senior Secured Credit Facilities, the Partnership will be required to offer each electing lender to prepay such lender’s
term loans under the Senior Secured Credit Facilities at a price equal to 101% of par. Additionally, a change in control will permit holders of our convertible debentures to require that we purchase the debentures upon the conditions set forth in the respective indenture governing the debentures, which may discourage, delay or prevent a change of control or the acquisition of a substantial block of our common shares. In addition, some of our PPAs or other commercial agreements may contain change of control provisions.
We have a shareholder rights plan in place that may delay or prevent a change of control or the acquisition of a substantial block of our common shares and may make any future unsolicited acquisition attempt more difficult. Under the rights plan:
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The rights will generally become exercisable if a person or group acquires 20% or more of Atlantic Power’s outstanding common shares (unless such transaction is a “permitted bid” or a transaction to which the application of the shareholders rights plan has been waived pursuant to the terms of the plan) and thus becomes an “acquiring person.” A “permitted bid” is an offer pursuant to which, among other things, such person or group agrees to hold the offer open to all shareholders for a period longer than the statutorily required period;
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Each right, when exercisable, will entitle the holder, other than the “acquiring person,” to acquire shares of Atlantic Power’s common shares at a significant discount to the then-prevailing market price; and
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As a result, the rights plan may cause substantial dilution to a person or group that becomes an “acquiring person” and may discourage or delay a merger or acquisition that shareholders may consider favorable, including transactions in which shareholders might otherwise receive a premium for their shares.
Our common shares may not continue to be qualified investments under Canadian tax laws
There can be no assurance that our common shares will continue to be qualified investments under relevant Canadian tax laws for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans, registered education savings plans, registered disability savings plans and tax-free savings accounts. Canadian tax laws impose penalties for the acquisition or holding of non-qualified or ineligible investments.
We are subject to Canadian tax
As a Canadian corporation, we are generally subject to Canadian federal, provincial and other taxes, and dividends paid by us are generally subject to Canadian withholding tax if paid to a shareholder that is not a resident of Canada. We hold promissory notes from our U.S. holding companies (the “Intercompany Notes”) and are required to include, in computing our taxable income, interest on the Intercompany Notes.
Canadian federal income tax laws and policies could be changed in a manner which adversely affects holders of our common shares
There can be no assurance that Canadian federal income tax laws and Canada Revenue Agency administrative policies respecting the Canadian federal income tax consequences generally applicable to us, to our subsidiaries, or to a U.S. or Canadian holder of common shares will not be changed in a manner which adversely affects holders of our common shares.
Our current structure may be subject to additional U.S. federal income tax liability
Under our current structure, our subsidiaries that are incorporated in the United States are subject to U.S. federal income tax on their income at regular corporate rates (currently as high as 35%, plus state and local taxes), and two of our U.S. holding companies will claim interest deductions with respect to the Intercompany Notes in computing its income for U.S. federal income tax purposes. To the extent any interest expense under the Intercompany Notes is disallowed or is otherwise not deductible, the U.S. federal income tax liability of our U.S. holding companies will increase, which could materially affect the after-tax cash available to distribute to us.
We received advice from our U.S. tax counsel at the time of the issuance, based on certain representations by us and our U.S. holding companies and determinations made by our independent advisors, as applicable, that the Intercompany Notes should be treated as debt for U.S. federal income tax purposes. However, it is possible that the Internal Revenue Service (the “IRS”) could successfully challenge these positions and assert that any of these arrangements should be treated as equity rather than debt for U.S. federal income tax purposes or that the interest on such arrangements is otherwise not deductible. In this case, the otherwise deductible interest would be treated as non-deductible distributions and, in the case of the Intercompany Notes, may be subject to U.S. withholding tax to the extent our respective U.S. holding company had current or accumulated earnings and profits. The determination of debt or equity treatment for U.S. federal income tax purposes is based on an analysis of the facts and circumstances. There is no clear statutory definition of debt for U.S. federal income tax purposes, and its characterization is governed by principles developed in case law, which analyzes numerous factors that are intended to identify the nature of the purported creditor’s interest in the borrower.
Not all courts have applied this analysis in the same manner, and some courts have placed more emphasis on certain factors than other courts have. To the extent it were ultimately determined that our interest expense on the Intercompany Notes were disallowed, our U.S. federal income tax liability for the applicable open tax years would materially increase, which could materially affect the after-tax cash available to us to distribute. Alternatively, the IRS could argue that the interest on the Intercompany Notes exceeded or exceeds an arm’s length rate, in which case only the portion of the interest expense that does not exceed an arm’s length rate may be deductible and the remainder may be subject to U.S. withholding tax to the extent our U.S. holding companies had current or accumulated earnings and profits. We have received advice from independent advisors that the interest rate on these debt instruments was and is, as applicable, commercially reasonable under the circumstances, but the advice is not binding on the IRS.
Furthermore, our U.S. holding companies’ deductions attributable to the interest expense on the Intercompany Notes may be limited by the amount by which each U.S. holding company’s net interest expense (the interest paid by each U.S. holding company on all debt, including the Intercompany Notes, less its interest income) exceeds 50% of its adjusted taxable income (generally, U.S. federal taxable income before net interest expense, net operating loss carryovers, depreciation and amortization). Any disallowed interest expense may currently be carried forward to future years. In addition, if our U.S. holding companies do not make regular interest payments as required under these debt agreements, other limitations on the deductibility of interest under U.S. federal income tax laws could apply to defer and/or eliminate all or a portion of the interest deduction that our U.S. holding companies would otherwise be entitled to.
Our U.S. holding companies have existing net operating loss carryforwards that we can utilize to offset future taxable income. Some of these loss carryforwards are subject to an annual limitation on their use. While we expect these losses will be available to us as a future benefit, in the event that they are successfully challenged by the IRS or subject to additional future limitations, including, but not limited to, as a result of implementation of any of the potential options we are considering, our ability to realize these benefits may be limited. A reduction in our net operating losses, or additional limitations on our ability to use such losses, may result in a material increase in our future income tax liability.
Atlantic Power Preferred Equity Ltd. is subject to Canadian tax, as is Atlantic Power’s income from the Partnership
As a Canadian corporation, we are generally subject to Canadian federal, provincial and other taxes. See “Risks Related to Our Structure-We are subject to Canadian tax.” We are required to include in computing our taxable income any income earned by the Partnership. In addition, Atlantic Power Preferred Equity Ltd., a subsidiary of the Partnership, is also a Canadian corporation and is generally subject to Canadian federal, provincial and other taxes. Atlantic Power Preferred Equity Ltd. is liable to pay its applicable Canadian taxes.
We are subject to significant pending civil litigation, which if decided against us, could require us to pay substantial judgments or settlements and incur expenses that could have a material adverse effect on our business, results of operations, financial condition and liquidity.
Litigation may be time consuming, expensive and distracting from the conduct of our daily business. Due to the nature of these proceedings, the lack of precise damage claims and the type of claims we are subject to, we are unable to
determine the ultimate or maximum amount of monetary liability or financial impact, if any, to us in these legal matters, which unless otherwise described in "Item 3. Legal Proceedings", seek damages from the defendants of material or indeterminate amounts. As a result, we are also unable to reasonably estimate the possible loss or range of losses, if any, arising from these litigations. Although we are unable at this time to estimate what our ultimate liability in these matters may be, it is possible that we will be required to pay substantial judgments or settlements and incur expenses that could have a material adverse effect on our business, results of operations, financial condition and liquidity. We intend to defend vigorously against these actions. For additional information with respect to these unresolved matters, see "Item 3. Legal Proceedings".
Risks Related to Our Business and Our Projects
The expiration or termination of our power purchase agreements could have a material adverse impact on our business, results of operations and financial condition
Power generated by our projects, in most cases, is sold under PPAs that expire at various times. Currently, our PPAs are scheduled to expire between December 31, 2017 and December 31, 2037. Approximately 25% of our projects, on a net MW basis, and 33% on a Project Adjusted EBITDA basis, have PPAs that will expire in the next five years, including North Bay, Kapuskasing, Calstock, Williams Lake, Oxnard, North Island, Naval Training Center, Naval Station and Kenilworth. See Item 1. Business-Our Organization and Segments for details about our projects’ PPAs and related expiration dates. In addition, these PPAs may be subject to termination prior to expiration in certain circumstances, including default by the project. When a PPA expires or is terminated, it may be difficult for us to secure a new PPA on acceptable terms or timing, if at all, the price received by the project for power under subsequent arrangements may be reduced significantly, or there may be a delay in securing a new PPA until a significant time after the expiration of the original PPA at the project. It is possible that subsequent PPAs may not be available at prices that permit the operation of the project on a profitable basis. If this occurs, the affected project may temporarily or permanently cease operations and the value of the project may be impaired such that we would be required to record an impairment loss under applicable accounting rules. See “-Impairment of goodwill or long-lived assets could have a material adverse effect on our business, results of operations and financial condition”.
The loss of significant PPAs, our inability to secure new PPAs on favorable terms or at all, or the breach by the other parties to such contracts that prevents us from fulfilling our obligations thereunder, could have a material adverse impact on our business, results of operations and financial condition.
Our projects depend on their electricity and thermal energy customers and there is no assurance that these customers will perform their obligations or make required payments
Each of our projects relies on one or more PPAs, steam sales agreements or other agreements with one or more utilities or other customers for a substantial portion of its revenue. At times, we rely on a single customer or a limited number of customers to purchase all or a significant portion of a project’s output. In 2015, the largest customers of our power generation projects, including projects recorded under the equity method of accounting, are IESO, San Diego Gas & Electric, and BC Hydro which purchase approximately 29%, 11% and 10%, respectively, of the net electric generation capacity of our projects. If a customer stops purchasing output from our power generation projects or purchases less power than anticipated, such customer may be difficult to replace, if at all. Further concentration of our customers would increase our dependence on any one customer. Our cash flows and results of operations, including the amount of cash available to make payments on our indebtedness, are highly dependent upon customers under such agreements fulfilling their contractual obligations. There is no assurance that these customers will perform their contractual obligations or make required payments.
Further, our customers generally have investment-grade credit ratings, as measured by Standard & Poor’s. Customers that have assigned ratings at the top end of the range have, in the opinion of the rating agency, the strongest capability for payment of debt or payment of claims, while customers at the bottom end of the range have the weakest capacity. Agency ratings are subject to change, and there can be no assurance that a ratings agency will continue to rate the 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.
Certain of our projects are exposed to fluctuations in the price of electricity, which may have a material adverse effect on the operating margin of these projects and on our business, results of operations and financial condition
Those of our projects operating without a PPA or with PPAs based on spot market pricing for some or all of their output will be exposed to fluctuations in the wholesale price of electricity. In addition, should any of the long-term PPAs expire or terminate, the relevant project will be required to either negotiate a new PPA or sell into the electricity wholesale market, in which case the prices for electricity will depend on market conditions at the time, which may not be favorable. The open market wholesale prices for electricity are very volatile. Long and short-term power prices may fluctuate substantially due to other factors outside of our control, including:
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changes in generation capacity in the electricity markets, including the addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation facilities, expansion or retirement of existing facilities or additional transmission capacity;
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electric supply disruptions, including plant outages and transmission disruptions;
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fuel transportation capacity constraints;
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weather conditions;
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changes in the demand for power or in patterns of power usage;
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development of new fuels and new technologies for the production or storage of power;
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development of new technologies for the production of natural gas;
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availability of competitively priced renewable fuel sources;
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available supplies of natural gas, crude oil and refined products, and coal;
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interest rate and foreign exchange rate fluctuation;
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availability and price of emission credits;
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geopolitical concerns affecting global supply of oil and natural gas;
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general economic conditions which impact energy consumption in areas where we operate; and
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power market, fuel market and environmental regulation and legislation.
The market price for electricity is affected by changes in demand for electricity. Factors such as economic slowdown, worse than expected economic conditions, milder than normal weather, the growth of energy efficiency and efforts aimed at energy conservation, among others, could reduce energy demand or significantly slow the growth in demand for electricity, thereby reducing the market price for electricity. A reduction in demand could contribute to conditions that no longer support the continued operation of certain power generation projects, which could adversely affect our results of operations through increased depreciation rates, impairment charges and accelerated future decommissioning costs, among others.
We are also exposed to market power prices at the Selkirk, Morris and Chambers projects. At Chambers, our utility customer has the right to sell a portion of the plant’s output into the spot power market if it is economical to do so,
and the Chambers project shares in the profits from these sales. In addition, during periods of low spot electricity prices the utility takes less generation, which negatively affects the project’s operating margin. At Morris, approximately 68% of the facility’s capacity is currently not contracted. The facility can generate and sell this excess capacity into the grid at market prices. If market prices do not justify the increased generation, the project has no requirement to sell any excess capacity. At Selkirk, none of the capacity of the facility is contracted and is therefore sold at market prices or not sold at all if market prices do not support the profitable operation of that portion of the facility. As a result, fluctuations in the price of electricity may have a material adverse effect on the operating margins of these facilities and on our business, results of operations and financial condition.
Our projects depend on third-party suppliers under fuel supply agreements, and increases in fuel costs may adversely affect the profitability of the projects
The amount of energy generated at the projects is highly dependent on suppliers under certain fuel supply agreements fulfilling their contractual obligations. The loss of significant fuel supply agreements or an inability or failure by any supplier to meet its contractual commitments may adversely affect our results.
Upon the expiration or termination of existing fuel supply agreements, we or our project operators will have to renegotiate these agreements or may need to source fuel from other suppliers. We may not be able to renegotiate these agreements or enter into new agreements on similar terms. There can be no assurance as to availability of the supply or pricing of fuel under new arrangements, and it can be very difficult to accurately predict the future prices of fuel. If our suppliers are unable to perform their contractual obligations or we are unable to renegotiate our fuel supply agreements, we may seek to meet our fuel requirements by purchasing fuel at market prices, exposing us to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price. Changes in market prices for natural gas, biomass, coal and oil may result from the following:
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weather conditions;
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seasonality;
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demand for energy commodities and general economic conditions;
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availability and price of emission credits;
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additional generating capacity;
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disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;
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availability and levels of storage and inventory for fuel stocks;
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natural gas, crude oil, refined products and coal production levels;
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changes in market liquidity;
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governmental regulation and legislation; and
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our creditworthiness and liquidity, and the willingness of fuel suppliers/transporters to do business with us.
Revenues earned by our projects may be affected by the availability, or lack of availability, of a stable supply of fuel at reasonable or predictable prices. The price we can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. To the extent possible, our projects attempt to match fuel cost setting mechanisms in supply agreements to energy payment formulas in the PPA and to provide for indexing or pass-through of fuel costs to customers. In cases where there is no pass-through of fuel costs, we often attempt to mitigate the market price risk of changing commodity costs through the use of hedging strategies. To the extent that costs are not matched well to PPA energy payments, pass-through of fuel costs is not allowed or hedging strategies are
unsuccessful, increases in fuel costs may adversely affect our results of operation. This may have a material adverse effect on our business, results of operations and financial condition. Our energy payments at our Orlando project are subject to fluctuations as the energy payments are comprised of a fuel component based on the cost of coal consumed at a nearby coal-fired generating station.
Our projects may not operate as planned
The ability of our projects to meet availability requirements and generate the required amount of power to be sold to customers under the PPAs are primary determinants of the amount of cash that will be distributed from the projects to us, and that will in turn be available for debt service obligations, investments in internal or external growth opportunities or funding of our operations. There is a risk of equipment failure due to wear and tear, more frequent and/or larger than forecasted downtimes for equipment maintenance and repair, unexpected construction delays, latent defect, design error or operator error, or force majeure events, among other things, which could adversely affect revenues and cash flow. Additionally, older equipment, even if maintained in accordance with good practices, is subject to operational failure, including events that are beyond our control, and may require unplanned expenditures to operate efficiently. Unplanned outages of generation facilities, including extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues or require us to incur significant costs as a result of obtaining replacement power from third parties in the open market to satisfy our obligations.
In general, our power generation projects transmit electric power to the transmission grid for purchase under the PPAs through a single step up transformer. As a result, the transformer represents a single point of vulnerability and may exhibit no abnormal behavior in advance of a catastrophic failure that could cause a temporary shutdown of the facility until a replacement transformer can be found or manufactured. To the extent that we suffer disruptions of plant availability and power generation due to transformer failures or for any other reason, there could be a material adverse effect on our business, results of operations and financial condition and the amount of available cash flow may be adversely affected.
We provide letters of credit under our $210 million Revolving Credit Facility for contractual credit support at some of our projects. If the projects fail to perform under the related project-level agreements, the letters of credit could be drawn and we would be required to reimburse our senior lenders for the amounts drawn.
The effects of weather and climate change may adversely impact our business, results of operations and financial condition
Our operations are affected by weather conditions, which directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Conversely, moderate temperatures in winter or summer decrease heating or cooling electricity and gas demand and revenues. To the extent that weather is warmer in the summer or colder in the winter than assumed, we may require greater resources to meet our contractual commitments. These conditions, which cannot be accurately predicted, may have an adverse effect on our business, results of operations and financial condition by causing us to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.
To the extent climate change contributes to the frequency or intensity of weather-related events, our operations and planning process could be impacted, which may adversely impact our business, results of operations and financial condition.
Revenues from hydropower projects are highly dependent on suitable precipitation and associated weather conditions and in the absence of such suitable conditions, our hydropower projects may not meet anticipated production levels, which could adversely affect our forecasted revenues.
We own interests in four hydropower projects, which are subject to substantial resource risks. The energy and revenues generated at a hydro energy project are highly dependent on climatic conditions, particularly precipitation patterns, which are variable and difficult to predict for any given year. We base our investment decisions with respect to each hydro energy project on the historical stream flow records for the area. However, actual climatic conditions in any given year may not meet the historical averages which would impair our ability to meet anticipated production levels, which could adversely affect our forecasted revenues.
U.S., Canadian and/or global economic conditions and uncertainty could adversely affect our business, results of operations and financial condition
Our business may be affected by changes in U.S., Canadian and/or global economic conditions, including inflation, deflation, interest rates, availability of capital, consumer spending rates and the effects of governmental initiatives to manage economic conditions. Uncertainty about global economic conditions may cause consumers to alter behaviors that may directly or indirectly reduce energy spending, which could have a material adverse effect on demand for our product. Volatility in the financial markets and the deterioration of national and global economic conditions may have a material adverse effect on our business, results of operations and financial condition.
Financial markets can also be, and have been in the past, affected by concerns over U.S. fiscal policy, federal deficit and related budget and tax issues. These concerns continue to raise discussions relating to the stability of the long-term sovereign credit rating of the United States. Any actions taken by the U.S. federal government regarding the federal deficit or any action taken or threatened by ratings agencies, could significantly impact the global and U.S. economies and financial markets. Any such economic downturn could have a material adverse effect on our business, results of operations and financial condition.
Risks that are beyond our control, including but not limited to geopolitical crisis, acts of terrorism or related acts of war, natural disasters or other catastrophic events could have a material adverse effect on our business, results of operations, ability to raise capital and financial condition
Man-made events, such as acts of terror and governmental responses to acts of terror, could adversely affect general economic conditions, which could have a material impact on our business, results of operations and financial condition. Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other domestic targets. Our projects may be targets of terrorist activities, as well as events occurring in response to or in connection with them, that could cause environmental repercussions and/or result in full or partial disruption of the ability of the projects to generate and/or transmit electricity. Any such environmental repercussions or other disruption could result in a decline in energy consumption and significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our business, results of operations and financial condition.
Our projects could also be impacted by natural disasters, such as earthquakes, floods, lightning activity, hurricanes, tropical storms, winter storms, tornadoes, wind, seismic activity, more frequent and more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise and other related phenomena. Severe weather or other natural disasters could be destructive or otherwise disrupt our operations or compromise the physical or cyber security of our facilities, which could result in increased costs and could adversely affect our ability to manage our business effectively. We maintain standard insurance against catastrophic losses, which are subject to deductibles, limits and exclusions; however, our insurance coverage may not be sufficient to cover all of our losses. Additionally, future significant weather-related events, natural disasters and other similar events that have an adverse effect on the economy could have a material adverse effect on our business, results of operations, ability to raise capital and financial condition.
Our business faces significant operating hazards, natural disaster risks and other hazards such as fire and explosions and insurance may not be sufficient to cover all losses
Our business involves significant operating hazards related to the generation of electricity, including hazards related to acquiring, transporting and unloading fuel, operating large pieces of rotating equipment, structural collapse, machinery failure, and delivering electricity to transmission and distribution systems. In addition, we are exposed to natural disaster risks and other hazards such as fire and explosions. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, disruption of communication systems and technology, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being subject to various litigation matters, including regulatory and administrative proceedings, asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. While we believe that the projects maintain an amount of insurance coverage that is adequate and similar to what would be maintained by a prudent owner/operator of similar facilities, and are subject to deductibles, limits and exclusions which are customary or reasonable given the cost of procuring insurance, current operating conditions and insurance market conditions, there can be no assurance that such insurance will continue to be offered on an economically feasible basis, nor that all events that could give rise to a loss or liability are insurable or insured, nor that the amounts of insurance will at all times be sufficient to cover each and every loss or claim that may occur involving our assets or operations of our projects. Any losses in excess of those covered by insurance, which may include a significant judgment against any project or project operator, the loss of a significant permit or other approval or the imposition of a significant fine or penalty, could have a material adverse effect on our business, results of operations, financial condition and future prospects.
Our operations are subject to the provisions of various energy laws and regulations
Our business is subject to extensive Canadian and U.S. federal, state, provincial and local laws and regulations. Compliance with the requirements under these various regimes may cause us to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines and/or civil or criminal liability.
Generally, in the United States, our projects are subject to regulation by the FERC regarding the terms and conditions of wholesale service and rates, as well as by state regulators regarding the prudency of utilities entering into PPAs entered into by QF projects and the siting of the generation facilities. The majority of our generation is sold by QF projects under PPAs that required approval by state authorities.
The EP Act of 2005 also limited the requirement that electric utilities buy electricity from QFs in certain markets that have certain competitive characteristics, potentially making it more difficult for our current and future projects to negotiate favorable PPAs with these utilities.
If any project were to lose its status as a QF, it would lose its ability to make sales to utilities on favorable terms. Such project may no longer be entitled to exemption from provisions of Public Utility Holding Company Act (“PUHCA”) of 2005 or from certain provisions of the Federal Power Act and state law and regulations. Loss of QF status could also trigger defaults under covenants to maintain that status in the PPAs and project-level debt agreements, and if not cured within allowed cure periods, could result in termination of agreements, penalties or acceleration of indebtedness under such agreements. In such event, our business, results of operations and financial condition could be negatively impacted.
Notwithstanding their status as QFs and EWGs, our facilities remain subject to numerous FERC regulations, including those relating to power marketer status, approval of mergers, acquisitions and investments relating to utilities, and mandatory reliability rules and regulations delegated to NERC. Any violation of these rules and regulations could subject us to significant fines and penalties and negatively impact our business, results of operations and financial condition.
The EP Act of 2005 and other federal and state programs also may provide incentives for various forms of electric generation technologies, which may subsidize our competitors. The U.S. regulatory environment has undergone
significant changes in the last several years due to state and federal policies affecting wholesale competition and the creation of incentives for the addition of large amounts of new renewable energy generation and, in some cases, transmission. These changes are ongoing and we cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on our business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism as well as proposals to re-regulate the markets. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process. If competitive restructuring of the electric power markets is reversed, discontinued, or delayed, or new law or other future regulatory developments are introduced, our business, results of operations and financial condition could be negatively impacted.
Generally, in Canada, our projects are subject to energy regulation primarily by the relevant provincial authorities. In addition, our projects are subject to Canada’s corporate, commercial and other laws of general application to businesses. Our projects require licenses, permits and approvals which can be in addition to any required environmental permits. No assurance can be provided that we will be able to obtain, comply with and renew, as required, all necessary licenses, permits and approvals for these facilities. If we cannot comply with and renew as required all applicable licenses, permits and approvals, our business, results of operations and financial condition could be adversely affected.
Additionally, public policy mechanisms and favorable regulatory incentives in the United States and Canada, including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, renewable portfolio standards, and carbon trading plans, impact the viability of our renewable energy projects. As a result of budgetary constraints, political factors or otherwise, governments from time to time may review their policies that support renewable energy and consider actions to make the policies less conducive to the development and operation of renewable energy facilities. In the U.S., in December 2015, the federal renewable energy production and investment tax credits were extended but will begin to phase down in 2017 and 2020, respectively. Any reductions to, or the elimination of, governmental incentives that support renewable energy, or the imposition of additional taxes or other assessments on renewable energy, could result in a material adverse effect on our business, results of operations and financial condition.
The introductions of new laws, or other future regulatory developments, may have a material adverse impact on our business, operations or financial condition.
Risks with respect to the two Canadian provinces where we currently have projects are addressed further below.
(i) British Columbia
The Government of British Columbia has a number of specific statutes and regulations that govern the generation, transmission and distribution of electricity within British Columbia. Our projects in that province are subject to these laws. These statutes can be changed by act of the provincial legislature and the regulations may be changed by the provincial cabinet. Such changes could have a material effect on our projects.
The Utilities Commission Act (British Columbia) governs the BCUC, which is responsible for the regulation of British Columbia’s public energy utilities, which include publicly owned and investor-owned utilities (i.e., independent power producers). All contracts for electricity supply, including those between independent power producers and BC Hydro, must be filed with and approved by the BCUC as being “in the public interest.” The BCUC may hold a hearing in this regard. Furthermore, the BCUC may make rules govering conditions to be contained in agreements entered into by public utilities for electricity. Consequently, power procurement is controlled by the BCUC and, as a result, our potential contracts with BC Hydro may be subject to terms that adversely affect us.
The Clean Energy Act (British Columbia), which became law in 2010, sets out British Columbia’s energy objectives, one of which is the generation of at least 93% of the electricity in British Columbia from clean or renewable resources. BC Hydro is required to submit resource plans outlining how it will meet these objectives and requires the province to be electricity self-sufficient by 2016. BC Hydro is generally required to acquire all new power (beyond what
it already generates from existing BC Hydro plants) from independent power producers. Two of our three British Columbia projects currently sell all of their electricity to BC Hydro, and the third project sells substantially all of its electricity to BC Hydro. Therefore, changes to BC Hydro’s energy procurement policies and financial difficulties of or regulatory intervention in respect of BC Hydro and/or the province’s energy objectives could impact the market for electricity generated by our British Columbia projects, although BC Hydro is currently limited by regulation to undertaking efficiency improvements at its existing facilities and only undertaking development of new generation facilities/projects with BCUC approval. There is a risk that the regulatory regime could adversely affect the amount of power that BC Hydro purchases from our projects and the competitive environment or the price at which BC Hydro is willing to purchase power from our British Columbia projects.
(ii) Ontario
The government of Ontario has a number of specific statutes and regulations that govern our projects in that province. The statutes can be changed by act of the provincial legislature and the regulations may be changed by the provincial cabinet. Such changes could have a material effect on our projects.
In Ontario, the OEB is an administrative tribunal with authority to grant or renew, and set the terms for, licenses with respect to electricity generation facilities, including our projects. No person is permitted to own or operate a large or medium-scale electricity generation facility in Ontario without a license from the OEB. While all of our Ontario projects are currently licensed, the OEB has the authority to effectively modify the licenses by adopting “codes” that are deemed to form part of the licenses. Furthermore, any violations of the license or other irregularities in the relationship with the OEB can result in fines.
While the OEB provides reports to the Ontario Minister of Energy, it generally operates independently from the government. However, the Minister may issue policy directives (with Cabinet approval) concerning general policy and the objectives to be pursued by the OEB, and the OEB is required to implement such policy directives. Thus, the OEB’s regulation of our projects is subject to potential political interference, to a degree.
A number of other regulators and quasi-governmental entities play a role, including the IESO, Hydro One, the ESA and OEFC. All these agencies may affect our projects.
Noncompliance with federal reliability standards may subject us and our projects to penalties
Many of our operations are subject to the regulations of NERC, a self-regulatory non-governmental organization which has statutory responsibility to regulate bulk power system users and generation and transmission owners and operators. NERC groups the users, owners, and operators of the bulk power system into 17 categories, known as functional entities-e.g., Generator Owner, Generator Operator, Purchasing-Selling Entity, etc.-according to the tasks they perform. The NERC Compliance Registry lists the entities responsible for complying with federal mandatory reliability standards and the FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity found to be in noncompliance. Violations may be discovered or identified through self-certification, compliance audits, spot checking, self-reporting, compliance investigations by NERC (or a regional reliability organization) and the FERC, periodic data submissions, exception reporting, and complaints. The penalty that could be imposed for violating the requirements of the standards is a function of the Violation Risk Factor. Penalties for the most severe violations can reach as high as $1 million per violation, per day, and our projects could be exposed to these penalties if violations occur, which could have a material adverse effect on our business, results of operations and financial condition.
Our projects are subject to significant environmental and other regulations
Our projects are subject to numerous and significant federal, state, provincial and local laws, including statutes, regulations, by-laws, guidelines, policies, directives and other requirements governing or relating to, among other things: air emissions; discharges into water; ash disposal; the storage, handling, use, transportation and distribution of dangerous goods and hazardous, residual and other regulated materials, such as chemicals; the prevention of releases of hazardous materials into the environment; the prevention, presence and remediation of hazardous materials in soil and groundwater,
both on and off site; land use and zoning matters; and workers’ health and safety matters. Our facilities could experience incidents, malfunctions or other unplanned events that could result in spills or emissions in excess of permitted levels and result in personal injury, penalties and property damage. As such, the operation of our projects carries an inherent risk of environmental, health and safety liabilities (including potential civil actions, compliance or remediation orders, fines and other penalties), and may result in the projects being involved from time to time in administrative and judicial proceedings relating to such matters. We have implemented environmental, health and safety management programs designed to regularly improve environmental, health and safety performance, but there is no guarantee that such programs will fully and effectively eliminate the inherent risk of environmental, health and safety liabilities related to the operation of our projects.
Environmental laws and regulations have generally become more stringent over time, and this trend may continue. In the United States, the Clean Air Act and related regulations and programs of the Environmental Protection Agency extensively regulate the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds by power plants. In July 2011, the EPA issued its final Cross-State Air Pollution Rule (“CSAPR”), which replaces its prior Clean Air Interstate Rule and requires 27 states and the District of Columbia to curb emissions of sulfur dioxide and nitrogen oxides from power plants through participation in a cap and trade system or more aggressive state-by-state emissions limits. In November 2014, the EPA issued a ministerial rule setting a schedule for implementation of the CSAPR beginning in 2015. Other more stringent EPA air emission regulations currently being implemented include the more stringent national ambient air quality standards for sulfur dioxide, issued in June 2010, and for fine particulate matter, issued in December 2012. Additionally, EPA’s new mercury and air toxics emissions standards for power plants, issued in December 2011, are undergoing reconsideration after they were overturned by the Supreme Court. Meeting these new standards, when implemented, may have a material adverse impact on our business, results of operations and financial condition.
In December 2014, the EPA issued its final regulations governing disposal of coal ash in landfills and impoundments. The final rule affirmed the historic treatment of coal ash as non-hazardous solid waste but establishes new requirements governing structural integrity, groundwater protection, operating criteria, recordkeeping and reporting, and closure for such landfills and impoundments. We are currently assessing the increased compliance obligations and associated costs to our 40% owned coal-fired facility.
Similar increasingly stringent environmental regulations also apply to our projects in British Columbia and Ontario.
Significant costs may be incurred for either capital expenditures or the purchase of allowances under any or all of these programs to keep the projects compliant with environmental laws and regulations. Some of our projects’ PPAs do not allow for the pass-through of emissions allowance or emission reduction capital expenditure costs. If it is not economical to make those expenditures, it may be necessary to retire or mothball facilities, or restrict or modify our operations to comply with more stringent standards.
Our projects have obtained environmental permits and other approvals that are required for their operations. Compliance with applicable environmental laws, regulations, permits and approvals and material future changes to them could materially impact our businesses. Although we believe the operations of the projects are currently in material compliance with applicable environmental laws, licenses, permits and other authorizations required for the operation of the projects, and although there are environmental monitoring and reporting systems in place with respect to all the projects, there is no guarantee that more stringent laws will not be imposed, that there will not be more stringent enforcement of applicable laws or that such systems may not fail, which may result in material expenditures. Failure by the projects to comply with any environmental, health or safety requirements, or increases in the cost of such compliance, including as a result of unanticipated liabilities or expenditures for investigation, assessment, remediation or prevention, could result in additional expense, capital expenditures, restrictions and delays in the projects’ activities, the extent of which cannot be predicted and which could have a material adverse effect on our business, results of operations and financial condition.
If additional regulatory requirements are imposed on energy companies mandating limitations on greenhouse gas emissions or requiring efficiency improvements, such requirements may result in compliance costs that alone or in combination could make some of our projects uneconomical to maintain or operate
The EPA, other regulatory agencies, environmental advocacy groups and other organizations are focusing considerable attention on greenhouse gas emissions from power generation facilities and their potential role in climate change. In the United States, President Obama has declared action addressing climate change to be a major priority, and the EPA has taken several recent actions for the regulation of greenhouse gas emissions. See “Item 1. Business-Industry Regulation-Carbon Emissions.” We expect that additional EPA regulations, and possibly additional legislation and/or regulation by other regulatory authorities, may be issued, resulting in the imposition of additional limitations on greenhouse gas emissions or requiring efficiency improvements from fossil fuel-fired electric generating units.
There are also potential impacts on our natural gas businesses as greenhouse gas legislation or regulations may require greenhouse gas emission reductions from the natural gas sector and could affect demand for natural gas. Additionally, greenhouse gas requirements could result in increased demand for energy conservation and renewable products, as well as increase competition surrounding such innovation. Additionally, our reputation could be damaged due to public perception surrounding greenhouse gas emissions at our power generation projects. Any such negative public perception could ultimately result in a decreased demand for electric power generation or distribution. Several regions of the United States and Canada have moved forward with greenhouse gas emission regulation.
Concerning our projects in British Columbia, regulatory restrictions stemming from the GGIRTA and the GGRCTA, and financial commitments arising in connection with the requirements under the CTA, could affect our ability to operate our projects in British Columbia and affect our profitability. Concerning our projects in Ontario, regulatory restrictions may arise in the event the government of Ontario implements its plans for a carbon emissions cap and trade system, proposed to take effect in January 2017. This could affect our ability to operate our projects in Ontario and affect our profitability.
All of our subject generating facilities have complied on a timely basis with the new EPA and Ontario greenhouse gas reporting requirements. Compliance with greenhouse gas emission reduction requirements may require increasing the energy efficiency of equipment at our natural gas projects, committing significant capital toward carbon capture and storage technology, purchase of allowances and/or offsets, fuel switching, and/or retirement of high-emitting projects and potential replacement with lower emitting projects. The cost of compliance with greenhouse gas emission legislation and/or regulation is subject to significant uncertainties due to the outcome of several interrelated assumptions and variables, including timing of the implementation of rules, required levels of reductions, allocation requirements of the new rules, the maturation and commercialization of carbon capture and storage technology, and the selected compliance alternatives. We cannot estimate the aggregate effect of such requirements on our business, results of operations, financial condition or our customers. However, such expenditures, if material, could make our generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect our business, results of operations and financial condition.
Impairment of goodwill or long-lived assets could have a material adverse effect on our results of operations and financial condition
As of December 31, 2015, we had $134.5 million of goodwill, which represented approximately 7.8% of our total assets on our consolidated balance sheets. Goodwill is not amortized, but is evaluated for impairment at least annually or more frequently if an event or change in circumstance occurs that would more likely than not reduce the fair value of a reporting unit below its carrying value. We could be required to, and have in the past, evaluated the potential impairment of goodwill outside of the required annual evaluation process if we experience situations, including but not limited to, sustained declines in market capitalization, deterioration in general economic conditions or our operating or regulatory environment, increased competitive environment, an increase in fuel costs (particularly when we are unable to pass-through the impact to customers), negative or declining cash flows, loss of a key contract or customer (particularly when we are unable to replace it on equally favorable terms), divestiture of a significant component of our business or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods. Additionally, goodwill
may be impaired if any acquisitions we make do not perform as expected. See Note 8 to the consolidated financial statements included in this Annual Report on Form 10-K.
Long-lived assets are initially recorded at acquisition cost and are amortized or depreciated over their estimated useful lives. Long-lived assets are evaluated for impairment only when impairment indicators are present whereas goodwill is evaluated for impairment on an annual basis or more frequently if potential impairment indicators are present. Otherwise, the recoverability assessment of long-lived assets is similar to the potential impairment evaluation of goodwill particularly as it relates to the identification of potential impairment indicators, and making estimates and assumptions to determine fair value, as described above.
Increasing competition could adversely affect our performance and the performance of our projects
The power generation industry is characterized by intense competition and our projects encounter competition from utilities, industrial companies and other independent power producers, in particular with respect to uncontracted output. In recent years, there has been increasing competition among generators for PPAs, and this has contributed to a reduction in electricity prices in certain markets where supply has surpassed demand plus appropriate reserve margins.
Further, changes and developments in technology, including fuel cells, microturbines, solar cells and other emerging technologies related to energy generation, distribution and consumption, may facilitate the entrance of new competitors, increase the supply of electricity, and reduce the cost of methods of producing power that we do not currently use or lower the price of or demand for energy. If these technologies became cost competitive, we could face increasing competition and the value of our generating facilities could be reduced.
In addition, we continue to confront significant competition for acquisition and investment opportunities and, to the extent that any opportunities are identified, we may be unable to effect acquisitions or investments on attractive terms, if at all. Increasing competition among participants in the power generation industry may adversely affect our performance and the performance of our projects. Further, a payout of a significant portion of our cash flow to service our debt may result in us not retaining a sufficient amount of cash to finance acquisition or investment opportunities and make other capital and operating expenditures. See “-Risk Related to Our Structure-We may not generate sufficient cash flow to service our debt obligations or implement our business plan, including financing internal or external growth opportunities.”
We have limited control over management decisions at certain projects
Six of our projects are not wholly-owned by us or we have contracted for their operations and maintenance, and in some cases we have limited control over the operation of the projects. Although we generally prefer to acquire projects where we have control, we may make acquisitions in non-control situations to the extent that we consider it advantageous to do so and consistent with regulatory requirements and restrictions, including the Investment Company Act of 1940. Third-party operators operate six of our projects. As such, we must rely on the technical and management expertise of these third-party operators although typically we negotiate to obtain positions on a management or operating committee if we do not own 100% of a project. To the extent that such third-party operators do not fulfill their obligations to manage the operations of the projects or are not effective in doing so, our cash flow may be adversely affected. The approval of third-party operators also may be required for us to receive distributions of funds from projects or to transfer our interest in projects. Our inability to control fully certain projects could have an adverse effect on our business, results of operations and financial condition.
We may face significant competition for acquisitions and may not be able to finance or otherwise pursue, execute or successfully integrate acquisitions or new business initiatives
To the extent identification of and pursuit of acquisition opportunities forms a part of our strategy, we may be unable to identify attractive acquisition candidates in the power industry in the future, and we may not be able to make acquisitions on an accretive basis or at all, or be sure that such acquisitions, if any, will be successfully integrated into our existing operations. In addition, a payout of a significant portion of our cash flow to service our debt obligations, may result in us not retaining a sufficient amount of cash to finance any acquisition or other growth opportunities, to the
extent any such acquisition or other opportunities are available to us. As a result, we may have to forego such opportunities, even if they would otherwise be necessary or desirable, if we do not find alternative sources of financing for such opportunities to make cash available to us. In addition, even if we are able to find alternative sources of financing for such opportunities, we may be precluded from pursuing an otherwise attractive acquisition or investment if the projected short-term cash flow from the acquisition or investment is not adequate to service the capital raised to fund such acquisition or investment. This could limit our flexibility in planning for, or reacting to, changes in our business and industry, placing us at a competitive disadvantage compared to our competitors.
Although electricity demand is expected to grow, creating the need for more generation, such growth is expected to occur at a slower rate. The U.S. power industry is continuing to undergo consolidation and may present attractive acquisition opportunities but we are likely to confront significant competition for those opportunities and, to the extent that any opportunities are identified, we may be unable to effect acquisitions or investments.
Any acquisition, investment or new business initiative may involve potential risks, including an increase in indebtedness, the inability to successfully integrate operations, the potential disruption of our ongoing business, the diversion of management’s attention from other business concerns, inadequate return on capital and the possibility that we pay more than the acquired company or interest is worth. There may also be liabilities that we fail to discover, or are unable to discover, in our due diligence prior to the consummation of an acquisition or prior to launching an initiative or entering a market. We may not be indemnified for some or all of these liabilities in an acquisition transaction.
Our equity interests in certain projects may be subject to transfer restrictions
The partnership or other agreements governing some of the projects may limit a partner’s ability to sell its interest. Specifically, these agreements may prohibit any sale, pledge, transfer, assignment or other conveyance of the interest in a project without the consent of the other partners. In some cases, other partners may have rights of first offer or rights of first refusal in the event of a proposed sale or transfer of our interest. These restrictions may limit or prevent us from managing our interests in these projects in the manner we see fit, and may have an adverse effect on our ability to sell our interests in these projects at the prices we desire. See “-Risks Related to Our Structure-We cannot provide any assurance regarding the outcome or impact on our business of any potential options we are considering.”
Our projects are exposed to risks inherent in the use of derivative instruments
We and our projects may use derivative instruments, including futures, forwards, options and swaps, to manage commodity and financial market risks. These activities, though intended to mitigate price volatility, expose us to other risks. In the future, the project operators could recognize financial losses on these arrangements, including as a result of volatility in the market values of the underlying commodities, if a counterparty fails to perform under a contract or upon the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear the transactions. If actively quoted market prices and pricing information from external sources are not available, the valuation of these contracts would involve judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
Most of these contracts are recorded at fair value with changes in fair value recorded currently in the statement of operations, resulting in significant volatility in our income (loss) (as calculated in accordance with GAAP) that does not significantly affect current period cash flows or the underlying risk management purpose of the derivative instruments. As a result, we may be unable to accurately predict the impact that our risk management decisions may have on our quarterly and annual income (loss) (as calculated in accordance with GAAP).
If the values of these financial contracts change in a manner that we do not anticipate, or if a counterparty fails to perform under a contract, it could harm our business, results of operations, financial condition and cash flows. We have executed natural gas swaps to reduce our risks to changes in the market price of natural gas, which is the fuel consumed at many of our projects. Due to decreases in natural gas prices, we have incurred losses on these natural gas swaps. We execute these swaps only for the purpose of managing risks and not for speculative trading.
We do not typically hedge the entire exposure of our operations against commodity price volatility. To the extent we do not hedge against commodity price volatility, our business, results of operations and financial condition may be improved or diminished based upon movement in commodity prices.
Certain employees are subject to collective bargaining
A number of our plant employees, from one plant in British Columbia and four plants in Ontario are subject to collective bargaining agreements. These agreements expire periodically and we may not be able to renew them without a labor disruption or without agreeing to significant increases in labor costs. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on our business, results of operations and financial condition.
Our Pension Plan may require additional future contributions
Certain of our employees in Canada are participants in a defined benefit pension plan that we sponsor. As of December 31, 2015, our pension plan was at a deficit on a going concern basis, which measures its funded status on the basis that the plan will continue to operate indefinitely. The additional amount of future contributions to our defined benefit plan will depend upon asset returns and a number of other factors and, as a result, the amounts we will be required to contribute in the future may vary. Cash contributions to the plan will reduce the cash available for our business.
Hostile cyber intrusions could severely impair our operations, lead to the disclosure of confidential information, damage our reputation and otherwise have an adverse effect on our business, results of operations and financial condition
A cyber intrusion is considered to be any adverse event that threatens the confidentiality, integrity or availability of our information resources. More specifically, a cyber intrusion is an intentional attack or an unintentional event that can include gaining unauthorized access to systems to disrupt operations, corrupt data, steal confidential information, and impact our ability to make collections or otherwise impact our operations. We are dependent on various information technologies throughout our company and our projects to carry out multiple business activities. Further, the computer systems that run our facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. and/or Canadian bulk power system or our operations could view our computer systems, software or networks as attractive targets for cyber attack. In addition, our business requires that we collect and maintain confidential employee and shareholder information, which is subject to the risk of electronic theft or loss.
A successful cyber attack, such as unauthorized access, malicious software or other violations on the systems that control generation and transmission at our projects could severely disrupt business operations, diminish competitive advantages through reputation damages and increase operational costs. The breach of certain business systems could affect our ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. For these reasons, a significant cyber incident could materially and adversely affect our business, results of operations and financial condition.
Failure to comply with the U.S. Foreign Corrupt Practices Act and/or the Canadian Corruption of Foreign Public Officials Act could subject us to, among other things, penalties and legal expenses that could harm our reputation and have a material adverse effect on our business, results of operations and financial condition
We are subject to anti-corruption laws and regulations including the U.S. Foreign Corrupt Practices Act (“FCPA”) and the Canadian Corruption of Foreign Public Officials Act (the “CFPOA”), which generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business and/or other benefits. In addition, the FCPA imposes accounting standards and requirements on U.S. publicly traded corporations and their foreign affiliates, which are intended to prevent the diversion of corporate funds to the payment of bribes and other improper payments, and to prevent the establishment of “off books” slush funds from which improper payments can be made (similar provisions have been proposed to be added to the CFPOA). The
Securities and Exchange Commission (the “SEC”) has increased its enforcement of the FCPA during the past several years. In recent years, enforcement of the CFPOA in Canada has also increased and can be attributed, in part, to the establishment of the Royal Canadian Mounted Police’s International Anti-Corruption Unit in 2008. Although we have implemented policies and procedures designed to ensure that we, our employees and other intermediaries comply with the FCPA and/or the CFPOA, there is no assurance that such policies or procedures will work effectively all of the time or protect us against liability under the FCPA and/or the CFPOA for actions taken by our employees and other intermediaries with respect to our business or any businesses that we may acquire. If we are not in compliance with the FCPA and/or the CFPOA, we may be subject to criminal penalties pursuant to the CFPOA and/or criminal and civil penalties and other remedial measures pursuant to the FCPA, including changes or enhancements to our procedures, policies and control, as well as potential personnel change and disciplinary actions, which could have an adverse impact on our business, results of operations and financial condition.
Our success depends in part on our ability to retain, motivate and recruit executives and other key employees, and failure to do so could negatively affect us
Our success depends in part on our ability to retain, recruit and motivate key employees who have experience in our industry. Experienced employees in the power industry are in high demand and competition for their talents can be intense. Further, an aging work force in the power industry necessitates recruiting, retaining and developing the next generation of leadership. A failure to attract and retain executives and other key employees with specialized knowledge in power generation could have an adverse impact on our business, results of operations and financial condition because of the difficulty of promptly finding qualified replacements. See “-Risks Related to our Structure-Our recent management changes may impact our business plan.”
As a result of the sale of our Wind Projects, our business has become more concentrated, subjecting it to increased risk from each individual portion of the business
As a result of the sale of the Wind Projects on June 26, 2015, our operations have become more concentrated in our remaining East U.S., West U.S. and Canada segments, our portfolio of projects has become less diversified geographically and by fuel type, we have fewer renewable energy projects in our portfolio and our customer base is more concentrated. As a result, each of the risks that affected our projects prior to the sale of the Wind Projects, including, without limitation, our exposure to market prices of electricity and risks associated with equipment failure or frequent and/or larger than forecasted downtimes for equipment maintenance and repair, will now pose a greater risk to our overall business, financial condition and results of operations. Further, new laws or other regulatory developments that favor renewable energy and in particular, wind energy, may have a more significant adverse impact on our business than in the past. In addition, approximately 25% of our PPAs on a MW-weighted basis are scheduled to expire over the next five years, beginning in December 2017, and our weighted average remaining PPA life after the close of the sale of our Wind Project is approximately 8 years, down from 10 years previously. This increases our reliance on each of our existing PPAs and the potential adverse effect that could result from the expiration or termination of any single PPA. In addition, the increased concentration of our business in our remaining East U.S, West U.S. and Canada segments also increases our dependence on our remaining customers. For the year ended December 31, 2015, OEFC, San Diego Gas & Electric and BC Hydro accounted for 29%, 11% and 10%, respectively, of our revenue. If any such customer stops purchasing output from our power generation projects or purchases less power than anticipated, such customer may be difficult to replace, if at all, which may adversely impact our business.
We reported a material weakness in our internal control over financial reporting, which if not remedied, could continue to adversely affect our internal controls and financial reporting and could lead to materially inaccurate financial reports.
In connection with our management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2015, we identified a material weakness in our internal control over financial reporting, as described in "Item 9A. Controls and Procedures." Although we believe we are taking the steps necessary to remediate the material weakness, we cannot assure you that the processes, procedures and controls we implement will result in full remediation of the material weakness. Failure to remediate the material weakness, or additional material weaknesses in our internal control over financial reporting, could result in material misstatements in our financial statements or cause
us to fail to timely meet our reporting obligations. The occurrence of these events could in turn potentially negatively impact our share price or divert management’s attention.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
We have included descriptions of the locations and general character of our principal physical operating properties, including an identification of the segments that use such properties, in “Item 1. Business,” which is incorporated herein by reference. A significant portion of our equity interests in the entities owning these properties is pledged as collateral under our Senior Secured Credit Facilities or under non-recourse operating level debt arrangements.
Our principal executive office is located at 3 Allied Drive Suite 220, Dedham, Massachusetts under a lease that expires in 2019.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Shareholder class action lawsuits
Massachusetts District Court Actions
On March 8, 14, 15 and 25, 2013 and April 23, 2013, five purported securities fraud class action complaints were filed by alleged investors in Atlantic Power common shares in the United States District Court for the District of Massachusetts (the “District Court”) against Atlantic Power and Barry E. Welch, our former President and Chief Executive Officer and a former Director of Atlantic Power, in each of the actions, and, in addition to Mr. Welch, some or all of Patrick J. Welch, our former Chief Financial Officer, Lisa Donahue, our former interim Chief Financial Officer, and Terrence Ronan, our current Chief Financial Officer, in certain of the actions (the “Proposed Individual Defendants,” and together with Atlantic Power, the “Proposed Defendants”) (the “U.S. Actions”).
The District Court complaints differed in terms of the identities of the Proposed Individual Defendants they named, as noted above, the named plaintiffs, and the purported class period they alleged (July 23, 2010 to March 4, 2013 in three of the District Court actions and August 8, 2012 to February 28, 2013 in the other two District Court actions), but in general each alleged, among other things, that in Atlantic Power’s press releases, quarterly and year-end filings and conference calls with analysts and investors, Atlantic Power and the Proposed Individual Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power’s common share dividend that artificially inflated the price of Atlantic Power’s common shares. The District Court complaints assert claims under Section 10(b) and, against the Proposed Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended.
The parties to each District Court action filed joint motions requesting that the District Court set a schedule in the District Court actions, including: (i) setting a deadline for the lead plaintiff to file a consolidated amended class action complaint (the “Amended Complaint”), after the appointment of lead plaintiff and counsel; (ii) setting a deadline for Proposed Defendants to answer, file a motion to dismiss or otherwise respond to the Amended Complaint (and for subsequent briefing regarding any such motion to dismiss); and (iii) confirming that the Proposed Defendants need not answer, move to dismiss or otherwise respond to any of the five District Court complaints prior to the filing of the Amended Complaint. On May 7, 2013, each of six groups of investors (the “U.S. Lead Plaintiff Applicants”) filed a motion (collectively, the “U.S. Lead Plaintiff Motions”) with the District Court seeking: (i) to consolidate the five U.S. Actions (the “Consolidated U.S. Action”); (ii) to be appointed lead plaintiff in the Consolidated U.S. Action; and (iii) to have its choice of lead counsel confirmed. On May 22, 2013, three of the U.S. Lead Plaintiff Applicants filed oppositions to the other U.S. Lead Plaintiff Motions, and on June 6, 2013, those three Lead Plaintiff Applicants filed replies in support of their respective motions. On August 19, 2013, the District Court held a status conference to address certain issues raised by the U.S. Lead Plaintiff Motions, entered an order consolidating the five U.S. Actions, and
directed two of the six U.S. Lead Plaintiff Applicants to file supplemental submissions by September 9, 2013. Both of those U.S. Lead Plaintiff Applicants filed the requested supplemental submissions, and then sought leave to file additional briefing. The Court granted those requests for leave and additional submissions were filed on September 13 and September 18, 2013.
On March 31, 2014, the Court entered an order consolidating the five individual U.S. Actions, appointing the Feldman, Shapero, Carter and Smith investor group (one of the six U.S. Lead Plaintiffs Applicants) as Lead Plaintiff and approving Lead Plaintiff’s selection of counsel. The Court also granted the parties’ joint motion regarding initial case scheduling and directed the parties to resubmit a proposed schedule that contains specific dates. In response to that directive, on April 7, 2014, Lead Plaintiff filed an application and proposed order, which sought an extension of the schedule contained in the joint motion. The application and proposed order requested that: (i) Lead Plaintiff be permitted to file an amended complaint on or before May 30, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or otherwise respond to the amended complaint on or before July 29, 2014, (iii) Lead Plaintiff be permitted to file an opposition, if any, on or before September 24, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead Plaintiff’s opposition on or before November 13, 2014. Proposed Defendants did not object to the schedule proposed by Lead Plaintiff. On May 29, 2014, Lead Plaintiff filed a renewed application and proposed order, which sought another extension of the schedule, and on June 3, 2014, Lead Plaintiff and the Proposed Defendants jointly filed a stipulation and proposed order requesting the following revised schedule: (i) Lead Plaintiff be permitted to file an amended complaint on or before June 6, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or otherwise respond to the amended complaint on or before August 5, 2014, (iii) Lead Plaintiff be permitted to file an opposition, if any, on or before October 6, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead Plaintiff’s opposition on or before November 20, 2014. On June 3, 2014, the Court entered an order setting this requested schedule.
On June 6, 2014, Lead Plaintiff filed the amended complaint (the “Amended Complaint”). The Amended Complaint names as defendants Barry E. Welch and Terrence Ronan (the “Individual Defendants”) and Atlantic Power (together with the Individual Defendants, the “Defendants”) and alleges a class period of June 20, 2011 to March 4, 2013 (the “Class Period”). The Amended Complaint makes allegations that are substantially similar to those asserted in the five initial complaints. Specifically, the Amended Complaint alleges, among other things, that in Atlantic Power’s press releases, quarterly and year-end filings and conference calls with analysts and investors, Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power’s common share dividend, which artificially inflated the price of Atlantic Power’s common shares during the class period. The Amended Complaint continues to assert claims under Section 10(b) and, against the Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended. It also asserts a claim for unjust enrichment against the Individual Defendants. In accordance with the schedule referenced above, Defendants filed their motion to dismiss the consolidated (the “Motion to Dismiss”) U.S. Action on August 5, 2014.
On September 30, 2014, citing Atlantic Power’s September 16, 2014 announcement of changes to its dividend and its President and CEO transition, Lead Plaintiff filed a motion (the “Extension Motion”) requesting a thirty-day extension of its October 6, 2014 deadline for filing its brief in opposition to the Motion to Dismiss, in which to determine whether to file a second amended complaint. On October 2, 2014, the Court entered an order (i) extending Lead Plaintiff’s deadline to file its opposition to the Motion to Dismiss to October 10, 2014 and (ii) requiring Defendants to file their opposition to the Extension Motion by October 2, 2014. In accordance with this order, on October 2, 2014, Defendants filed their opposition to the Extension Motion. On October 10, 2014, Lead Plaintiff filed its opposition to the Motion to Dismiss (the “Opposition”) and also filed a motion for leave to amend the Amended Complaint, attaching a proposed second amended complaint. On October 21, 2014, Lead Plaintiff and Defendants filed a joint scheduling motion requesting (i) November 7, 2014 as the deadline for Defendants to file their opposition to Lead Plaintiff’s motion for leave to amend the Amended Complaint; (ii) November 24, 2014 as the deadline for Defendants to file their reply in further support of the Motion to Dismiss; and (iii) November 24, 2014 as the deadline for Lead Plaintiff to file its reply in further support of its motion for leave to amend the Amended Complaint. On October 22, 2014, the Court entered an order setting this requested schedule. Pursuant to that order, the Motion to Dismiss and Extension Motion were fully briefed on November 24, 2014. On January 22, 2015, the Court held oral argument on the Motion to Dismiss and Extension Motion.
On January 30, 2015, Lead Plaintiff filed a motion for leave to file a supplemental submission in opposition to Defendants’ motion to dismiss (the “Motion for Leave”). The Court denied the Motion for Leave in an order entered on February 5, 2015, but permitted Lead Plaintiff to submit a brief letter identifying supplemental authorities. Lead Plaintiff filed that letter on February 9, 2015, and Defendants filed a response on February 10, 2015.
On March 13, 2015, the District Court entered an order granting Defendants’ motion to dismiss and denying Lead Plaintiff’s motion to amend the Amended Complaint, and on March 18, 2015, the District Court entered an order dismissing the Amended Complaint with prejudice.
On April 16, 2015, Lead Plaintiff filed a notice of appeal to the United States Court of Appeals for the First Circuit (the “First Circuit”). On August 19, 2015, Lead Plaintiff filed with the First Circuit its brief appealing the dismissal of its securities fraud claims.
On September 4, 2015, while appellate proceedings were still on-going, Lead Plaintiff filed with the District Court a Rule 60(b)(2) motion to vacate the judgment based on evidence cited in the Ontario Superior Court’s decision dismissing the Canadian action (for more information on that litigation, see below under “Canadian Actions”). On September 17, 2015, Atlantic Power opposed Lead Plaintiff’s motion.
On September 18, 2015, Lead Plaintiff requested a stay of the appellate proceedings in the First Circuit pending resolution of the District Court’s decision on its Rule 60(b)(2) motion. On September 21, 2015, Atlantic Power opposed Lead Plaintiff’s request for a stay and tendered to the First Circuit its opposition brief to Lead Plaintiff’s appeal. On October 5, 2015, the First Circuit granted Lead Plaintiff’s request for a stay in the appellate proceeding pending the District Court’s decision on the Rule 60(b)(2) motion.
On October 21, 2015, the District Court entered an order denying Lead Plaintiff’s Rule 60(b)(2) motion to vacate the judgment.
On October 29, 2015, pursuant to Federal Rule of Appellate Procedure 42(b), the parties jointly stipulated to the voluntary dismissal of the appeal before the First Circuit with prejudice. On November 30, 2015, the First Circuit ordered that the case be voluntarily dismissed.
Canadian Actions
On March 19, 2013, April 2, 2013 and May 10, 2013, three notices of action relating to Canadian securities class action claims against the Proposed Defendants were also issued by alleged investors in Atlantic Power common shares, and in one of the actions, holders of Atlantic Power convertible debentures, with the Ontario Superior Court of Justice in the Province of Ontario. On April 8, 2013, a similar claim issued by alleged investors in Atlantic Power common shares seeking to initiate a class action against the Proposed Defendants was filed with the Superior Court of Quebec in the Province of Quebec (the “Canadian Actions”).
On April 17, May 22, and June 7, 2013 statements of claim relating to the notices of action were filed with the Ontario Superior Court of Justice in the Province of Ontario.
On August 30, 2013, the three Ontario actions were succeeded by one action with an amended claim being issued on behalf of Jacqeline Coffin and Sandra Lowry. As in the U.S. Action, this claim named the Company, Barry E. Welch and Terrence Ronan as Defendants. The Plaintiffs sought leave to commence an action for statutory misrepresentation under the Ontario Securities Act and asserted common law claims for misrepresentation.
The Plaintiffs’ motions for leave and certification were heard on May 20-21, 2015.
On July 24, 2015, the Ontario Superior Court of Justice issued a decision denying the Plaintiffs’ motion for leave and certification. The Superior Court granted leave to reconstitute a claim for debenture holders but required that there be a debenture holder as plaintiff, that the claim be amended and that the Plaintiffs pay the Defendants partial indemnity costs of responding to the Plaintiffs’ motion.
The Plaintiffs appealed the July 24 decision on leave and certification to the Ontario Court of Appeal.
The appeal was subsequently abandoned by the Plaintiffs, and the Ontario action was dismissed by Order dated December 2, 2015, the Defendants agreeing not to claim costs from the Plaintiffs.
The proposed Quebec class action was suspended by the Superior Court of Quebec pending the outcome of the motions for leave and certification of the Ontario action as a class proceeding. Following the result in Ontario, the petitioner in the Quebec proceedings has agreed in principle with the Defendants to discontinue the Quebec proceedings without costs. The discontinuance will require the authorization of the Superior Court of Quebec. The parties are preparing materials to obtain this authorization.
The petitioner in the Quebec proceedings did not estimate the alleged damages of the proposed class. Because the Quebec proceedings were suspended and then an agreement to discontinue was made in its early stages, Atlantic Power is unable to reasonably estimate the possible loss or range of losses, if any, arising from this litigation, if it were to continue. If the action were to continue, Atlantic Power intends to defend against it vigorously.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Share Repurchase Program
On December 22, 2015, our Board of Directors approved a normal course issuer bid (“NCIB”) for each series of our convertible unsecured subordinated debentures, our common shares and for each series of the preferred shares of Atlantic Power Preferred Equity Ltd. (“APPEL”), our wholly-owned subsidiary. The Board authorization permits the Company to repurchase shares through open market repurchases. There can be no assurances as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The NCIB will expire on December 28, 2016 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIB. Under the NCIB, we may purchase up to a total of 12,139,215 common shares (Cdn$28.0 million based on the Cdn$2.31 closing share price of our common shares on the TSX on December 31, 2015) and are limited to daily purchases of 22,600 common shares per day. During the year ended December 31, 2015, we repurchased 47,300 common shares under the NCIB at a total cost of $0.1 million and through March 3, 2016, we repurchased a cumulative 575,553 common shares at a total cost of $1.0 million.
The following table presents information regarding repurchases made by the Company of its common shares for the year ended December 31, 2015.
(1)
On December 22, 2015, our Board of Directors approved a normal course issuer bid (“NCIB”) for each series of our convertible unsecured subordinated debentures, our common shares and for each series of the preferred shares of Atlantic Power Preferred Equity Ltd. (“APPEL”), our wholly-owned subsidiary. Under the NCIB, we may purchase up to a total of 12,139,215 common shares (Cdn$28.0 million based on the Cdn$2.31 closing share price of our common shares on the TSX on December 31, 2015) and are limited to daily purchases of 22,600 common shares per day. The NCIB will expire on December 28, 2016 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIB.
Market Information and Holders
Our common shares trade on the NYSE under the symbol “AT” and on the TSX under the symbol “ATP”.
The following table sets forth the price ranges of our outstanding common shares, as reported by the NYSE for the periods indicated:
The following table sets forth the price ranges of our common shares, as applicable, as reported by the TSX for the periods indicated:
The number of common shares outstanding was approximately 121,624,829 on March 3, 2016.
Dividends
Dividends declared per common share in 2015 and 2014 were as follows (Cdn$):
On February 9, 2016, our Board of Directors, consistent with management’s recommendation, eliminated the Company’s common share dividend, effective immediately. Previously, the Company had paid a dividend of Cdn$0.03 per share quarterly, with the most recent payment on December 31, 2015. In conjunction with the elimination of the common share dividend, the Company’s dividend reinvestment plan was terminated.
Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information as of December 31, 2015 regarding our Long-Term Incentive Plan. For the description of our Long-Term Incentive Plan, see Note 16, Equity Compensation Plans to the consolidated financial statements.
(1)
Number of securities to be issued upon exercise of outstanding awards and number of securities remaining available for future issuance reflects expected redemption of award one-third in cash and two-thirds in common shares. See Item 15. “Exhibits and Financial Statements Schedule”-Note 2(t), Equity compensation plans.
(2)
The maximum aggregate number of common shares that may be issued under our Long-Term Incentive Plan upon redemption of notional shares is 3,000,000 and the maximum aggregate number of common shares that may be issued under our Transition Equity Grant Participation Agreement upon redemption of notional shares is 600,000. See Item 15. “Exhibits and Financial Statements Schedule”-Note 2(t), Equity compensation plans.
Performance Graph
The performance graph below compares the cumulative total shareholder return on our common shares for the period December 31, 2010, through December 31, 2015, with the cumulative total return of the Standard & Poor’s 500 Composite Stock Price Index, or S&P 500 and the Standard & Poor’s TSX Composite or S&P/TSX. Our common shares trade on the NYSE under the symbol “AT” and the TSX under the symbol “ATP”.
The performance graph shown below is being furnished and compares each period assuming that a $100 investment was made on December 31, 2010, in each of our common shares, the stocks included in the S&P 500 and the stocks included in the S&P/TSX, and that all dividends were reinvested.
Comparison of Cumulative Total Return
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth our selected historical consolidated financial information for each of the periods indicated. The annual historical information for each of the years in the three-year period ended December 31, 2015 has been derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
You should read the following selected consolidated financial data along with “Item 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following management’s discussion and analysis of financial condition and results of operations should be read in conjunction with our audited consolidated financial statements included in this Annual Report on Form 10-K. All dollar amounts discussed below are in millions of U.S. dollars, unless otherwise stated. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
(in millions of U.S. dollars, except per-share amounts)
The discussion and analysis below has been organized as follows:
1)
Our Strategy, Overview of 2015 Results and Recent Events
2)
Consolidated Overview and Results of Operations
3)
Project Operating Performance
4)
Supplementary Non-GAAP Financial Information
5)
Liquidity and Capital Resources
6)
Critical Accounting Policies
Our Strategy, Overview of 2015 Results and Recent Events
Management is focused on the following priorities:
·
Debt reduction: By strengthening our balance sheet we will improve our financial flexibility and become more competitive to pursue external growth opportunities.
·
Overhead cost reduction: Improving our cost structure provides additional flexibility for debt reduction, external growth and other value-accretive investments.
·
Fleet optimization: By making capital investments in our existing projects we are able to achieve cash returns that are higher than what is available in the external markets and at lower risk.
·
PPA renewals: We will leverage the strength of our operations, diversity and location of our projects to renew or extend our contracts in a challenging market.
·
External growth: We will take a creative, disciplined and value-oriented approach to external development or acquisitions.
In 2015, we made substantial progress in strengthening the Company. Our key achievements in the execution of our strategy during 2015 were:
·
Sale of the Wind Projects - On June 26, 2015, we completed the sale of the Wind Projects for aggregate cash proceeds of approximately $335 million after transaction fees and recorded a $46.8 million gain on sale as discussed in more detail in Item 15 - Note 3, Divestments.
·
Extension of the Morris Energy Service Agreement - On December 22, 2015, we entered into an agreement with Equistar Chemicals, LP, a subsidiary of LyondellBasell, to modify and extend the Energy Services Agreement (“ESA”) for our Morris project from November 2023 to December 2034.
·
Debt repayment - During 2015, we reduced our corporate and project-level debt by approximately $652 million. We achieved this primarily with the $319.9 million redemption of our 9.0% Senior Unsecured Notes due November 2018 (“9.0% Notes”) with proceeds from the sale of the wind projects, $248.8 million of project-level debt that was disposed with the sale of the wind projects and $83.2 million of amortization of our Senior Secured Credit Facility and other non-recourse project-level debt. Additionally, during 2015 we repurchased and cancelled $21.8 million aggregate principal of convertible debentures.
·
Overhead cost reduction - We have cut our corporate overhead expense from approximately $54 million in 2013 to $32 million for 2015, which represents a cumulative reduction from 2013 of approximately 41%. We did this by consolidating our offices in Boston, the Chicago area, Toronto, Seattle and Portland into our new headquarters location in Dedham, Massachusetts, as well as through other cost reductions.
·
Improved Credit Rating - Recognizing the considerable amount of debt reduction as well as the reduction in corporate overhead over the past three years, in October 2015, Moody’s upgraded our corporate family rating from B2 to B1 and in February 2016, S&P upgraded our corporate credit rating from B to B+.
·
Investment in our fleet - During 2015 we invested $10.7 million in our fleet for optimization projects and a total of $22 million since 2013. These investments returned approximately $6 million in cash during 2015.
·
External growth - In September 2015, Joe Cofelice joined Atlantic Power Corporation as EVP of Commercial Development to focus on exploring external opportunities.
In 2016, we have continued to focus on the above-discussed priorities. On February 9, 2016, we announced changes to our capital allocation strategy designed to create value for our shareholders in a tax-efficient manner, while also improving our financial flexibility and strengthening our balance sheet.
As part of this strategy, we will prioritize allocation of our discretionary capital (after mandatory debt repayment) to equity and debt repurchases, each under the normal course issuer bid (“NCIB”) implemented in December 2015, with a goal of capturing value arising from price-to-value opportunities in our publicly traded securities. In addition, we will continue to make high-return investments in our existing projects, as well as potential repowering of projects linked to extensions of PPAs.
As a result of this redirection of capital to expected higher-return purposes, the Board of Directors, consistent with management’s recommendation, eliminated the Company’s common share dividend, effective immediately. Previously, we paid a dividend of Cdn$0.03 per share quarterly, with the most recent payment on December 31, 2015. In conjunction with the elimination of the common share dividend, our dividend reinvestment plan was terminated.
Performance highlights
(1)
See reconciliation and definition below under Supplementary Non-GAAP Financial Information.
Revenue decreased from $489.9 million in the year ended December 31, 2014 to $420.2 million in the year ended December 31, 2015, a decrease of 14.2%. The primary drivers of the decrease are as follows:
·
PPA expiration - a $24.8 million decrease resulting from the PPA expiration at Tunis on December 31, 2014;
·
Impact of lower fuel costs - energy revenue pricing at several of our projects is impacted by changes in fuel cost. Lower fuel prices during 2015 resulted in a $31.4 million decrease in revenue from 2014. These decreases in revenue are offset by lower fuel expense so the net impact on project income is not material;
·
Hydrological conditions - a $5.8 million decrease from lower water flows and maintenance outages at our hydro projects; and
·
Currency - an approximate $24.5 million impact at our Canadian projects resulting from the weakening of the Canadian Dollar against the U.S. dollar during 2015. The decrease in revenue due to currency is
partially offset by the benefit of lower expenses also from currency at our Canadian projects. Currency had a net negative impact of $3.1 million to consolidated project income.
Consolidated project loss was $(41.1) million for the year ended December 31, 2015, an increase of $2.5 million from the prior year. The primary drivers of the increase are as follows:
·
Revenue - revenue decreased $69.7 million as discussed above; and
·
Impairment of goodwill and long-lived assets - goodwill and long-lived asset impairment increased $21.2 million from $106.6 million in 2014 to $127.8 million in 2015.
These increases in project loss were partially offset by increases in project income resulting from:
·
Fuel expense - fuel expense decreased from $210.4 million in 2014 to $165.1 million in 2015 primarily due to lower natural gas prices; and
·
Equity earnings - equity earnings increased from $25.5 million in 2014 to $36.7 million in 2015 due primarily to higher revenues and lower fuel expenses at our 50% ownership interest in the Orlando project and lower depreciation at our 17.7% ownership interest in Selkirk, which recorded accelerated depreciation in 2014 due to the expiration of its PPA in August 2014.
A detailed discussion of project income (loss) by segment is provided in Consolidated Overview and Results of Operations below. The discussion of Project Adjusted EBITDA by segment begins on page 64.
Factors that may influence our results
The primary components of our financial results are (i) the financial performance of our projects, (ii) unrealized gains and losses associated with derivative instruments, (iii) interest expense and foreign exchange impacts on corporate-level debt, and (iv) impairment of long-lived assets and goodwill. We have recorded net losses in four of the past five years, primarily as a result of non-cash losses associated with items (ii), (iii) and (iv) above, which are described in more detail in the following paragraphs.
Financial performance of our projects
The operating performance of our projects supports cash distributions that are made to us after all operating, maintenance, capital expenditures and debt service requirements are satisfied at the project-level. Our projects are able to generate cash flows because they generally receive revenues from long-term contracts that provide relatively stable cash flows. Risks to the stability of these distributions include the following:
·
Power generated by our projects, in most cases, is sold under PPAs that expire at various times. Currently, our PPAs are scheduled to expire between December 31, 2017 and December 31, 2037. When a PPA expires or is terminated, it may be difficult for us to secure a new PPA on acceptable terms or timing, if at all, or the price received by the project for power under subsequent arrangements may be reduced significantly, or there may be a delay in securing a new PPA until a significant time after the expiration of the original PPA at the project. For example, the PPA at Selkirk expired in August 2014. As a result, 100% of the capacity at Selkirk is not contracted and therefore sold at market power prices. Our next PPA expirations do not occur until year end 2017 and are at our North Bay and Kapuskasing projects in Ontario. See “Risk Factors-Risks Related to Our Business and Our Projects-The expiration or termination of our power purchase agreements could have a material adverse impact on our business, results of operations and financial condition.”
·
While approximately 35% of our power generation revenue in 2015 was related to contractual capacity payments, commodity prices do influence our variable revenues and the cost of fuel. Our PPAs are generally structured to minimize our risk to fluctuations in commodity prices by passing the cost of fuel through to the utility and its customers, but some of our projects do have exposure to market power and fuel prices. See Item 1A. “Risk Factors-Risks Related to Our Business and Our Projects-Our projects depend on third-party suppliers under fuel supply agreements, and increases in fuel costs may adversely
affect the profitability of the projects” and Item 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and commodity prices, will affect our cash flows or the value of our holdings of financial instruments. The objective of market risk management is to minimize the impact that market risks have on our cash flows as described in the following paragraphs.
Our market risk-sensitive instruments and positions have been determined to be “other than trading.” Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in fuel and electricity commodity prices, currency exchange rates or interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in fuel commodity prices, currency exchange rates or interest rates and the timing of transactions. See Note 14, Accounting for derivative instruments and hedging activities for additional information.
Fuel Commodity Market Risk
Our current and future cash flows are impacted by changes in electricity, natural gas, biomass and coal prices. See “Item 1A. Risk Factors-Risks Related to Our Business and Our Projects-Our projects depend on third-party
suppliers under fuel supply agreements, and increases in fuel costs may adversely affect the profitability of the projects.” We often employ (i) tolling structures, whereby an offtaker is responsible for fuel procurement, (ii) long-term fuel contracts, where we lock in a set quantity of fuel at a predetermined price or (iii) pass-through arrangements, whereby the cost of fuel is borne by the ultimate offtaker. The combination of long-term energy sales and fuel purchase agreements is generally designed to mitigate the impacts to cash flows of changes in commodity prices by passing through changes in fuel prices to the buyer of the energy.
Our 50% owned Orlando project operates without a fuel contract and is exposed to changes in natural gas prices. We have entered into various natural gas swaps to effectively fix the price of 6.3 million Mmbtu of future natural gas purchases at Orlando, which is approximately 100% of our share of the expected on-peak natural gas purchases at the project through 2016 or approximately 63% of our share of the expected base load natural gas purchases for each of 2015 and 2016. Because projected on-peak gas exposure is fully hedged, a $1.00 MMBtu change in the price of natural gas would not impact estimated cash distributions for 2016.
In June 2014, the Partnership entered into contracts for the purchase of 2.9 million Gigajoules (“Gj”) of future natural gas purchases beginning on November 1, 2014 and expiring on December 31, 2017 for our projects in Ontario. These contracts effectively fix the price of approximately 98% of our expected uncontracted gas requirements for each of 2014 and 2015 and 32% and 30% of our expected uncontracted gas requirements for 2016 and 2017, respectively. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at December 31, 2015. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations.
Electricity Commodity Market Risk
Our current and future cash flows are impacted by changes in electricity prices when our projects operate with no PPA or at projects that operate with PPAs that are based on spot market pricing. Our most significant exposure to market power prices is at the Chambers, Morris, and Selkirk projects.
At our 40% owned Chambers project, our utility customer has the right to sell a portion of the plant’s output into the spot power market if it is profitable to do so, and the Chambers project shares in the profits from these sales. In addition, during periods of low spot electricity prices the utility takes less generation, which negatively affects the project’s operating margin. In 2016, projected cash distributions from Chambers would change by approximately $0.1 million per 10% change in the PJM-East spot price of electricity based on a forecasted around the clock (“ATC”) price of $38.31 per MWh and certain other assumptions.
At Morris, where we own 100% of the project, the facility can sell approximately 120 MW above the off-taker’s demand into the grid at market prices. If market prices do not justify the increased generation the project has no requirement to sell power in excess of the off-taker’s demand which can negatively impact operating margins. In 2016, projected cash distributions from Morris would change by approximately $0.6 million per 10% change in the spot price of electricity based on the current level of approximately 175,000 MWh grid sales and all other variables being held constant.
At Selkirk, where we own 17.7% of the project, 100% of the project’s capacity is currently not contracted and is sold into the spot power market or not sold at all if market prices do not support profitable operation of that portion of the facility. Forecasted distributions for 2016 would not change materially per 10% change in the forecasted spot price of electricity.
When a PPA expires or is terminated, it is possible that the price received by the project for power under subsequent arrangements may be reduced and in some cases, significantly. Our project may not be able to secure a new agreement and could be exposed to sell power at spot market price. See Item 1A. “Risk Factors-Risk Related to Our Business and Our Projects-The expiration or termination of our power purchase agreements could have a material adverse impact on our business, results of operations and financial condition.” It is possible that subsequent PPAs or the spot market may not be available at prices that permit the operation of the project on a profitable basis. If this occurs, the affected project may temporarily or permanently cease operations.
Foreign Currency Exchange Risk
We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates, as many of our projects generate cash flow in U.S. dollars and Canadian dollars but we pay dividends on our preferred shares and interest on some of our corporate level long-term debt and all but one of our convertible debentures, predominantly in Canadian dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on any Canadian dollar obligation. From time to time, we execute this strategy utilizing cash flows from our projects that generate Canadian dollars and by entering into forward contracts to purchase Canadian dollars. These foreign exchange forward contracts are recorded at estimated fair value based on quoted market prices and the estimation of the counter-party’s credit risk. Changes in the fair value of the foreign currency forward contracts are recorded in foreign exchange (gain) loss in the consolidated statements of operations. As of December 31, 2015, we have no foreign currency forward contracts as there are sufficient Canadian dollars generated from the business to cover Canadian dollar obligations.
The following table contains the components of recorded foreign exchange (gain) loss for the years ended December 31, 2015, 2014, and 2013:
A 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar would have a $29.1 million impact on the carrying value of the MTNs and convertible debentures denominated in Canadian dollars at December 31, 2015.
Interest Rate Risk
Changes in interest rates impact cash payments that are required on our debt instruments as approximately 38.2% of our debt, including our share of the project-level debt associated with equity investments in affiliates, either bears interest at variable rates or is not financially hedged through the use of interest rate swaps. After considering the impact of interest rate swaps described below, a hypothetical change in the average interest rate of 100 basis points would change annual interest costs, including interest at equity investments, by approximately $3.4 million at December 31, 2015.
The Partnership
On May 5, 2014 the Partnership entered into interest rate swap agreements to mitigate exposure to changes in the Adjusted Eurodollar Rate for $199.0 million notional amount ($153.7 million at December 31, 2015) of the $600 million aggregate principal amount of borrowings ($473.2 million at December 31, 2015) under the Term Loan Facility. Borrowings under the $600 million Term Loan Facility bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 3.75%. Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00% resulting in a minimum of a 4.75% all-in rate on the Term Loan Facility. As a result of entering into the swap agreements, the all-in rate for $199.0 million of the Term Loan Facility cannot be less than 4.91% if the Adjusted Eurodollar Rate is equal to or greater than 1.00%. If the Adjusted Eurodollar Rate is below 1.00%, we will pay interest at a rate equivalent to the minimum 4.75% all-in rate plus any difference between the actual three month Adjusted Eurodollar Rate and 1.16%.
The interest rate swap agreements were effective June 30, 2014 and terminate on December 29, 2017. The interest rate swap agreements are not designated as hedges and changes in their fair market value will be recorded in the consolidated statements of operations.
Epsilon Power Partners
Epsilon Power Partners, a wholly owned subsidiary, is exposed to changes in interest rates related to its variable-rate non-recourse debt and previously had an interest rate swap to mitigate this exposure. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 7.37% and had a maturity date of July 2019. The notional amount of the swap matched the outstanding principal balance over the remaining life of Epsilon Power Partners’ debt. On February 20, 2014, we paid $2.6 million to terminate this contract in connection with the termination of our prior revolving credit facility. We recorded interest expense related to its settlement in the consolidated statement of operations for the year ended December 31, 2014.
Cadillac
We have an interest rate swap at our consolidated Cadillac project to economically fix its exposure to changes in interest rates related to the variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the project-level Cadillac debt and changes in its fair market value are recorded in other comprehensive income (loss). The interest rate swap expires on September 30, 2025.
In accounting for the cash flow hedge, gains and losses on the derivative contract are reported in other comprehensive income (loss), but only to the extent that the gains and losses from the change in value of the derivative contracts can later offset the loss or gain from the change in value of the hedged future cash flows during the period in which the hedged cash flows affect net income (loss). That is, for cash flow hedge, all effective components of the derivative contract’s gains and losses are recorded in other comprehensive income (loss), pending occurrence of the expected transaction. Other comprehensive income (loss) consists of those financial items that are included in “Accumulated other comprehensive loss” in our accompanying consolidated balance sheets but not included in our net income (loss). Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income (loss) changes by exactly as much as the derivative contracts and there is no impact on net income (loss) until the expected transaction occurs.
Piedmont
The Piedmont project has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreement effectively converts the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.8% through February 29, 2016. From February 2016 until the maturity of the debt in August 2018, the fixed rate of the swap is 4.47% and the applicable margin is 4.0%, resulting in an all-in rate of 8.5%. The swap continues at the fixed rate of 4.47% from the maturity of the debt in August 2018 until November 2030. Prior to conversion of the Piedmont Construction loan facility to a term loan, the notional amounts of the interest rate swap agreements matched the estimated outstanding principal balance of Piedmont’s construction loan facility. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively. As a result of the Piedmont term loan conversion on February 14, 2014, these swap agreements were amended to reduce the notional amounts to match the outstanding $68.5 million principal of the term loan. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our consolidated financial statements are appended to the end of this Annual Report on Form 10-K, beginning on page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
(a)Evaluation of Disclosure Controls and Procedures
Our Chief Executive Officer and Chief Financial Officer have evaluated the company’s disclosure controls and procedures, as defined in Rules 13a- 15(e) and 15d-15(e) of the Exchange Act, as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were not effective as of the end of the fiscal year covered by this Annual Report on Form 10-K because of the material weakness in internal control over financial reporting described below.
Notwithstanding the material weakness discussed below, our management, including our Chief Executive Officer and our Chief Financial Officer, concluded that the consolidated financial statements in this Annual Report on Form 10-K fairly present, in all material respects, the Company's financial condition, results of operations and cash flows for the periods presented, in conformity with U.S. generally accepted accounting principles.
(b)Management’s Report on Financial Statements and Practices
The accompanying Consolidated Financial Statements of Atlantic Power Corporation were prepared by management, which is responsible for their integrity and objectivity. The statements were prepared in accordance with generally accepted accounting principles and include amounts that are based on management’s best judgments and estimates. The other financial information included in this annual report is consistent with that in the financial statements.
Management also recognizes its responsibility for conducting the Company’s affairs according to the highest standards of personal and corporate conduct. This responsibility is characterized and reflected in key policy statements issued from time to time regarding, among other things, conduct of its business activities within the laws of the host countries in which the Company operates and potentially conflicting outside business interests of its employees. The Company maintains a systematic program to assess compliance with these policies.
(c)Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-14(f) under the Exchange Act. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2015 using the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).
Because of their inherent limitations, our disclosure controls and procedures and our internal control over financial reporting may not prevent errors or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to risks, including that the controls may become inadequate because of changes in conditions or that the degree of compliance with our policies or procedures may deteriorate.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of a company's annual or interim financial statements will not be prevented or detected on a timely basis.
Based on its evaluation, management has concluded that a material weakness existed in the Company's internal control over financial reporting as of December 31, 2015 because the Company’s internal controls over its long-lived asset and goodwill impairment tests were not designed effectively to ensure the proper application of US GAAP over (i) the determination of the carrying value of our asset groups and reporting units used in the accounting for long-lived asset recoverability and goodwill impairment test, and (ii) the determination of the long-lived asset and goodwill impairment charges. Specifically, with respect to (i) and (ii), we did not design and maintain effective controls related to determining the carrying value of the asset groups for the purpose of performing the long-lived asset impairment testing as we did not appropriately include the carrying value of goodwill in certain long-lived asset groups in which the asset group is at the same level as the reporting unit. This resulted in an initial conclusion that no long-lived asset impairment should be recorded and also impacted the carrying value of our reporting units for step 1 and step 2 of our goodwill impairment tests.
These control deficiencies resulted in misstatements related to goodwill, property, plant and equipment, net, deferred income taxes and impairment, within the preliminary consolidated financial statements that were corrected prior to the issuance of the Company’s consolidated financial statements as of and for the fiscal year ended December 31, 2015.
These control deficiencies, if unremediated, could, in another reporting period, result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected by the controls. Accordingly, our management has determined that these control deficiencies constitute a material weakness.
(d)Management's Remediation Plan
Management is actively engaged in the planning for, and implementation of, remediation efforts to address the material weakness identified above. Management intends to take the following actions to address the material weakness:
Re-designing its controls, including the implementation of new controls, relating to the long-lived asset and goodwill impairment analysis, including: (i) enhancing the design and documentation of management review controls in order to enhance the precision at which management review controls operate, (ii) improving the documentation of internal control procedures, and (iii) enhancing the evaluation of the components of carrying value and comparison to the requirements of generally accepted accounting principles.
We are in the process of implementing our remediation plan. However, while we expect to take the necessary steps to establish and enhance controls designed to address the material weakness in the coming year, because the internal controls relate to impairment tests, which are event-driven or annual tests, we are unable at this time to estimate when the remediation will be completed.
(e)Attestation Report of the Registered Public Accounting Firm
The effectiveness of our internal control over financial reporting as of December 31, 2015 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report, which is included in Item 15 of this annual report Form 10-K on page.
(f)Changes in Internal Control over Financial Reporting
Other than the material weakness described above, there has been no change in our internal control over financial reporting during the fourth fiscal quarter ended December 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information concerning our directors and executive officers required by Item 10 will be included in the Proxy Statement and is incorporated herein by reference.
We have adopted a code of ethics that applies to directors, managers, officers and employees. This code of ethics, titled “Code of Business Conduct and Ethics,” is posted on our website. The internet address for our website is www.atlanticpower.com, and the “Code of Business Conduct and Ethics” may be found from our main Web page by clicking first on “About Us” and then on “Code of Conduct.”
We intend to satisfy any disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the “Code of Business Conduct and Ethics” by posting such information on our website, on the Web page found by clicking through to “Conduct of Conduct” as specified above.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information concerning our directors and executive officers required by Item 11 will be included in the Proxy Statement and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information concerning security ownership and other matters required by Item 12 will be included in the Proxy Statement and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information concerning certain relationships and related transactions required by Item 13 will be included in the Proxy Statement and is incorporated herein by reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information concerning principal accountant fees and services required by Item 14 will be included in the Proxy Statement and is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements
See “Index to Consolidated Financial Statements” on page of this Annual Report on Form 10-K.
(a)(2) Financial Statement Schedules
See “Index to Consolidated Financial Statements” on page of this Annual Report on Form 10-K. Schedules other than that listed have been omitted because of the absence of the conditions under which they are required or because the information required is shown in the consolidated financial statements or the notes thereto.
(a)(3) Exhibits
EXHIBIT INDEX
+Indicates management contract or compensatory plan or arrangement.
*Filed herewith.
**Furnished herewith.
(b) Exhibits:
See Item 15(a)(3) above.
(c) Financial Statement Schedules:
See Item 15(a)(2) above.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
						
						
						
						
						
Signature
Title
Date
						
						
						
						
						
/s/ James J. Moore, JR.
						
President, Chief Executive Officer and Director
						
March 7, 2016
						
James J. Moore, Jr.
						
(principal executive officer)
						
						
						
						
						
						
						
						
/s/ Terrence Ronan
						
Chief Financial Officer (Duly Authorized
						
March 7, 2016
						
Terrence Ronan
						
Officer and Principal Financial and Accounting Officer)
						
						
						
						
						
						
						
						
/s/ Irving R. Gerstein
						
Chairman of the Board
						
March 7, 2016
						
Irving R. Gerstein
						
						
						
						
						
						
						
						
						
						
/s/ R. Foster Duncan
						
Director
						
March 7, 2016
						
R. Foster Duncan
						
						
						
						
						
						
						
						
						
						
/s/ Kenneth M. Hartwick
						
Director
						
March 7, 2016
						
Kenneth M. Hartwick
						
						
						
						
						
						
						
						
						
						
/s/ Kevin T. Howell
						
Director
						
March 7, 2016
						
Kevin T. Howell
						
						
						
						
						
						
						
						
						
						
/s/ Holli Ladhani
						
Director
						
March 7, 2016
						
Holli Ladhani
						
						
						
						
						
						
						
						
						
						
/s/ John A. McNeil
						
Director
						
March 7, 2016
						
John A. McNeil
						
						
						
						
						
						
						
						
						
						
/s/ Gilbert S. Palter
						
Director
						
March 7, 2016
						
Gilbert S. Palter
						
						
						
						
						
						
						
						
						
						
/s/ Teresa M. Ressel
						
Director
						
March 7, 2016
						
Teresa M. Ressel
						
						
						
						
						
			 		
Atlantic Power Corporation
Index to Consolidated Financial Statements
						
Page
Report of Independent Registered Public Accounting Firm
Consolidated Audited Financial Statements
						
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statement of Comprehensive Loss
Consolidated Statements of Shareholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Financial Statement Schedules
						
Schedule II-Valuation and Qualifying Accounts
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Atlantic Power Corporation:
We have audited Atlantic Power Corporation’s (the “Company”) internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Atlantic Power Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. A material weakness related to the Company’s internal controls over its long-lived asset and goodwill impairment tests has been identified and included in management’s assessment.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Atlantic Power Corporation and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive loss, shareholders’ equity, cash flows and related financial statement schedule for each of the years in the three-year period ended December 31, 2015. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2015 consolidated financial statements, and this report does not affect our report dated March 7, 2016, which expressed an unqualified opinion on those consolidated financial statements.
In our opinion, because of the effect of the aforementioned material weakness on the achievement of the objectives of the control criteria, Atlantic Power Corporation has not maintained effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
/s/ KPMG LLP
New York, New York
March 7, 2016
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Atlantic Power Corporation:
We have audited the accompanying consolidated balance sheets of Atlantic Power Corporation and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive loss, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule “Schedule II - Valuation and Qualifying Accounts.” These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlantic Power Corporation and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Atlantic Power Corporation’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 7, 2016 expressed an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
New York, New York
March 7, 2016
ATLANTIC POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
(in millions of U.S. dollars)
See accompanying notes to consolidated financial statements.
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions of U.S. dollars, except per share amounts)
See accompanying notes to consolidated financial statements.
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(in millions of U.S. dollars)
See accompanying notes to consolidated financial statements.
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in millions of U.S. dollars)
See accompanying notes to consolidated financial statements.
ATLANTIC POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions of U.S. dollars)
See accompanying notes to consolidated financial statements.
			 		
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in millions of U.S. dollars, except per-share amounts)
			
		
1. Nature of business
General
Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. Our power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements (“PPAs”), which seek to minimize exposure to changes in commodity prices. As of December 31, 2015, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,138 megawatts (“MW”) in which our aggregate ownership interest is approximately 1,500 MW. Our current portfolio consists of interests in twenty-three operational power generation projects across eleven states in the United States and two provinces in Canada. Eighteen of our projects are majority-owned.
Atlantic Power is a corporation established under the laws of the Province of Ontario, Canada on June 18, 2004 and continued to the Province of British Columbia on July 8, 2005. Our shares trade on the Toronto Stock Exchange under the symbol “ATP” and on the New York Stock Exchange under the symbol “AT.” Our registered office is located at 355 Burrard Street, Suite 1900, Vancouver, British Columbia V6C 2G8 Canada and our headquarters is located at 3 Allied Drive, Suite 220, Dedham, Massachusetts 02026, USA.
2. Summary of significant accounting policies
(a)
Principles of consolidation and basis of presentation:
The accompanying consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the consolidated accounts and operations of our subsidiaries in which we have a controlling financial interest. The usual condition for a controlling financial interest is ownership of the majority of the voting interest of an entity. However, a controlling financial interest may also exist in entities, such as a variable interest entity, through arrangements that do not involve controlling voting interests.
We apply the standard that requires consolidation of variable interest entities (“VIEs”), for which we are the primary beneficiary. The guidance requires a variable interest holder to consolidate a VIE if that party has both the power to direct the activities that most significantly impact the entities’ economic performance, as well as either the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. We have determined that our equity investments are not VIEs by evaluating their design and capital structure. Accordingly, we use the equity method of accounting for all of our investments in which we do not have an economic controlling interest. We eliminate all intercompany accounts and transactions in consolidation.
(b)Cash and cash equivalents:
Cash and cash equivalents include cash deposited at banks and highly liquid investments with original maturities of 90 days or less when purchased.
(c)Restricted cash:
Restricted cash represents cash and cash equivalents that are maintained by the projects or corporate to support payments for maintenance costs and meet project level and corporate contractual debt obligations. Restricted cash is classified as a current or long-term asset based on the timing and nature of when or how the cash is expected to be used or when the restrictions are expected to lapse.
			
		
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
(d)Accounts receivable:
Accounts Receivable are carried at cost. We periodically assesses the collectability of accounts receivable, considering factors such as specific evaluation of collectability, historical collection experience, the age of accounts receivable and other currently available evidence of the collectability, and record an allowance for doubtful accounts for the estimated uncollectible amount as appropriate.
(e)Deferred financing costs:
Deferred financing costs represent costs to obtain long-term financing and are amortized using the effective interest method over the term of the related debt, which ranges from 4 to 22 years. The carrying amount of deferred financing costs recorded on the consolidated balance sheets was $42.5 million and $62.8 million at December 31, 2015 and 2014, respectively. Interest expense from the amortization of deferred finance costs for the years ended December 31, 2015, 2014, and 2013 was $20.5 million, $16.5 million, and $8.0 million, respectively.
(f)Inventory:
Inventory represents small parts and other consumables and fuel, the majority of which is consumed by our projects in provision of their services, and are valued at the lower of cost or net realizable value. Cost is the sum of the purchase price and incidental expenditures and charges incurred to bring the inventory to its existing condition or location. The cost of inventory items that are interchangeable are determined on an average cost basis. For inventory items that are not interchangeable, cost is assigned using specific identification of their individual costs.
(g)Property, plant and equipment:
Property, plant and equipment are stated at cost, net of accumulated depreciation. Depreciation is provided on a straight-line basis over the estimated useful life of the related asset. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred.
(h)Project development costs and capitalized interest:
Project development costs are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including among others, obtaining a PPA.
Interest incurred on funds borrowed to finance capital projects are capitalized, until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2015, 2014, and 2013 was $0.0 million, $0.0 million, and $1.9 million, respectively.
When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and depreciated on a straight-line basis over the estimated useful life of the project’s related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.
(i)Other intangible assets:
Other intangible assets include PPAs and fuel supply agreements at our projects acquired as part of business combinations, as well as capitalized development costs. PPAs are valued at the time of acquisition based on the contract
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
prices under the PPAs compared to projected market prices. Fuel supply agreements are valued at the time of acquisition based on the contract prices under the fuel supply agreement compared to projected market prices. The balances are presented net of accumulated amortization in the consolidated balance sheets. Amortization is recorded on a straight-line basis over the remaining term of the agreement.
(j)Investments accounted for by the equity method:
We have investments in entities that own power producing assets with the objective of generating cash flow. The equity method of accounting is applied to such investments in affiliates, which include joint ventures, partnerships, and limited liability companies because the ownership structure prevents us from exercising a controlling influence over the operating and financial policies of the projects. Our investments in partnerships and limited liability companies with 50% or less ownership, but greater than 5% ownership in which we do not have a controlling interest are accounted for under the equity method of accounting. We apply the equity method of accounting to investments in limited partnerships and limited liability companies with greater than 5% ownership because our influence over the investment’s operating and financial policies is considered to be more than minor.
Under the equity method, equity in pre-tax income or losses of our investments is reflected as equity in earnings of unconsolidated affiliates. The cash flows that are distributed to us from these unconsolidated affiliates are directly related to the operations of the affiliates’ power producing assets and are classified as cash flows from operating activities in the consolidated statements of cash flows. We record the return of our investments in equity investees as cash flows from investing activities. Cash flows from equity investees are considered a return of capital when distributions are generated from proceeds of either the sale of our investment in its entirety or a sale by the investee of all or a portion of its capital assets.
(k)Impairment of long-lived assets, non-amortizing intangible assets and equity method investments:
Long-lived assets, such as property, plant and equipment, and other intangible assets and liabilities subject to depreciation and amortization, are reviewed for impairment annually or whenever events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset group. If the carrying amount of an asset group exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset group exceeds its fair value.
Investments in and the operating results of 50%-or-less owned entities not consolidated are included in the consolidated financial statements on the basis of the equity method of accounting. We review our investments in such unconsolidated entities for impairment whenever events or changes in business circumstances indicate that the carrying amount of the investments may not be fully recoverable. We also review a project for impairment at the earlier of executing a new PPA (or other arrangement) or six months prior to the expiration of an existing PPA. Factors such as the business climate, including current energy and market conditions, environmental regulation, the condition of assets, and the ability to secure new PPAs are considered when evaluating long-lived assets for impairment. Evidence of a loss in value that is other than temporary might include the absence of an ability to recover the carrying amount of the investment, the inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment or, where applicable, estimated sales proceeds that are insufficient to recover the carrying amount of the investment. Our assessment as to whether any decline in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of the investment is recoverable within a reasonable period of time outweighs evidence to the contrary. We generally consider our investments in our equity method investees to be strategic long-term investments. Therefore, we complete our assessments with a long-term view. If the fair value of the investment is determined to be less than the carrying value and the decline in value is considered to be other than temporary, the asset is written down to its fair value.
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
(l)Goodwill:
Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated to the assets acquired, less liabilities assumed, based on their fair values. Goodwill is allocated, as of the date of the business combination, to our reporting units that are expected to benefit from the synergies of the business combination.
Goodwill is not amortized and is tested for impairment, annually in the fourth quarter, or more frequently if events or changes in circumstances indicate that the asset might be impaired.
In our test, we first perform step zero to determine whether the existence of events or circumstances leads to a determination that it is more likely than not (i.e. more than 50%) that the fair value of a reporting unit is less than its carrying amount. Such qualitative factors may include the following: macroeconomic conditions, industry and market considerations, cost factors, overall financial performance and other relevant entity-specific events. If the qualitative assessment determines that an impairment is more likely than not, then we perform a two-step quantitative impairment test. In the first step of the quantitative analysis, the carrying amount of the reporting unit is compared with its fair value. When the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not to be impaired and the second step of the impairment test is unnecessary.
The second step is carried out when the carrying amount of a reporting unit exceeds its fair value, in which case, the implied fair value of the reporting unit’s goodwill is compared with its carrying amount to measure the amount of the impairment loss, if any. The implied fair value of goodwill is determined in the same manner as the value of goodwill is determined in a business combination, using the fair value of the reporting unit as if it were the purchase price. When the carrying amount of reporting unit goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess and is recorded in the consolidated statements of operations.
(m)Accounts payable and other accrued liabilities:
Accounts payable consists of amounts due to trade creditors related to our core business operations. These payables include amounts owed to vendors and suppliers for items such as fuel, maintenance, inventory and other raw materials. Other accrued liabilities include items such as income taxes, legal contingencies and employee-related costs including payroll, benefits and related taxes.
(n)Assets held for sale and discontinued operations:
For those businesses where we have committed to a plan to divest, each business is valued at the lower of its carrying amount or estimated fair value less cost to sell. If the carrying amount of the business exceeds its estimated fair value, an impairment loss is recognized. Fair value is estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples, or indicative bids, when available. A number of significant estimates and assumptions are involved in the application of these techniques, including the forecasting of markets and market share, sales volumes and prices, costs and expenses, and multiple other factors. We consider historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the divestiture of a business may differ from the estimated fair value reflected in the consolidated financial statements. Depreciation and amortization expense is not recorded on assets of a business to be divested once they are classified as held for sale. Businesses to be divested are classified in the consolidated financial statements as either discontinued operations or held for sale.
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
For businesses classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities of operations held for sale on the consolidated balance sheet and to discontinued operations on the consolidated statements of operations, respectively, for all periods presented. The gains or losses associated with these divested businesses are recorded in discontinued operations on the consolidated statements of operations. Segment information does not include the assets or operating results of businesses classified as discontinued operations for all periods presented.
(o)Derivative financial instruments:
We use derivative financial instruments in the form of interest rate swaps and foreign exchange forward contracts to manage our current and anticipated exposure to fluctuations in interest rates and foreign currency exchange rates. We have also entered into natural gas supply contracts and natural gas forwards or swaps to minimize the effects of the price volatility of natural gas, which is a significant operating cost. We do not enter into derivative financial instruments for trading or speculative purposes. Certain derivative instruments qualify for a scope exception to fair value accounting because they are considered normal purchases or normal sales in the ordinary course of conducting business. This exception applies when we have the ability to, and it is probable that we will deliver or take delivery of the underlying physical commodity.
We have designated one of our interest rate swaps as a hedge of cash flows for accounting purposes. Tests are performed to evaluate hedge effectiveness and ineffectiveness at inception and on an ongoing basis, both retroactively and prospectively. Derivatives accounted for as hedges are recorded at fair value in the balance sheet. Unrealized gains or losses on derivatives designated as a hedge are deferred and recorded as a component of accumulated other comprehensive income (loss) until the hedged transactions occur and are recognized in earnings. The ineffective portion of the cash flow hedge, if any, is immediately recognized in earnings.
Derivative financial instruments not designated as a hedge are measured at fair value with changes in fair value recorded in the consolidated statements of operations. The following table summarizes derivative financial instruments that are not designated as hedges for accounting purposes and the accounting treatment in the consolidated statements of operations of the changes in fair value and cash settlements of such derivative financial instrument:
(p)Income taxes:
Income tax expense includes the current tax obligation or benefit and change in deferred income tax asset or liability for the period. We use the asset and liability method of accounting for deferred income taxes and record deferred income taxes for all significant temporary differences. Income tax benefits associated with uncertain tax positions are recognized when we determine that it is more-likely-than-not that the tax position will be ultimately sustained. Refer to Note 15 for more information.
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
(q)Revenue recognition:
We recognize energy sales revenue on a gross basis when electricity and steam are delivered under the terms of the related contracts. PPAs, steam purchase arrangements and energy services agreements are long-term contracts to sell power and steam on a predetermined basis.
Energy-Energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in our consolidated statements of operations.
Capacity-Capacity payments under the PPAs are recognized as the lesser of (1) the amount billable under the PPA or (2) an amount determined by the kilowatt hours made available during the period multiplied by the estimated average revenue per kilowatt hour over the term of the PPA.
(r)Administrative expenses:
Administrative expenses include corporate and other expenses primarily for executive management, finance, legal, human resources and information systems, which are not directly allocable to our business segments.
(s)Power purchase arrangements containing a lease:
We have entered into PPAs to sell power at predetermined rates. PPAs are assessed as to whether they contain leases which convey to the counterparty the right to the use of the project’s property, plant and equipment in return for future payments. Such arrangements are classified as either capital or operating leases. PPAs that transfer substantially all of the benefits and risks of ownership of property to the PPA counterparty are classified as direct financing leases.
Finance income related to leases or arrangements accounted for as direct financing leases is recognized in a manner that produces a constant rate of return on the net investment in the lease. The net investment is comprised of net minimum lease payments and unearned finance income. Unearned finance income is the difference between the total minimum lease payments and the carrying value of the leased property. Unearned finance income is deferred and recognized in net income (loss) over the lease term.
For PPAs accounted for as operating leases, we recognize lease income consistent with the recognition of energy revenue. When energy is delivered, we recognize lease income in energy revenue.
(t)Foreign currency translation and transaction gains and losses:
The local currency is the functional currency of our U.S. and Canadian projects. Our reporting currency is the U.S. dollar. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the determination of our statements of operations for the period, but are accumulated and reported as a separate component of shareholders’ equity until sale of the net investment in the project takes place. Foreign currency transaction gains or losses are reported within foreign exchange (gain) loss in our statements of operations.
(u)Equity compensation plans:
The officers and certain other employees are eligible to participate in the Long-Term Incentive Plan (“LTIP”). Vested notional units are expected to be redeemed one-third in cash and two-thirds in shares of our common stock.
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
Notional units granted that are expected to be redeemed in cash upon vesting are accounted for as liability awards. Notional units granted that are expected to be redeemed in common shares upon vesting are accounted for as equity awards. Unvested notional units are entitled to receive dividends equal to the dividends per common share during the vesting period in the form of additional notional units. Unvested units are subject to forfeiture if the participant is not an employee at the vesting date.
We initially recognize compensation expense on the estimated number of notional units for which the requisite service is expected to be rendered. In 2015, we have estimated a weighted average forfeiture rate of 11% for LTIP granted in 2015. This estimate will be revisited if subsequent information indicates the actual number of notional units forfeited is likely to differ from previous estimates. Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the estimated fair value of the award on the grant date for notional units accounted for as equity awards and the fair value of the award at each balance sheet date for notional units accounted for as liability awards.
(v)Asset retirement obligations:
The fair value for an asset retirement obligation is recorded in the period in which it is incurred. Retirement obligations associated with long-lived assets are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. When the liability is initially recorded, we capitalize the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss.
(w)Pensions:
We offer pension benefits to certain employees through a defined benefit pension plan. We recognize the funded status of our defined benefit plan in the consolidated balance sheets in other long-term liabilities and record an offset to other comprehensive income (loss). In addition, we also recognize on an after-tax basis, as a component of other comprehensive income (loss), gains and losses as well as all prior service costs that have not been included as part of our net periodic benefit cost. The determination of our obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. Our actuarial consultants use assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of our pension obligation or expense recorded.
(x)Business combinations:
We account for our business combinations in accordance with the acquisition method of accounting, which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred.
(y)Concentration of credit risk:
The financial instruments that potentially expose us to credit risk consist primarily of cash and cash equivalents, restricted cash, derivative instruments and accounts receivable. Cash and restricted cash are held by major financial
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
institutions that are also counterparties to our derivative instruments. We have long-term agreements to sell electricity, gas and steam to public utilities and corporations. We have exposure to trends within the energy industry, including declines in the creditworthiness of our customers. We do not normally require collateral or other security to support energy-related accounts receivable. We do not believe there is significant credit risk associated with accounts receivable due to the credit worthiness and payment history of our customers. See Note 22, Segment and geographic information, for a further discussion of customer concentrations.
(z)Use of estimates:
The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, valuation of goodwill, intangible assets and liabilities related to PPAs and fuel supply agreements, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the fair value of financial instruments and derivatives, pension obligations, asset retirement obligations, and the fair values of acquired assets. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.
(aa)Revision to the presentation of preferred shares issued by a subsidiary company:
The classification of preferred shares issued by a subsidiary company has been revised from total Atlantic Power Corporation shareholders’ equity on the Consolidated Balance Sheets at December 31, 2014 to a separate line item in the noncontrolling interests section of equity. The revision does not impact total equity in either period presented. The revision was appropriate in order to properly present the preferred shares issued by a subsidiary company in the consolidated balance sheet. The revision is not considered material to any previously issued financial statements.
(ab)Recently adopted and issued accounting standards:
Adopted
In April 2014, the FASB issued changes to reporting discontinued operations and disclosures of disposals of components of an entity. These changes require a disposal of a component to meet a higher threshold in order to be reported as a discontinued operation in an entity’s financial statements. The threshold is defined as a strategic shift that has, or will have, a major effect on an entity’s operations and financial results such as a disposal of a major geographical area or a major line of business. Additionally, the following two criteria have been removed from consideration of whether a component meets the requirements for discontinued operations presentation: (i) the operations and cash flows of a disposal component have been or will be eliminated from the ongoing operations of an entity as a result of the disposal transaction, and (ii) an entity will not have any significant continuing involvement in the operations of the disposal component after the disposal transaction. Furthermore, equity method investments now may qualify for discontinued operations presentation. These changes also require expanded disclosures for all disposals of components of an entity, whether or not the threshold for reporting as a discontinued operation is met, related to profit or loss information and/or asset and liability information of the component. These changes became effective on January 1, 2015 and were applied to the sale of the Wind Projects in June 2015.
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
In July 2013, the FASB issued changes to the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. These changes require an entity to present an unrecognized tax benefit as a liability in the financial statements if (i) a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset to settle any additional income taxes that would result from the disallowance of a tax position. Otherwise, an unrecognized tax benefit is required to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. Previously, there was diversity in practice as no explicit guidance existed. These changes became effective for us on January 1, 2014 and did not have a material impact on the consolidated financial statements.
In March 2013, the FASB issued changes to a parent entity’s accounting for the cumulative translation adjustment upon derecognition of certain subsidiaries or groups of assets within a foreign entity or of an investment in a foreign entity. A parent entity is required to release any related cumulative foreign currency translation adjustment from accumulated other comprehensive income (loss) into net income (loss) in the following circumstances: (i) a parent entity ceases to have a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity if the sale or transfer results in the complete or substantially complete liquidation of the foreign entity in which the subsidiary or group of assets had resided; (ii) a partial sale of an equity method investment that is a foreign entity; (iii) a partial sale of an equity method investment that is not a foreign entity whereby the partial sale represents a complete or substantially complete liquidation of the foreign entity that held the equity method investment; and (iv) the sale of an investment in a foreign entity. These changes became effective for us on January 1, 2014 and had no impact on the consolidated financial statements.
In February 2013, the FASB issued changes to the accounting for obligations resulting from joint and several liability arrangements. These changes require an entity to measure such obligations for which the total amount of the obligation is fixed at the reporting date as the sum of (i) the amount the reporting entity agreed to pay on the basis of its arrangement among its co- obligors, and (ii) any additional amount the reporting entity expects to pay on behalf of its co-obligors. An entity will also be required to disclose the nature and amount of the obligation as well as other information about those obligations. Examples of obligations subject to these requirements are debt arrangements and settled litigation and judicial rulings. These changes became effective for us on January 1, 2014 and had no impact on the consolidated financial statements.
On January 1, 2013, we adopted changes issued by the FASB to the reporting of amounts reclassified out of accumulated other comprehensive income. These changes require an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required to be reclassified in its entirety to net income. For other amounts that are not required to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures that provide additional detail about those amounts. These requirements are to be applied to each component of accumulated other comprehensive income. Other than the additional disclosure requirements, the adoption of these changes had no impact on the consolidated financial statements.
On January 1, 2013, we adopted changes issued by the FASB to the testing of indefinite-lived intangible assets for impairment, similar to the goodwill changes issued in September 2011. These changes provide an entity the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not (more than 50%) that the fair value of an indefinite-lived intangible asset is less than its carrying amount. Such qualitative factors may include the following: macroeconomic conditions; industry and market considerations; cost factors; overall financial performance; and other relevant entity-specific events. If an entity elects to perform a qualitative assessment and determines that an impairment is more likely than not, the entity is then required to
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perform the existing two-step quantitative impairment test, otherwise no further analysis is required. An entity also may elect not to perform the qualitative assessment and, instead, proceed directly to the two-step quantitative impairment test. The adoption of these changes had no impact on the consolidated financial statements.
In July 2012, the Financial Accounting Standards Board (“FASB”) issued changes to the testing of indefinite-lived intangible assets for impairment, similar to the goodwill changes issued in September 2011. These changes provide an entity the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not (more than 50%) that the fair value of an indefinite-lived intangible asset is less than its carrying amount. Such qualitative factors may include the following: macroeconomic conditions; industry and market considerations; cost factors; overall financial performance; and other relevant entity-specific events. If an entity elects to perform a qualitative assessment and determines that an impairment is more likely than not, the entity is then required to perform the existing two-step quantitative impairment test, otherwise no further analysis is required. An entity also may elect not to perform the qualitative assessment and, instead, proceed directly to the two-step quantitative impairment test. These changes became effective for us for any indefinite-lived intangible asset impairment test performed on January 1, 2013 or later. The adoption of these changes did not impact the consolidated financial statements.
In December 2011, the FASB issued changes to the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The enhanced disclosures will enable users of an entity’s financial statements to understand and evaluate the effect or potential effect of master netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. These changes became effective for us on January 1, 2013. Other than the additional disclosure requirements, the adoption of these changes did not impact the consolidated financial statements.
Issued
In May 2014, the FASB issued new recognition and disclosure requirements for revenue from contracts with customers, which supersedes the existing revenue recognition guidance. The new recognition requirements focus on when the customer obtains control of the goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity will recognize revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements will include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments and changes in judgments and assets recognized from the costs to obtain or fulfill a contract. Entities will generally be required to make more estimates and use more judgment under the new standard. The new requirements will be effective for us beginning January 1, 2018, and may be implemented either retrospectively for all periods presented, or as a cumulative-effect adjustment as of January 1, 2018. Early adoption is permitted, but not before January 1, 2017. Management is currently evaluating the potential impact of this new guidance on our consolidated financial statements and which implementation approach to select.
In August 2014, the FASB issued changes to the disclosure of uncertainties about an entity’s ability to continue as a going concern. Under GAAP, continuation of a reporting entity as a going concern is presumed as the basis for preparing financial statements unless and until the entity’s liquidation becomes imminent. Even if an entity’s liquidation is not imminent, there may be conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern. Because there is no guidance in GAAP about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern or to provide related note disclosures, there is diversity in practice whether, when, and how an entity discloses the relevant conditions and events in its financial
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statements. As a result, these changes require an entity’s management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that financial statements are issued. Substantial doubt is defined as an indication that it is probable that an entity will be unable to meet its obligations as they become due within one year after the date that financial statements are issued. If management has concluded that substantial doubt exists, then the following disclosures should be made in the financial statements: (i) principal conditions or events that raised the substantial doubt, (ii) management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations, (iii) management’s plans that alleviated the initial substantial doubt or, if substantial doubt was not alleviated, management’s plans that are intended to at least mitigate the conditions or events that raise substantial doubt, and (iv) if the latter in (iii) is disclosed, an explicit statement that there is substantial doubt about the entity’s ability to continue as a going concern. These changes become effective for us for financial statements issued after December 15, 2016. We are currently evaluating the potential impact of these changes on the consolidated financial statements. Subsequent to adoption, this guidance will need to be applied by management at the end of each annual period and interim period therein to determine what, if any, impact there will be on the consolidated financial statements in a given reporting period.
In January 2015, the FASB issued changes to the presentation of extraordinary items. Such items are defined as transactions or events that are both unusual in nature and infrequent in occurrence, and, currently, are required to be presented separately in an entity’s income statement, net of income tax, after income from continuing operations. The changes eliminate the concept of an extraordinary item and, therefore, the presentation of such items will no longer be required. Notwithstanding this change, an entity will still be required to present and disclose a transaction or event that is both unusual in nature and infrequent in occurrence in the notes to the financial statements. These changes become effective for us on January 1, 2016. We have determined that the adoption of these changes will not have an impact on the consolidated financial statements.
In February 2015, the FASB issued changes to the analysis that an entity must perform to determine whether it should consolidate certain types of legal entities. These changes (i) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminate the presumption that a general partner should consolidate a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships, and (iv) provide a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. These changes become effective for us on January 1, 2016. We are currently evaluating the potential impact of these changes on the consolidated financial statements.
In April 2015, the FASB issued changes to the presentation of debt issuance costs. Currently, such costs are required to be presented as a noncurrent asset in an entity’s balance sheet and amortized into interest expense over the term of the related debt instrument. The changes require that debt issuance costs be presented in an entity’s balance sheet as a direct deduction from the carrying value of the related debt liability. The amortization of debt issuance costs remains unchanged. These changes become effective for us on January 1, 2016. Management has determined that the adoption of these changes will result in a decrease of approximately $42.4 million based on the outstanding amount at December 31, 2015 to both deferred financing costs located in noncurrent assets and long-term debt on the accompanying consolidated balance sheets.
In July 2015, the FASB issued changes to the subsequent measurement of inventory. Currently, an entity is required to measure its inventory at the lower of cost or market, whereby market can be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. The changes require that inventory be measured at the lower of cost and net realizable value, thereby eliminating the use of the other two market methodologies. Net realizable value is defined as the estimated selling prices in the ordinary course of business less
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reasonably predictable costs of completion, disposal, and transportation. These changes become effective for us on January 1, 2017. Management has determined that the adoption of these changes will not have an impact on the consolidated financial statements.
In September 2015, the FASB issued new guidance on adjustments to provisional amounts recognized in a business combination, which are currently recognized on a retrospective basis. Under the new requirements, adjustments will be recognized in the reporting period in which the adjustments are determined. The effects of changes in depreciation, amortization, or other income arising from changes to the provisional amounts, if any, are included in earnings of the reporting period in which the adjustments to the provisional amounts are determined. An entity is also required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new requirements will be effective for us beginning January 1, 2016, and are required to be implemented on a prospective basis. Early adoption is permitted. We will apply this new guidance to any future business combinations.
In November 2015, the FASB issued changes to the balance sheet classification of deferred taxes. These changes simplify the presentation of deferred income taxes by requiring all deferred income tax assets and liabilities, along with any related valuation allowance, to be classified as noncurrent in a classified balance sheet. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by these changes. The new guidance will be effective us in fiscal years beginning after December 15, 2016 and is not expected to have an impact on the consolidated financial statements.
3. Divestments
2015 Divestments
(a) Wind Projects
On March 31, 2015, Atlantic Power Transmission (“APT”), our wholly-owned, direct subsidiary, entered into the Purchase Agreement with TerraForm AP Acquisition Holdings, LLC (“TerraForm”), an affiliate of SunEdison, Inc., to sell our Wind Projects. On June 26, 2015, the sale was completed for aggregate cash proceeds of approximately $335 million after transaction fees, exclusive of transaction-related taxes. We recorded a $46.8 million gain on sale, which is included as a component of income from discontinued operations in the consolidated statements of operations for the year ended December 31, 2015.
Terraform acquired from APT, 100% of APT’s direct membership interests in a holding company formed to facilitate the sale, thereby acquiring our indirect interests in our portfolio of Wind Projects consisting of five operating wind projects in Idaho and Oklahoma and representing 521 MW net ownership: Goshen (12.5% economic interest), Idaho Wind (27.6% economic interest), Meadow Creek (100% economic interest); Rockland Wind Farm (50% economic interest, but consolidated on a 100% basis); and Canadian Hills (99% economic interest). As a result of the sale, we deconsolidated approximately $249 million of project debt (or approximately $274 million as adjusted for our proportional ownership of Rockland, Goshen North and Idaho Wind) and approximately $224 million of non-controlling interest related to tax equity interests at Canadian Hills and the minority ownership interests at Rockland and Canadian Hills.
The Wind Projects were designated as assets held for sale and discontinued operations on March 31, 2015, the date we established a firm commitment to a plan to sell the wind assets. Our determination to designate the Wind
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Projects as discontinued operations was based on the impact the sale will have on our operations and financial results and because the Wind Projects made up the entirety of our Wind reportable Segment. We stopped depreciating the property, plant and equipment of the Wind Projects on the designation date.
(b)Frontier
On April 22, 2015, our indirect wholly-owned subsidiary, Ridgeline Energy LLC (‘‘Ridgeline’), closed a transaction with CRE-Frontier Solar California LLC (‘‘CRE’’), a subsidiary of Centaurus Renewable Energy LLC, whereby CRE agreed to purchase 100% of Ridgeline’s equity interests in Frontier Solar, LLC (‘‘Frontier’’), which is developing an approximately 20 MW solar electric generating facility in California, for net cash proceeds of $4.3 million. If Frontier achieves commercial operations and meets certain operating performance metrics, we could receive additional cash proceeds. We recorded a $2.3 million gain on sale related to the transaction in other income in the consolidated statements of operations for the year ended December 31, 2015. Frontier is not accounted for as a component of discontinued operations.
2014 Divestments
(a)Delta-Person
In December 2012, we and the other owners of Delta-Person, entered into a purchase and sale agreement with BHB Power, LLC and Public Service Company of New Mexico to sell the project for approximately $37.2 million including working capital adjustments. The sale of Delta-Person closed in July 2014 resulting in a gain on sale of approximately $8.6 million in the consolidated statement of operations for the year ended December 31, 2014. We received net cash proceeds in July 2014 for our ownership interest of approximately $7.2 million in the aggregate. Delta-Person is not accounted for as a component of discontinued operations.
(b)Greeley
In March 2014, we closed a transaction with Initium Power Partners, LLC. (“Initium”), whereby Initium agreed to purchase all of the issued and outstanding membership interests in Greeley for approximately $1.0 million. We recorded a $2.1 million non-cash gain on the sale, which is included as a component of income from discontinued operations in the consolidated statement of operations for the year ended December 31, 2014.
2013 Divestments
(a)
Rollcast
On November 5, 2013, we completed the sale of our 60% interest in Rollcast to its remaining shareholders. As consideration for the sale, we were assigned asset management contracts valued at $0.5 million for the Cadillac and Piedmont projects as well as the remaining 2% ownership interest in Piedmont bringing our total ownership to 100%. In return, we paid $0.5 million in cash to the minority owner and forgave an outstanding $1.0 million loan that was provided by us to Rollcast to fund working capital during 2013. We recorded a $1.0 million gain on sale in the consolidated statements of operations for the year ended December 31, 2013. Rollcast’s net loss is recorded as loss from discontinued operations in the consolidated statements of operations for the year ended December 31, 2013.
(b)
Gregory
On April 2, 2013, we and the other owners of Gregory entered into a purchase and sale agreement with an affiliate of NRG Energy, Inc. to sell the project for approximately $274.2 million, including working capital adjustments.
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The sale of Gregory closed on August 7, 2013 resulting in a gain on sale of $30.4 million that was recorded in the consolidated statements of operations for the year ended December 31, 2013. We received net cash proceeds for our ownership interest of approximately $34.6 million in the aggregate, after repayment of project-level debt and transaction expenses. As of December 31, 2015, approximately $0.4 million of these proceeds remain in escrow for any post-closing adjustments that may arise subsequent to the closing date. We used the net proceeds from the sale for general corporate purposes.
(c)
Auburndale, Lake and Pasco
On January 30, 2013, we entered into a purchase and sale agreement for the sale of our Auburndale Power Partners, L.P. (“Auburndale”), Lake CoGen, Ltd. (“Lake”) and Pasco CoGen, Ltd. (“Pasco”) projects (collectively, the “Florida Projects”) for approximately $140.0 million, with working capital adjustments. The sale closed on April 12, 2013 and we received net cash proceeds of approximately $117.0 million in the aggregate, after repayment of project-level debt at Auburndale and settlement of all outstanding natural gas swap agreements at Lake and Auburndale. This includes approximately $92.0 million received at closing and cash distributions from the Florida Projects of approximately $25.0 million received since January 1, 2013. We used a portion of the net proceeds from the sale to fully repay our senior credit facility, which had an outstanding balance of approximately $64.1 million on the closing date. The remaining cash proceeds were used for general corporate purposes. The Florida Projects are accounted for as a component of discontinued operations in the consolidated statements of operations for the year ended December 31, 2013. See Note 21, Discontinued operations, for further information.
(d)
Path 15
On March 11, 2013, we entered into a purchase and sales agreement with Duke Energy Corporation and American Transmission Co., to sell our interests in the Path 15 transmission line (“Path 15”). The sale closed on April 30, 2013 and we received net cash proceeds from the sale, including working capital adjustments, of approximately $52.0 million, plus a management agreement termination fee of $4.0 million, for a total sale price of approximately $56.0 million. The cash proceeds were used for general corporate purposes. All project-level debt issued by Path 15, totaling $137.2 million, transferred with the sale. Path 15 is accounted for as a component of discontinued operations in the consolidated statements of operations for the year ended December 31, 2013. See Note 21, Discontinued operations, for further information.
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4. Changes in accumulated other comprehensive loss by component
The changes in accumulated other comprehensive loss by component were as follows:
(1)
In all periods presented, there were no tax impacts related to rate changes and no amounts were reclassified to earnings (loss).
(2)
This amount was included in Interest expense, net on the accompanying consolidated statements of operations.
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5. Equity method investments in unconsolidated affiliates
The following tables summarize our equity method investments in unconsolidated affiliates:
Equity (deficit) in earnings (loss) of equity method investments was as follows:
(1)
We sold Gregory in August 2013, resulting in a gain on sale of approximately of $30.4 million, which is recorded in gain on sale of equity investments in the consolidated statements of operations for the year ended December 31, 2013.
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The following summarizes the financial position at December 31, 2015, 2014 and 2013, and operating results for the years ended December 31, 2015, 2014 and 2013, respectively, for our proportional ownership interest in equity method investments:
(1)
Excludes Idaho Wind Partners 1, LLC and Goshen, which were sold in June 2015 as a part of the sale of the Wind Projects.
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1)
Excludes Idaho Wind Partners 1, LLC and Goshen, which were sold in June 2015 as a part of the sale of Wind Projects.
6. Inventory
Inventory consists of the following:
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7. Property, plant and equipment
Depreciation expense of $59.0 million, $64.6 million and $64.4 million was recorded for the years ended December 31, 2015, 2014 and 2013, respectively.
As described in Note 8, Goodwill, we recorded a $76.6 million and $9.6 million long-lived asset impairment to property, plant and equipment in the years ended December 31, 2015 and 2014, respectively.
8. Goodwill
Our goodwill balance was $134.5 million and $197.2 million as of December 31, 2015 and December 31, 2014, respectively. We apply an accounting standard under which goodwill has an indefinite life and is not amortized. Goodwill is tested for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test goodwill for impairment at the reporting unit level, which is at the project level and, the lowest level below the operating segments for which discrete financial information is available.
In the fourth quarter of 2015, we performed our annual goodwill impairment test as of November 30, 2015. Of the total reporting units with goodwill recorded, only Morris ($3.3 million of goodwill at December 31, 2015), Nipigon ($3.6 million of goodwill at December 31, 2015) and Mamquam ($64.1 million of goodwill at December 31, 2015) passed step 1 of the two-step test. The total fair value of these reporting units exceeded their carrying value by approximately $118.0 million or 37%. The Williams Lake, Calstock, Curtis Palmer, North Bay, Kapuskasing and Moresby Lake reporting units all failed step 1 of the two-step test.
Because these reporting units failed step 1 of the two-step goodwill impairment test, we identified a triggering event and initiated a test of the recoverability of each of the reporting units’ long-lived assets. The asset group for testing the long-lived assets for impairment is the same as the reporting unit for goodwill impairment testing purposes. In order to test the recoverability of the assets in the asset groups, we compared the carrying amount of the assets to estimated undiscounted future cash flows expected to be generated by the asset group. The carrying value of each asset group includes its recorded property, plant equipment, intangible assets related to PPAs and goodwill. Of the five asset groups tested, the Williams Lake and Calstock asset groups (Canada segment) failed the recoverability test. For these asset groups, we estimated their fair value utilizing an income approach based on market participant assumptions. These assumptions include estimated cash flows from both contracted and uncontracted periods over the remaining useful lives of the Williams Lake and Calstock asset groups. We determined that the carrying value exceeded the fair value at both asset groups and recorded an impairment of $74.1 million and $2.5 million to the property, plant and equipment of the Williams Lake and Calstock reporting units, respectively, for the year ended December 31, 2015.
Subsequent to recording long-lived asset impairments, we completed our annual goodwill impairment assessment. For each of the reporting unit that failed step 1 of the two-step test, we performed a step 2 analysis. As a
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result of this analysis, we recorded a $35.6 million full impairment at the Williams Lake reporting unit, a $13.7 million partial impairment at the Curtis Palmer reporting unit and a $1.9 million full impairment at the Calstock reporting unit in the year ended December 31, 2015. At the time of their acquisition in November 2011, the fair value of the assets acquired and liabilities assumed for the Williams Lake, Curtis Palmer and Calstock reporting units were valued assuming a merchant basis for the period subsequent to the expiration of the projects’ original PPAs. The forecasted energy revenue on a merchant basis, in the respective markets in which those plants operate, was higher than the energy prices currently forecasted to be in effect subsequent to the expiration of the reporting unit’s PPA. Power prices, in the respective markets in which those plants operate, have declined from 2011and from the dates of our previous impairment assessments due to several factors including decreased demand, lower oil prices and lower natural gas prices resulting from an abundance of shale gas. Our forecasts for discounted cash flows also reflect a higher level of uncertainty for re-contracting at prices than were previously forecasted in 2011. Furthermore, the PPA at the Curtis Palmer reporting unit expires at the earlier of December 2027 or the provision of 10,000 GWh of generation. Based on Curtis Palmer’s cumulative generation through the date of the goodwill impairment test, we anticipate the PPA expiring two years before December 2027. As a result, the discounted cash flow model for Curtis Palmer utilizes forward power prices for that two-year period that are substantially lower than the prices under the current PPA.
The long-lived asset and goodwill impairment charges were recorded in the fourth quarter of 2015 and not earlier in the fiscal year because we did not identify any triggering events that would have required an event-driven impairment assessment. The triggering event for testing long-lived assets was identified through our annual test of goodwill. While declining oil prices over the past year have affected long-term power prices, the continued depressed price of oil and the long-term outlook for sustained low oil prices in the fourth quarter of 2015 had the most significant impact to the key inputs to our long-term forecasted cash flow models.
During the third quarter of 2014, we performed an event-driven goodwill impairment test based on the continued deficit of our market capitalization as compared to our book carrying value. The test was performed as of August 31, 2014. As a result of the event-driven goodwill assessment, we recorded a $17.9 million full impairment at the Kenilworth reporting unit (East U.S. segment), a $50.2 million full impairment at the Manchief reporting unit (West U.S. segment) and a $23.7 million partial impairment at the Williams Lake reporting unit (Canada segment). The total impairment recorded in the three months ended September 30, 2014 was $91.8 million. The goodwill impairment recorded at each reporting unit was primarily due to (i) decreases in forward merchant energy prices subsequent to the expiration of the reporting units’ respective ESA or PPA, as applicable, as compared to the assumptions at the time of the reporting units’ acquisition in November 2011, (ii) the continued amortization of cash flows under the reporting units’ respective ESA or PPAs and (iii) an increase in the discount rate reflecting increased re-contracting risk. At the time of its acquisition in November 2011, the fair value of the assets acquired and liabilities assumed for each of the Kenilworth, Manchief and Williams Lake reporting units were valued assuming a merchant basis for the period subsequent to the expiration of the projects’ original ESAs or PPAs. As discussed above, these forecasted energy revenues on a merchant basis were higher than the energy prices currently forecasted to be in effect subsequent to the expiration of these reporting units’ ESAs or PPAs. Power prices have declined from 2011 due to several factors including decreased demand and lower natural gas and oil prices resulting from an abundance of shale gas. Our forecasts for discounted cash flows also reflect a higher level of uncertainty for re-contracting at prices that were previously forecasted in 2011.
Under our accounting policies for long-lived assets and goodwill impairment, we also perform an impairment analysis at the earlier of (i) executing a new PPA (or other arrangement) and (ii) six months prior to the expiration of an existing PPA. The Tunis project’s PPA expired on December 31, 2014 and accordingly, we performed a long-lived asset impairment test and a goodwill impairment test as of June 30, 2014. Based on the results of our long-lived asset impairment test, it was determined that the weighted average estimated undiscounted cash flows for Tunis over its remaining useful life did not exceed the carrying value of the property, plant and equipment at the Tunis reporting unit. As a result, the project recorded a $9.6 million long-lived asset impairment charge in the three months ended June 30,
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2014 which was the difference between the carrying value of the project’s property, plant and equipment and its estimated fair market value. Subsequent to adjusting the carrying value of the Tunis reporting unit for the $9.6 million long-lived asset impairment, we performed an impairment analysis for the project’s goodwill. The project failed step 1 of the impairment test because the weighted average estimated discounted cash flows over its remaining useful life did not exceed the carrying value of the Tunis reporting unit. We performed step 2 of the goodwill impairment test and impaired all of the project’s goodwill because the carrying value of goodwill exceeded its implied fair value. As a result, Tunis, a component of the Canada segment, recorded a $5.2 million goodwill impairment charge in the three months ended June 30, 2014. The total $14.8 million long-lived asset and goodwill impairment was primarily due to our assessment of the forecasted cash flows from re-contracting and other strategic outcomes.
We determine the fair value of our reporting units using an income approach with discounted cash flow (“DCF”) models, as we believe forecasted cash flows are the best indicator of such fair value. A number of significant assumptions and estimates are involved in the application of the DCF model to forecast operating cash flows, including assumptions about discount rates, projected merchant power prices, generation, fuel costs and capital expenditure requirements. The undiscounted and discounted cash flows utilized in our long-lived asset recovery and step 1 and 2 goodwill impairment tests for our reporting units are generally based on approved reporting unit operating plans for years with contracted PPAs and historical relationships for estimates at the expiration of PPAs. All cash flow forecasts from DCF models utilized estimated plant output for determining assumptions around future generation and industry data forward power and fuel curves to estimate future power and fuel prices. We used historical experience to determine estimated future capital investment requirements. The discount rate applied to the DCF models represents the weighted average cost of capital (“WACC”) consistent with the risk inherent in future cash flows of the particular reporting unit and is based upon an assumed capital structure, cost of long-term debt and cost of equity consistent with comparable independent power producers. The betas used in calculating the WACC rate were obtained from reputable third party sources. We utilized the assistance of valuation experts to perform step 1 and step 2 of the quantitative impairment test for several of our reporting units. The fair value that could be realized in an actual transaction may differ from that used to evaluate the impairment of goodwill.
The valuation of long-lived assets and goodwill for the impairment analyses is considered a level 3 fair value measurement, which means that the valuation of the assets and liabilities reflect management’s own judgments regarding the assumptions market participants would use in determining the fair value of the assets and liabilities. Fair value determinations require considerable judgment and are sensitive to changes in these underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of a goodwill impairment test will prove to be accurate predictions of the future. Examples of events or circumstances that could reasonably be expected to negatively affect the underlying key assumptions and ultimately impact the estimated fair value of our reporting units may include macroeconomic factors that significantly differ from our assumptions in timing or degree, increased input costs such as higher fuel prices and maintenance costs, or lower power prices than incorporated in our long-term forecasts.
The following table is a rollforward of goodwill for the year ended December 31, 2015:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
9. Power purchase agreements and other intangible assets and liabilities
Other intangible assets and liabilities include power purchase agreements, fuel supply agreements and capitalized development costs.
The following tables summarize the components of our intangible assets and other liabilities subject to amortization for the years ended December 31, 2015 and 2014:
The following table presents amortization expense of intangible assets for the years ended December 31, 2015, 2014 and 2013:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
The following table presents estimated future amortization expense for the next five years related to power purchase agreements and fuel supply agreements:
The following table presents the weighted average remaining amortization period related to our intangible assets as of December 31, 2015:
10. Other long-term liabilities
Other long-term liabilities consist of the following:
The following table is a rollforward of asset retirement obligations for the year ended December 31, 2015:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
11. Long-term debt
Long-term debt consists of the following:
Current maturities consist of the following:
(1)
LIBOR cannot be less than 1.00%. On May 5, 2014 we entered into interest rate swap agreements to mitigate the exposure to changes in LIBOR for $199.0 million notional amount ($153.6 million at December 31, 2015) of the $600.0 million ($473.2 million at December 31, 2015) outstanding aggregate borrowings under our senior secured term loan facility. See Note 14, Accounting for derivative instruments and hedging activities for further details.
(2)
Excludes non-recourse debts of $164.9 million and $83.8 million from Meadow Creek term loan and Rockland term loan as of December 31, 2014, respectively. Both debts are resolved as part of our sale of the Wind Projects. See Note 3, Divestments.
Principal payments on the maturities of our debt due in the next five years and thereafter are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
Senior Secured Credit Facilities
On February 24, 2014, Atlantic Power Limited Partnership (“the Partnership”), our wholly-owned indirect subsidiary, entered into a new senior secured term loan facility (the “Term Loan Facility”), comprising of $600 million in aggregate principal amount, and a new senior secured revolving credit facility (the “Revolving Credit Facility”) with a capacity of $210 million (collectively, the “Senior Secured Credit Facilities”). Borrowings under the Senior Secured Credit Facilities are available in U.S. dollars and Canadian dollars and bear interest at a rate equal to the Adjusted Eurodollar Rate (LIBOR), the Base Rate or the Canadian Prime Rate, each as defined in the credit agreement governing the Senior Secured Credit Facilities (the “Credit Agreement”), as applicable, plus an applicable margin between 2.75% and 3.75% that varies depending on whether the loan is a Eurodollar Rate Loan, Base Rate Loan, or Canadian Prime Rate Loan. The applicable margin for term loans bearing interest at the Adjusted Eurodollar Rate and the Base Rate is 3.75% and 2.75% respectively and was 3.75% at December 31, 2015. The Adjusted Eurodollar Rate cannot be less than 1.00% (1.00% at December 31, 2015). As further described in Note 14, the Partnership entered into interest rate swap agreements on May 5, 2014 to mitigate the exposure to changes in the Adjusted Eurodollar Rate for a portion of the Term Loan Facility.
In connection with the funding of the Senior Secured Credit Facilities, we terminated our prior revolving credit facility on February 26, 2014.
The Term Loan Facility matures on February 24, 2021. The revolving commitments under the Revolving Credit Facility terminate on February 24, 2018. Letters of credit are available to be issued under the revolving commitments until 30 days prior to the Letter of Credit Expiration Date under, and as defined in, the Credit Agreement. The Partnership is required to pay a commitment fee with respect to the commitments under the Revolving Credit Facility equal to 0.75% times the average of the daily difference between the revolving commitments and all outstanding revolving loans (excluding swing line loans) plus amounts available to be drawn under letters of credit and all outstanding reimbursement obligations with respect to drawn letters of credit.
The Senior Secured Credit Facilities are secured by a pledge of the equity interests in the Partnership and its subsidiaries, guaranties from the Partnership subsidiary guarantors and a limited recourse guaranty from the entity that holds all of the Partnership equity, a pledge of certain material contracts and certain mortgages over material real estate rights, an assignment of all revenues, funds and accounts of the Partnership and its subsidiaries (subject to certain exceptions), and certain other assets. The Senior Secured Credit Facilities are not otherwise guaranteed or secured by us or any of our subsidiaries (other than the Partnership subsidiary guarantors). The Senior Secured Credit Facilities have a debt service reserve account, which is required to be funded and maintained at the debt service reserve requirement, equal to six months of debt service. The debt service reserve requirement was funded with a $15.8 million letter of credit.
The Partnership’s existing Cdn$210 million aggregate principal amount of 5.95% Medium Term Notes due June 23, 2036 (the “MTNs”) prohibit the Partnership (subject to certain exceptions) from granting liens on its assets (and those of its material subsidiaries) to secure indebtedness, unless the MTNs are secured equally and ratably with such other indebtedness. Accordingly, in connection with the execution of the Credit Agreement, the Partnership has granted an equal and ratable security interest in the collateral package securing the Senior Secured Credit Facilities under the indenture governing the MTNs for the benefit of the holders of the MTNs.
The Credit Agreement contains customary representations, warranties, terms and conditions, and covenants. The covenants include a requirement that the Partnership and its subsidiaries maintain a Leverage Ratio (as defined in the Credit Agreement) ranging from 5.25:1.00 in 2014 to 4.00:1.00 in 2021, and an Interest Coverage Ratio (as defined in the Credit Agreement) ranging from 2.50:1.00 in 2014 to 3.25:1.00 in 2021. In addition, the Credit Agreement includes customary restrictions and limitations on the Partnership’s and its subsidiaries’ ability to (i) incur additional
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
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 thresholds.
Under the Credit Agreement, if a change of control (as defined in the Credit Agreement) occurs, unless the Partnership elects to make a voluntary prepayment of the term loans under the Senior Secured Credit Facilities, it will be required to offer each electing lender to prepay such lender’s term loans under the Senior Secured Credit Facilities at a price equal to 101% of par. In addition, in the event that the Partnership elects to repay, prepay or refinance all or any portion of the term loan facilities within one year from the initial funding date under the Credit Agreement, it will be required to do so at a price of 101% of the principal amount so repaid, prepaid or refinanced.
The Credit Agreement also contains a mandatory amortization feature and customary mandatory prepayment provisions, including: (i) from proceeds of assets sales, insurance proceeds, and incurrence of indebtedness, in each case subject to applicable thresholds and customary carve-outs; and (ii) the payment of 50% of the excess cash flow, as defined in the Credit Agreement, of the Partnership and its subsidiaries.
Under certain conditions the lending commitments under the Credit Agreement may be terminated by the lenders and amounts outstanding under the Credit Agreement may be accelerated. Such events of default include failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations or warranties in any material respect, non-payment or acceleration of other material debt of the Partnership and its subsidiaries, bankruptcy, material judgments rendered against the Partnership or certain of its subsidiaries, certain ERISA or regulatory events, a change of control of the Partnership, or defaults under certain guaranties and collateral documents securing the Senior Secured Credit Facilities, in each case subject to various exceptions and notice, cure and grace periods.
On February 26, 2014, $600 million was drawn under the Term Loan Facility, and letters of credit in an aggregate face amount of $144.1 million ($104.0 million as of December 31, 2015) were issued (but not drawn) pursuant to the revolving commitments under the Revolving Credit Facility and used to (i) satisfy a debt service reserve requirement in an amount equivalent to six months of debt service (approximately $15.8 million) and (ii) support contractual credit support obligations of the Partnership and its subsidiaries and of certain other of our affiliates.
Notes of the Partnership
The Partnership, a wholly-owned subsidiary acquired on November 5, 2011, has outstanding Cdn$210.0 million ($151.7 million as of December 31, 2015) aggregate principal amount of 5.95% senior unsecured notes, due June 2036 (MTNs). Interest on the MTNs is payable semi-annually at 5.95%. Pursuant to the terms of the MTNs, we must meet certain financial and other covenants, including a financial covenant generally based on the ratio of debt to capitalization of the Partnership. The MTNs are guaranteed by Atlantic Power Corporation and Atlantic Power Preferred Equity Ltd., an indirect, wholly-owned subsidiary acquired in connection with the acquisition of the Partnership.
Non-Recourse Debt
Project-level debt of our consolidated projects is secured by the respective project and its contracts with no other recourse to us. Project-level debt generally amortizes during the term of the respective revenue generating contracts of the projects. The loans have certain financial covenants that must be met in order to distribute available cash. At December 31, 2015, all of our projects, with the exception of Piedmont, were in compliance with the covenants contained in project-level debt. We do not expect our Piedmont project to meet its debt service coverage ratio covenants or to make distributions before the project’s debt maturity in 2018 at the earliest, due to continued operational issues that
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
have resulted in higher forecasted maintenance and fuel expenses than initially expected.
12. Convertible debentures
The following table provides details related to outstanding convertible debentures:
Aggregate interest expense related to the convertible debentures was $17.2 million, $22.8 million, and $24.2 million for the years ended December 31, 2015, 2014, and 2013, respectively.
In 2006 we issued, in a public offering, Cdn$60.0 million aggregate principal amount of 6.25% convertible secured debentures (the “2006 Debentures”) for gross proceeds of $52.8 million. The 2006 Debentures paid interest semi-annually on April 30 and October 31 of each year, had an initial maturity date of October 31, 2011 and were convertible into approximately 80.6452 common shares per Cdn$1,000 principal amount of 2006 Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$12.40 per common share. The 2006 Debentures were secured by a subordinated pledge of our interest in certain subsidiaries and contain certain restrictive covenants. In connection with our conversion to a common share structure on November 27, 2009, the holders of the 2006 Debentures approved an amendment to increase the annual interest rate from 6.25% to 6.50% and separately, an extension of the maturity date from October 2011 to October 2014. Over the maturity term of the 2006 Debentures, Cdn$15.2 million of the 2006 Debentures were converted to 1.2 million common shares. On October 31, 2014, we used Cdn$44.8 million of cash on hand to repay the 2006 Debentures at maturity.
On December 17, 2009, we issued, in a public offering, Cdn$86.3 million aggregate principal amount of 6.25% convertible unsecured debentures (the “2009 Debentures”) for gross proceeds of $82.1 million. The 2009 Debentures pay interest semi-annually on March 15 and September 15 of each year. The 2009 Debentures mature on March 15, 2017 and are convertible into approximately 76.9231 common shares per Cdn$1,000 principal amount of 2009 Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$13.00 per common share. As of December 31, 2015, a cumulative Cdn$18.8 million of the 2009 Debentures, have been converted to 1.4 million common shares.
On October 20, 2010, we issued, in a public offering, Cdn$80.5 million aggregate principal amount of 5.60% convertible unsecured subordinated debentures (the “2010 Debentures”) for gross proceeds of $78.9 million. The 2010 Debentures pay interest semi-annually on June 30 and December 30 of each year. The 2010 Debentures mature on June 30, 2017, unless earlier redeemed. The debentures are convertible into our common shares at an initial conversion
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
rate of 55.2486 common shares per Cdn$1,000 principal amount of 2010 Debentures, at any time, at the option of the holder, representing an initial conversion price of approximately Cdn$18.10 per common share.
On July 5, 2012, we issued, in a public offering, $130.0 million aggregate principal amount of 5.75% convertible unsecured subordinated debentures due June 30, 2019 (the “July 2012 Debentures”) for net proceeds of $124.0 million. The July 2012 Debentures pay interest semi-annually on the last day of June and December of each year. The July 2012 Debentures are convertible into our common shares at an initial conversion rate of 57.9710 common shares per $1,000 principal amount of July 2012 debentures representing a conversion price of $17.25 per common share. We used the proceeds to fund a portion of our equity commitment in Canadian Hills.
On December 11, 2012, we issued, in a public offering, Cdn$100 million aggregate principal amount of 6.00% convertible unsecured subordinated debentures due December 31, 2019 (the “December 2012 Debentures”) for net proceeds of Cdn$95.5 million. The December 2012 Debentures pay interest semi-annually on the last day of June and December of each year beginning June 30, 2013. The December 2012 Debentures are convertible into our common shares at an initial conversion rate of 68.9655 common shares per Cdn$1,000 principal amount of December 2012 Debentures representing a conversion price of Cdn$14.50 per common share. We used the proceeds to acquire all of the outstanding shares of capital stock of Ridgeline and to fund certain working capital commitments and acquisition expenses related to Ridgeline.
On November 11, 2014, we commenced a normal course issuer bid (“NCIB”) for our convertible debentures. Under the NCIB, we entered into a pre-defined automatic securities purchase plan with our broker in order to facilitate purchases of our convertible debentures which expired on November 10, 2015. As of December 31, 2015, we had repurchased and cancelled $24.8 million of convertible debentures and recorded a gain of $3.1 million in the consolidated statement of operations related to these transactions. On December 29, 2015, we commenced a new NCIB, which will expire on December 28, 2016. The actual amount of convertible debentures that may be purchased under the NCIB is approximately $28.5 million and is further limited to 10% of the public float of our convertible debentures.
13. Fair value of financial instruments
The estimated carrying values and fair values of our recorded financial instruments related to operations are as follows:
Our financial instruments that are recorded at fair value have been classified into levels using a fair value hierarchy.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
The three levels of the fair value hierarchy are defined below:
Level 1-Unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Financial assets utilizing Level 1 inputs include active exchange-traded securities.
Level 2-Quoted prices available in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are directly observable, and inputs derived principally from market data.
Level 3-Unobservable inputs from objective sources. These inputs may be based on entity-specific inputs. Level 3 inputs include all inputs that do not meet the requirements of Level 1 or Level 2.
The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of December 31, 2015 and December 31, 2014. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
The fair values of our derivative instruments are based upon trades in liquid markets. Valuation model inputs can generally be verified and valuation techniques do not involve significant judgment. The fair values of such financial instruments are classified within Level 2 of the fair value hierarchy. We use our best estimates to determine the fair value of commodity and derivative contracts we hold. These estimates consider various factors including closing exchange prices, time value, volatility factors and credit exposure. The fair value of each contract is discounted using a risk free interest rate.
We also adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating and the credit rating of our counterparties. As of December 31, 2015, the credit valuation adjustments resulted in a $3.8 million net increase in fair value, which consists of a $0.4 million pre-tax gain in other comprehensive income and a $3.4 million gain in change in fair value of derivative instruments. As of December 31, 2014, the credit
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
valuation adjustments resulted in a $13.0 million net increase in fair value, which consists of a $0.7 million pre-tax gain in other comprehensive income and a $12.3 million gain in change in fair value of derivative instruments.
The carrying amounts for cash and cash equivalents and restricted cash approximate fair value due to their short-term nature. The fair value of long-term debt and convertible debentures was determined using quoted market prices, as well as discounting the remaining contractual cash flows using a rate at which we could issue debt with a similar maturity as of the balance sheet date.
14. Accounting for derivative instruments and hedging activities
We recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. We have one contract designated as a cash flow hedge, and we defer the effective portion of the change in fair value of the derivatives in accumulated other comprehensive income (loss), until the hedged transactions occur and are recognized in earnings (loss). The ineffective portion of a cash flow hedge is immediately recognized in earnings (loss). For our other derivatives that are not designated as cash flow hedges, the changes in the fair value are immediately recognized in earnings (loss). These guidelines apply to our natural gas swaps, interest rate swaps, and foreign exchange contracts.
Gas purchase agreements
Gas purchase agreements to purchase gas forward at our North Bay, Kapuskasing and Nipigon projects do not qualify for the normal purchase normal sales (“NPNS”) exemption and are accounted for as derivative financial instruments. The gas purchase agreements at North Bay and Kapuskasing satisfy all of the forecasted fuel requirements for these projects through their expiration in the fourth quarter of 2016. The gas purchase agreement for Nipigon satisfies the majority of forecasted fuel requirements through December 31, 2022. These derivative financial instruments are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations.
In June 2014, the Partnership entered into contracts for the purchase of 2.9 million Gigajoules (“Gj”) of future natural gas purchases beginning on November 1, 2014 and expiring on December 31, 2017 for our projects in Ontario. These contracts effectively fix the price of approximately 98% of our expected uncontracted gas requirements for each of 2014 and 2015 and 32% and 30% of our expected uncontracted gas requirements for 2016 and 2017, respectively. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at December 31, 2015. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations.
Natural gas swaps
Our strategy to mitigate future exposure to changes in natural gas prices at our projects consists of periodically entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheets at fair value and the changes in their fair market value are recorded in the consolidated statements of operations.
The operating margin at our 50% owned Orlando project is exposed to changes in natural gas prices. We previously entered into natural gas swaps to effectively fix the price of 4.5 million Mmbtu of future natural gas purchases. On February 20, 2014, we paid $4.0 million to terminate a portion of these contracts in connection with the termination of our prior revolving credit facility. We recorded fuel expense related to the settlement of these contracts in the consolidated statement of operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
We have entered into various natural gas swaps to effectively fix the price of 6.3 million Mmbtu of future natural gas purchases at Orlando, which is approximately 100% of our share of the expected on-peak natural gas purchases at the project through 2016 or approximately 63% of our share of the expected base load natural gas purchases for 2015 and 2016, respectively. These contracts are accounted for as derivative financial instruments and are recorded in the consolidated balance sheet at fair value at December 31, 2015. Changes in the fair market value of these contracts are recorded in the consolidated statement of operations.
Interest rate swaps
The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.0% through February 15, 2015, 6.1% from February 16, 2015 to February 15, 2019, 6.3% from February 16, 2019 to February 15, 2023, and 6.4% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac’s debt. This swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025 and the effective portion of the changes in the fair market value is recorded in accumulated other comprehensive income (loss).
The Piedmont project has interest rate swap agreements to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreement effectively converts the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.8% through February 29, 2016. From February 2016 until the maturity of the debt in August 2018, the fixed rate of the swap is 4.47% and the applicable margin is 4.0%, resulting in an all-in rate of 8.5%. The swap continues at the fixed rate of 4.47% from the maturity of the debt in August 2018 until November 2030. Prior to conversion of the Piedmont Construction loan facility to a term loan, the notional amounts of the interest rate swap agreements matched the estimated outstanding principal balance of Piedmont’s construction loan facility. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively. As a result of the Piedmont term loan conversion on February 14, 2014, these swap agreements were amended to reduce the notional amounts to match the outstanding $68.5 million principal of the term loan. We recorded $1.0 million of deferred financing costs related to this transaction in the consolidated balance sheets. The interest rate swap agreements are not designated as hedges, and changes in their fair market value are recorded in the consolidated statements of operations.
On May 5, 2014 the Partnership entered into interest rate swap agreements to mitigate exposure to changes in the Adjusted Eurodollar Rate for $199.0 million notional amount ($153.6 million at December 31, 2015) of the $600 million aggregate principal amount of borrowings ($473.2 million of borrowings at December 31, 2015) under the Term Loan Facility. Borrowings under the $600 million Term Loan Facility bear interest at a rate equal to the Adjusted Eurodollar Rate plus an applicable margin of 3.75%. Based on the terms of the Credit Agreement, the Adjusted Eurodollar Rate cannot be less than 1.00% resulting in a minimum of a 4.75% all-in rate on the Term Loan Facility. As a result of entering into the swap agreements, the all-in rate for $199.0 million of the Term Loan Facility cannot be less than 4.91% if the Adjusted Eurodollar Rate is equal to or greater than 1.00%. If the Adjusted Eurodollar Rate is below 1.00%, we will pay interest at a rate equivalent to the minimum 4.75% all-in rate plus any difference between the actual Adjusted Eurodollar Rate and 1.16%. The interest rate swap agreements were effective June 30, 2014 and terminate on December 29, 2017. The interest rate swap agreements are not designated as hedges and changes in their fair market value will be recorded in the consolidated statements of operations.
Epsilon Power Partners, our wholly owned subsidiary, previously had an interest rate swap to economically fix the exposure to changes in interest rates related to the variable-rate non-recourse debt. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 7.37% and had a maturity date of July 2019. The notional amount of the swap matched the outstanding principal balance over the remaining life of Epsilon Power Partners’ debt. On February 20, 2014, we paid $2.6 million to terminate this contract in connection with the termination of our prior revolving credit facility. We recorded interest expense related to its settlement in the consolidated statement
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
of operations. This interest rate swap agreement was not designated as a hedge and changes in its fair market value were recorded in the consolidated statements of operations.
Foreign currency forward contracts
From time to time, we use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates, as many of our projects generate cash flow in U.S. dollars and Canadian dollars. On February 20, 2014, we paid $0.4 million to terminate all of our remaining foreign currency forward contracts in connection with the termination of our prior revolving credit facility and recorded their settlement in foreign exchange gain in the consolidated statement of operations for the three months ended March 31, 2014. On April 2, 2014, we executed a foreign currency forward contract in which we agreed to sell $41.0 million on September 30, 2014 and receive Cdn$45.3 million at a foreign exchange rate of Cdn$1.105 per U.S. dollar in order to mitigate the foreign exchange risk on the repayment at maturity of the Cdn$44.8 million convertible debentures due in October 2014. We recorded a $0.5 million realized foreign exchange loss on the expiration of the foreign currency forward contract on September 30, 2014. We repaid the Cdn$44.8 million convertible debentures with cash on hand at their maturity on October 31, 2014.
Volume of forecasted transactions
We have entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the NPNS exemption as of year ended December 31, 2015 and December 31, 2014:
Fair value of derivative instruments
We have elected to disclose derivative instrument assets and liabilities on a trade-by-trade basis and do not offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
Accumulated other comprehensive income
The following table summarizes the changes in the accumulated other comprehensive income (loss) (“OCI”) balance attributable to derivative financial instruments designated as a hedge, net of tax:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
Impact of derivative instruments on the consolidated statements of operations
The following table summarizes realized loss (gain) for derivative instruments not designated as cash flow hedges:
The following table summarizes the unrealized loss (gain) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:
15. Income taxes
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
The following is a reconciliation of the income taxes calculated at the Canadian enacted statutory rate of 26% at December 31, 2015, 2014 and 2013, respectively, to the provision for income taxes in the consolidated statements of operations:
The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2015 and 2014 are presented below:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
The following table summarizes the net deferred tax position as of December 31, 2015 and 2014:
As of December 31, 2015, we have recorded a valuation allowance of $175.2 million. This amount is comprised primarily of provisions against available Canadian and U.S. net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax asset will be realized. The ultimate realization of the deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.
In 2011, the IRS began an examination of our federal income tax returns for the tax years ended December 31, 2007 and 2009. On April 2, 2012, the IRS issued various Notices of Proposed Adjustments. The principal area of the proposed adjustments pertain to the classification of U.S. real property in the calculation of the gain related to our 2009 conversion from the previous Income Participating Security structure to our current traditional common share structure. On September 14, 2014, we entered into a settlement agreement with the IRS resulting in a $3.6 million increase to our taxable income for the 2009 tax year. This increase in taxable income was offset against our current year taxable losses for the 2009 tax year and therefore resulted in no cash taxes.
Tax benefits related to uncertain tax positions taken or expected to be taken on a tax return are recorded when such benefits meet a more likely than not threshold. Otherwise, these tax benefits are recorded when a tax position has been effectively settled, which means that the statute of limitation has expired or the appropriate taxing authority has completed their examination even though the statute of limitations remains open. Interest and penalties related to uncertain tax positions are recognized as part of the provision for income taxes and are accrued beginning in the period that such interest and penalties would be applicable under relevant tax law until such time that the related tax benefits are recognized. As of December 31, 2015, we have not recorded any tax benefits related to uncertain tax positions.
As of December 31, 2015, we had the following net operating loss carryforwards that are scheduled to expire in the following years:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
16. Equity compensation plans
Long-term incentive plan
The following table summarizes the changes in outstanding LTIP notional units during the years ended December 31, 2015, 2014 and 2013:
The total grant date fair value of all outstanding notional units under the LTIP was $3.7 million, $4.6 million and $4.8 million for the years ended December 31, 2015, 2014 and 2013. The weighted average remaining vesting term for outstanding notional units was 1.7 years at December 31, 2015. Approximately $1.7 million of total unrecognized compensation expense is expected to be recognized over this time period. Compensation expense related to LTIP was $3.1 million, $3.5 million and $2.2 million for the years ended December 31, 2015, 2014 and 2013, respectively. Cash payments made for vested notional units were $0.9 million, $0.7 million and $0.9 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Transition Equity Participation Agreement
We also have 550,869 transition notional shares outstanding at December 31, 2015 under the Transition Equity Participation Agreement with James J. Moore, Jr. Fifty percent of the transition notional shares granted with respect to fiscal year 2015 will vest upon the four-year anniversary of the date of grant and the remaining portion will vest on or any time after the two-year anniversary of the grant if the weighted average Canadian dollar closing price of our common shares on the TSX for at least three consecutive calendar months has exceeded the market price per common share determined as of January 22, 2015 ($2.58) by at least 50%.
17. Defined benefit plan
We sponsor and operate a defined benefit pension plan that is available to certain legacy employees of the Partnership. The Atlantic Power Services Canada LP Pension Plan (the “Plan”) is maintained solely for certain eligible legacy Partnership participants. The Plan is a defined benefit pension plan that allows for employee contributions. We expect to contribute $0.7 million to the pension plan in 2016.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
The net annual periodic pension cost related to the pension plan for the years ended December 31, 2015 and 2014 includes the following components:
A comparison of the pension benefit obligation and related plan assets for the pension plan is as follows:
Amounts recognized in the balance sheet were as follows:
Amounts recognized in accumulated OCI that have not yet been recognized as components of net periodic benefit cost were as follows, net of tax:
We estimate that there will be no amortization of net loss for the pension plan from accumulated OCI to net periodic cost over the next fiscal year.
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
The following table presents the balances of significant components of the pension plan:
The market-related value of the pension plan’s assets is the fair value of the assets. Plan assets are invested in a common collective trust which totaled $14.4 million and $16.3 million for the years ended December 31, 2015 and 2014 respectively.
We determine the level in the fair value hierarchy within which the fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety. The fair value of the common/collective trust is valued at a fair value which is equal to the sum of the market value of the fund’s investments, and is categorized as Level 2. There are no investments categorized as Level 1 or 3.
The following table presents the significant assumptions used to calculate our benefit obligations:
The following table presents the significant assumptions used to calculate our benefit expense:
We use December 31 as the measurement date for the Plan, and we set the discount rate assumptions on an annual basis on the measurement date. This rate is determined by management based on information provided by our actuary. The discount rate assumptions reflect the current rate at which the associated liabilities could be effectively settled at the end of the year. The discount rate assumptions used to determine future pension obligations as of the year ended December 31, 2015 and 2014, was based on the CIA / Natcan curve, which was designed by the Canadian Institute of Actuaries and Natcan Investment Management to provide a means for sponsors of Canadian plans to value the liabilities of their postretirement benefit plans. The CIA / Natcan curve is a hypothetical yield curve represented by extrapolating the corporate AA-rated yield curve beyond 10 years using yields on provincial AA bonds with a spread added to the provincial AA yields to approximate the difference between corporate AA and provincial AA credit risk. The CIA / Natcan curve utilizes this approach because there are very few corporate bonds rated AA or above with maturities of 10 years or more in Canada.
We employ a balanced total return investment approach, whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, and the plan’s funded status. Plan assets in the common collective trust are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across Canadian, U.S. and other international equities, as well as among growth, value and small and large capitalization stocks.
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
The pension plan assets weighted average allocations in the common collective trust were as follows:
Our expected future benefit payments for each of the next five years and in the aggregate for the five years thereafter, are as follows in Cdn$:
18. Common shares
Stock Repurchase Program
In December 2015, our Board of Directors approved an NCIB for each series of our convertible unsecured subordinated debentures, our common shares and for each series of the preferred shares of Atlantic Power Preferred Equity Ltd (“APPEL”), our wholly-owned subsidiary. The Board authorization permits the Company to repurchase stock through open market repurchases. The NCIB will expire on December 28, 2016 or such earlier date as the Company and/or APPEL complete their respective purchases pursuant to the NCIB. During the year ended December 31, 2015, we repurchased 47,300 common shares under the NCIB at a total cost of $0.1 million and through March 3, 2016, we repurchased a cumulative 575,553 common shares at a total cost of $1.0 million.
Common Share Dividends
We paid dividends of Cdn$0.03 per outstanding share to our common stockholders during the first, second, third and fourth quarters of 2015.
On February 9, 2016, we announced the elimination of our common stock dividend, effective immediately. In conjunction with the elimination of the common stock dividend, our dividend reinvestment plan (the “Plan”) also was eliminated. We filed a post-effective amendment to our registration statement on Form S-3 (Registration No. 333-194204) to deregister all of the Company’s common shares that remain unissued under the Plan.
19. Preferred shares issued by a subsidiary company
In 2007, a subsidiary acquired in our acquisition of the Partnership issued 5.0 million 4.85% Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Shares”) priced at Cdn$25.00 per share. Cumulative dividends are payable on a quarterly basis at the annual rate of Cdn$1.2125 per share. Beginning on June 30, 2012, the Series 1 Shares were redeemable by the subsidiary company at Cdn$26.00 per share, declining by Cdn$0.25 each year to Cdn$25.00 per share on or after June 30, 2016, plus, in each case, an amount equal to all accrued and unpaid dividends thereon.
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
In 2009, a subsidiary company acquired in our acquisition of the Partnership issued 4.0 million 7.0% Cumulative Rate Reset Preferred Shares, Series 2 (the “Series 2 Shares”) priced at Cdn$25.00 per share. The Series 2 Shares pay fixed cumulative dividends of Cdn$1.75 per share per annum, as and when declared, for the initial five-year period ending December 31, 2014. The dividend rate reset on December 31, 2014 and will reset every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield and 4.18%. On December 31, 2014 and on December 31 every five years thereafter, the Series 2 Shares were and will be redeemable by the subsidiary company at Cdn$25.00 per share, plus an amount equal to all declared and unpaid dividends thereon to, but excluding the date fixed for redemption. The holders of the Series 2 Shares had and will have the right to convert their shares into Cumulative Floating Rate Preferred Shares, Series 3 (the” Series 3 Shares”) of the subsidiary, subject to certain conditions, on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 3 Shares will be entitled to receive quarterly floating rate cumulative dividends, as and when declared by the board of directors of the subsidiary, at a rate equal to the sum of the then 90-day Government of Canada Treasury bill rate and 4.18%. On December 31, 2014, 1,661,906 of Series 2 shares were converted to Series 3 shares.
The Series 1 Shares, the Series 2 Shares and the Series 3 Shares are fully and unconditionally guaranteed by us and by the Partnership on a subordinated basis as to: (i) the payment of dividends, as and when declared; (ii) the payment of amounts due on a redemption for cash; and (iii) the payment of amounts due on the liquidation, dissolution or winding up of the subsidiary company. If, and for so long as, the declaration or payment of dividends on the Series 1 Shares, the Series 2 Shares or the Series 3 Shares is in arrears, the Partnership will not make any distributions on its limited partnership units and we will not pay any dividends on our common shares.
The subsidiary company paid aggregate dividends of $8.8 million on the Series 1 Shares, Series 2 Shares and Series 3 in 2015 as compared to $11.6 million in 2014.
20. Basic and diluted earnings (loss) per share
Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average common shares outstanding during their respective period. Diluted earnings (loss) per share is computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include shares that would be issued if all of the convertible debentures were converted into shares at January 1, 2015. Dilutive potential shares also include the weighted average number of shares, as of the date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP were vested and redeemed for shares under the terms of the LTIP.
Because we reported a loss for the years ended December 31, 2015, 2014 and 2013, diluted earnings per share are equal to basic earnings per share as the inclusion of potentially dilutive shares in the computation is anti-dilutive.
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
The following table sets forth the diluted net income and potentially dilutive shares utilized in the per share calculation for the years ended December 31, 2015, 2014 and 2013:
Potentially dilutive shares from convertible debentures have been excluded from fully diluted shares in the years ended December 31, 2015, 2014 and 2013 because their impact would be anti-dilutive.
21. Discontinued operations
On March 31, 2015, APT, our wholly-owned, direct subsidiary, entered into the Purchase Agreement with TerraForm, an affiliate of SunEdison, Inc., to sell our Wind Projects. On June 26, 2015, the sale was completed for aggregate cash proceeds of approximately $335 million after transaction fees, exclusive of transaction-related taxes. We recorded a $46.8 million gain on sale, which is included as a component of income from discontinued operations in the consolidated statements of operations for the year ended December 31, 2015.
On March 6, 2014, we sold our outstanding membership interests in Greeley for approximately $1.0 million and recorded a $2.1 million non cash gain on the sale related to the write off of asset retirement obligations. Greeley is accounted for as a component of discontinued operations in the consolidated statements of operations for the years ended December 31, 2015, 2014, and 2013, respectively.
On November 5, 2013, we completed the sale of our 60% interest in Rollcast to its remaining shareholders. As consideration for the sale, we were assigned asset management contracts valued at $0.5 million for the Cadillac and Piedmont projects as well as the remaining 2% ownership interest in Piedmont bringing our total ownership to 100%. In return, we paid $0.5 million in cash to the minority owner and forgave an outstanding $1.0 million loan that was provided by us to Rollcast to fund working capital during 2013. Rollcast’s net loss is recorded as loss from discontinued operations in the consolidated statements of operations for the year ended December 31, 2013.
The Florida Projects and Path 15 were sold on April 12, 2013 and April 30, 2013, respectively. Accordingly, the projects’ net income (loss) is recorded as income (loss) from discontinued operations, net of tax in the statements of operations for the years ended December 31, 2013.
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
The following table summarizes the December 31, 2014 financial position of the Wind Projects that were classified as assets held for sale:
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
The following tables summarize the revenue, loss from operations, and income tax expense of the Wind Projects, Greeley, Rollcast, Path 15 and the Florida Projects for the years ended December 31, 2015, 2014, and 2013:
The following table summarizes the operating and investing cash flows of the Wind Projects for the years ended December 31, 2015 and 2014:
Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations for the Wind Projects, Florida Projects, Path 15, Greeley and Rollcast was $0.25, ($0.10), and $0.02 for the years ended December 31, 2015, 2014, and 2013 respectively.
22. Segment and geographic information
We have four reportable segments: East U.S., West U.S., Canada and Un-Allocated Corporate. We revised our reportable business segments in the second quarter of 2015 as a result of significant project asset sales and in order to align our reportable business segments with changes in management’s structure, resource allocation and performance assessment in making decisions regarding our operations. Our financial results for the years ended December 31, 2014 and 2013 have been presented to reflect these changes in operating segments. We analyze the performance of our operating segments based on Project Adjusted EBITDA which is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
fair value. Our equity investments in unconsolidated affiliates are presented on a proportionally consolidated basis in Project Adjusted EBITDA and in the reconciliation of Project Adjusted EBITDA to project income (loss). Wind projects, which are components of the former Wind segment, Greeley and Path 15, which are components of the West U.S. segment, the Florida Projects, which are components of the East U.S. segment, and Rollcast, which is a component of Un-Allocated Corporate, are included in the income (loss) from discontinued operations line item in the table below. We have adjusted prior periods to reflect this reclassification. A reconciliation of Project Adjusted EBITDA to project income (loss) is included in the table below:
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
The table below provides information, by country, about our consolidated operations for each of the years ended December 31, 2015, 2014 and 2013 and Property, Plant & Equipment as of December 31, 2015 and 2014,
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
respectively. Revenue is recorded in the country in which it is earned and assets are recorded in the country in which they are located.
Ontario Electric Financial Corporation (“OEFC”), San Diego Gas & Electric, and BC Hydro provided 29.2%, 11.0%, and 10.0%, respectively, of total consolidated revenues for the year ended December 31, 2015. OEFC, San Diego Gas & Electric, and BC Hydro provided 25.8%, 15.1%, and 9.1%, respectively, of total consolidated revenues for the year ended December 31, 2014. OEFC purchases electricity from the Calstock, Kapuskasing, Nipigon, North Bay and Tunis projects in the East U.S. segment. San Diego Gas & Electric purchases electricity from the Naval Station, Naval Training Center, and North Island projects in the West U.S. segment. BC Hydro purchases electricity from the Mamquam, Moresby Lake, and Williams Lake projects in the West U.S. segment.
23. Commitments and contingencies
Commitments
Operating Lease Commitments
We lease our office properties and equipment under operating leases expiring on various dates through 2021. Certain operating lease agreements over their lease term include provisions for scheduled rent increases. We recognize the effects of these scheduled rent increases on a straight-line basis over the lease term. Lease expense under operating leases was $1.5 million, $1.0 million and $1.0 million for the years ended December 31, 2015, 2014, and 2013, respectively. Future minimum lease commitments under operating leases for the years ending after December 31, 2015, are as follows:
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
Long-Term Service Commitments
Our projects have entered into long-term contractual arrangements to obtain maintenance services for turbine equipment expiring on various dates through 2022. As of December 31, 2015, our commitments under such outstanding agreements are estimated as follows:
Fuel Supply and Transportation Commitments
We have entered into long-term contractual arrangements to procure fuel and transportation services for our projects. As of December 31, 2015, our commitments under such outstanding agreements are estimated as follows:
Contingencies
Shareholder class action lawsuits
Massachusetts District Court Actions
On March 8, 14, 15 and 25, 2013 and April 23, 2013, five purported securities fraud class action complaints were filed by alleged investors in Atlantic Power common shares in the United States District Court for the District of Massachusetts (the “District Court”) against Atlantic Power and Barry E. Welch, our former President and Chief Executive Officer and a former Director of Atlantic Power, in each of the actions, and, in addition to Mr. Welch, some or all of Patrick J. Welch, our former Chief Financial Officer, Lisa Donahue, our former interim Chief Financial Officer, and Terrence Ronan, our current Chief Financial Officer, in certain of the actions (the “Proposed Individual Defendants,” and together with Atlantic Power, the “Proposed Defendants”) (the “U.S. Actions”).
The District Court complaints differed in terms of the identities of the Proposed Individual Defendants they named, as noted above, the named plaintiffs, and the purported class period they alleged (July 23, 2010 to March 4, 2013 in three of the District Court actions and August 8, 2012 to February 28, 2013 in the other two District Court actions), but in general each alleged, among other things, that in Atlantic Power’s press releases, quarterly and year end filings and conference calls with analysts and investors, Atlantic Power and the Proposed Individual Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power’s common share dividend that artificially inflated the price of Atlantic Power’s common shares. The District Court complaints assert
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
claims under Section 10(b) and, against the Proposed Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended.
The parties to each District Court action filed joint motions requesting that the District Court set a schedule in the District Court actions, including: (i) setting a deadline for the lead plaintiff to file a consolidated amended class action complaint (the “Amended Complaint”), after the appointment of lead plaintiff and counsel; (ii) setting a deadline for Proposed Defendants to answer, file a motion to dismiss or otherwise respond to the Amended Complaint (and for subsequent briefing regarding any such motion to dismiss); and (iii) confirming that the Proposed Defendants need not answer, move to dismiss or otherwise respond to any of the five District Court complaints prior to the filing of the Amended Complaint. On May 7, 2013, each of six groups of investors (the “U.S. Lead Plaintiff Applicants”) filed a motion (collectively, the “U.S. Lead Plaintiff Motions”) with the District Court seeking: (i) to consolidate the five U.S. Actions (the “Consolidated U.S. Action”); (ii) to be appointed lead plaintiff in the Consolidated U.S. Action; and (iii) to have its choice of lead counsel confirmed. On May 22, 2013, three of the U.S. Lead Plaintiff Applicants filed oppositions to the other U.S. Lead Plaintiff Motions, and on June 6, 2013, those three Lead Plaintiff Applicants filed replies in support of their respective motions. On August 19, 2013, the District Court held a status conference to address certain issues raised by the U.S. Lead Plaintiff Motions, entered an order consolidating the five U.S. Actions, and directed two of the six U.S. Lead Plaintiff Applicants to file supplemental submissions by September 9, 2013. Both of those U.S. Lead Plaintiff Applicants filed the requested supplemental submissions, and then sought leave to file additional briefing. The Court granted those requests for leave and additional submissions were filed on September 13 and September 18, 2013.
On March 31, 2014, the Court entered an order consolidating the five individual U.S. Actions, appointing the Feldman, Shapero, Carter and Smith investor group (one of the six U.S. Lead Plaintiffs Applicants) as Lead Plaintiff and approving Lead Plaintiff’s selection of counsel. The Court also granted the parties’ joint motion regarding initial case scheduling and directed the parties to resubmit a proposed schedule that contains specific dates. In response to that directive, on April 7, 2014, Lead Plaintiff filed an application and proposed order, which sought an extension of the schedule contained in the joint motion. The application and proposed order requested that: (i) Lead Plaintiff be permitted to file an amended complaint on or before May 30, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or otherwise respond to the amended complaint on or before July 29, 2014, (iii) Lead Plaintiff be permitted to file an opposition, if any, on or before September 24, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead Plaintiff’s opposition on or before November 13, 2014. Proposed Defendants did not object to the schedule proposed by Lead Plaintiff. On May 29, 2014, Lead Plaintiff filed a renewed application and proposed order, which sought another extension of the schedule, and on June 3, 2014, Lead Plaintiff and the Proposed Defendants jointly filed a stipulation and proposed order requesting the following revised schedule: (i) Lead Plaintiff be permitted to file an amended complaint on or before June 6, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or otherwise respond to the amended complaint on or before August 5, 2014, (iii) Lead Plaintiff be permitted to file an opposition, if any, on or before October 6, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead Plaintiff’s opposition on or before November 20, 2014. On June 3, 2014, the Court entered an order setting this requested schedule.
On June 6, 2014, Lead Plaintiff filed the amended complaint (the “Amended Complaint”). The Amended Complaint names as defendants Barry E. Welch and Terrence Ronan (the “Individual Defendants”) and Atlantic Power (together with the Individual Defendants, the “Defendants”) and alleges a class period of June 20, 2011 to March 4, 2013 (the “Class Period”). The Amended Complaint makes allegations that are substantially similar to those asserted in the five initial complaints. Specifically, the Amended Complaint alleges, among other things, that in Atlantic Power’s press releases, quarterly and year end filings and conference calls with analysts and investors, Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power’s common share dividend, which artificially inflated the price of Atlantic Power’s common shares during the class period. The Amended Complaint continues to assert claims under Section 10(b) and, against the Individual Defendants, under Section 20(a) of the
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
Securities Exchange Act of 1934, as amended. It also asserts a claim for unjust enrichment against the Individual Defendants. In accordance with the schedule referenced above, Defendants filed their motion to dismiss the consolidated (the “Motion to Dismiss”) U.S. Action on August 5, 2014.
On September 30, 2014, citing Atlantic Power’s September 16, 2014 announcement of changes to its dividend and its President and CEO transition, Lead Plaintiff filed a motion (the “Extension Motion”) requesting a thirty day extension of its October 6, 2014 deadline for filing its brief in opposition to the Motion to Dismiss, in which to determine whether to file a second amended complaint. On October 2, 2014, the Court entered an order (i) extending Lead Plaintiff’s deadline to file its opposition to the Motion to Dismiss to October 10, 2014 and (ii) requiring Defendants to file their opposition to the Extension Motion by October 2, 2014. In accordance with this order, on October 2, 2014, Defendants filed their opposition to the Extension Motion. On October 10, 2014, Lead Plaintiff filed its opposition to the Motion to Dismiss (the “Opposition”) and also filed a motion for leave to amend the Amended Complaint, attaching a proposed second amended complaint. On October 21, 2014, Lead Plaintiff and Defendants filed a joint scheduling motion requesting (i) November 7, 2014 as the deadline for Defendants to file their opposition to Lead Plaintiff’s motion for leave to amend the Amended Complaint; (ii) November 24, 2014 as the deadline for Defendants to file their reply in further support of the Motion to Dismiss; and (iii) November 24, 2014 as the deadline for Lead Plaintiff to file its reply in further support of its motion for leave to amend the Amended Complaint. On October 22, 2014, the Court entered an order setting this requested schedule. Pursuant to that order, the Motion to Dismiss and Extension Motion were fully briefed on November 24, 2014. On January 22, 2015, the Court held oral argument on the Motion to Dismiss and Extension Motion.
On January 30, 2015, Lead Plaintiff filed a motion for leave to file a supplemental submission in opposition to Defendants’ motion to dismiss (the “Motion for Leave”). The Court denied the Motion for Leave in an order entered on February 5, 2015, but permitted Lead Plaintiff to submit a brief letter identifying supplemental authorities. Lead Plaintiff filed that letter on February 9, 2015, and Defendants filed a response on February 10, 2015.
On March 13, 2015, the District Court entered an order granting Defendants’ motion to dismiss and denying Lead Plaintiff’s motion to amend the Amended Complaint, and on March 18, 2015, the District Court entered an order dismissing the Amended Complaint with prejudice.
On April 16, 2015, Lead Plaintiff filed a notice of appeal to the United States Court of Appeals for the First Circuit (the “First Circuit”). On August 19, 2015, Lead Plaintiff filed with the First Circuit its brief appealing the dismissal of its securities fraud claims.
On September 4, 2015, while appellate proceedings were still on-going, Lead Plaintiff filed with the District Court a Rule 60(b)(2) motion to vacate the judgment based on evidence cited in the Ontario Superior Court’s decision dismissing the Canadian action (for more information on that litigation, see below under “Canadian Actions”). On September 17, 2015, Atlantic Power opposed Lead Plaintiff’s motion.
On September 18, 2015, Lead Plaintiff requested a stay of the appellate proceedings in the First Circuit pending resolution of the District Court’s decision on its Rule 60(b)(2) motion. On September 21, 2015, Atlantic Power opposed Lead Plaintiff’s request for a stay and tendered to the First Circuit its opposition brief to Lead Plaintiff’s appeal. On October 5, 2015, the First Circuit granted Lead Plaintiff’s request for a stay in the appellate proceeding pending the District Court’s decision on the Rule 60(b)(2) motion.
On October 21, 2015, the District Court entered an order denying Lead Plaintiff’s Rule 60(b)(2) motion to vacate the judgment.
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
On October 29, 2015, pursuant to Federal Rule of Appellate Procedure 42(b), the parties jointly stipulated to the voluntary dismissal of the appeal before the First Circuit with prejudice. On November 30, 2015, the First Circuit ordered that the case be voluntarily dismissed.
Canadian Actions
On March 19, 2013, April 2, 2013 and May 10, 2013, three notices of action relating to Canadian securities class action claims against the Proposed Defendants were also issued by alleged investors in Atlantic Power common shares, and in one of the actions, holders of Atlantic Power convertible debentures, with the Ontario Superior Court of Justice in the Province of Ontario. On April 8, 2013, a similar claim issued by alleged investors in Atlantic Power common shares seeking to initiate a class action against the Proposed Defendants was filed with the Superior Court of Quebec in the Province of Quebec (the “Canadian Actions”).
On April 17, May 22, and June 7, 2013 statements of claim relating to the notices of action were filed with the Ontario Superior Court of Justice in the Province of Ontario.
On August 30, 2013, the three Ontario actions were succeeded by one action with an amended claim being issued on behalf of Jacqeline Coffin and Sandra Lowry. As in the U.S. Action, this claim named the Company, Barry E. Welch and Terrence Ronan as Defendants. The Plaintiffs sought leave to commence an action for statutory misrepresentation under the Ontario Securities Act and asserted common law claims for misrepresentation.
The Plaintiffs’ motions for leave and certification were heard on May 20-21, 2015.
On July 24, 2015, the Ontario Superior Court of Justice issued a decision denying the Plaintiffs’ motion for leave and certification. The Superior Court granted leave to reconstitute a claim for debenture holders but required that there be a debenture holder as plaintiff, that the claim be amended and that the Plaintiffs pay the Defendants partial indemnity costs of responding to the Plaintiffs’ motion.
The Plaintiffs appealed the July 24 decision on leave and certification to the Ontario Court of Appeal.
The appeal was subsequently abandoned by the Plaintiffs, and the Ontario action was dismissed by Order dated December 2, 2015, the Defendants agreeing not to claim costs from the Plaintiffs.
The proposed Quebec class action was suspended by the Superior Court of Quebec pending the outcome of the motions for leave and certification of the Ontario action as a class proceeding. Following the result in Ontario, the petitioner in the Quebec proceedings has agreed in principle with the Defendants to discontinue the Quebec proceedings without costs. The discontinuance will require the authorization of the Superior Court of Quebec. The parties are preparing materials to obtain this authorization.
The petitioner in the Quebec proceedings did not estimate the alleged damages of the proposed class. Because the Quebec proceedings were suspended and then an agreement to discontinue was made in its early stages, Atlantic Power is unable to reasonably estimate the possible loss or range of losses, if any, arising from this litigation, if it were to continue. If the action were to continue, Atlantic Power intends to defend against it vigorously.
Other
In addition to the other matters listed, from time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
which are expected to have a material adverse impact on our financial position or results of operations or have been reserved for as of December 31, 2015.
24. Unaudited selected quarterly financial data
Unaudited selected quarterly financial data are as follows:
ATLANTIC POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(in millions of U.S. dollars, except per-share amounts)
			
		
25. Guarantees
We and our subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of our business activities. Examples of these contracts include asset purchases and sale agreements, joint venture agreements, operation and maintenance agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements.
In connection with the Purchase Agreement for the sale of the Wind Projects, on March 31, 2015, we entered into the Guaranty Agreement, under which we agreed to guarantee the full and prompt payment of all payment obligations of APT under the Purchase Agreement as and when they shall become due. APT and TerraForm have agreed to utilize the representation and warranty insurance for coverage of certain indemnification obligations, subject to a cap and certain exclusions.
			 		
			
		
ATLANTIC POWER CORPORATION
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013
(in millions of U.S. dollars)