Exhibit 99.1

Report to Shareholders

Dear Shareholder,

This year’s letter is divided into three sections: first, a review of the progress we have made in restructuring and turning around the business over the past three years; second, a summary of our 2017 results and the outlook for 2018; and third, a discussion of trends affecting the power markets, how Atlantic Power Corporation (the “Company”) is positioned in the current environment, and our views on growth and capital allocation.

2015 — 2017 RESTRUCTURING RESULTS

2017 represented the third year of our restructuring efforts. Our focus during this period has been on reducing debt and interest costs by reshaping our balance sheet, reducing corporate overheads, and rolling out a program to reduce operating costs. Our goal is to position the Company for the long haul, in a challenging commodity price environment when several of our above-market Power Purchase Agreements (PPAs) have expired or will expire in the next several years. As a result of these steps, summarized below, we now have an improved credit profile and liquidity of approximately $205 million.

Debt.  We reduced consolidated debt by $909 million, from $1,755 million at year-end 2014 to $846 million at year-end 2017. We accomplished this by debt amortization, discretionary debt repurchases, and asset sales. During this period our leverage ratio(1) declined from 6.9 times to 3.3 times. We plan to repay another $100 million of debt in 2018, although we expect our leverage ratio will increase to the high 4 times range because of lower Project Adjusted EBITDA,(2) before beginning to decline again in 2019 and beyond. We also significantly improved our debt maturity profile during this period as a result of debt repayment and refinancing activity. At year-end 2014, we had $671 million of bullet maturities in the following five years, but by March 2018, we had reduced the five-year total to approximately $20 million (all in 2019). We expect to amortize approximately $470 million of term loan and project debt from 2018 through 2022.

Interest payments.  The significant reduction in our debt during this period reduced our cash interest payments from $127 million in 2014 (not including $42 million of non-recurring cash costs associated with redemptions and refinancing transactions) to $72 million in 2017. We expect a further reduction in 2018, to an estimated $45 million. In addition to the reduction in our debt, the three re-pricings of our senior secured term loan and revolver since April 2017 have reduced the cost of those facilities to us and contributed to the reduction in cash interest payments in 2017 and beyond.

Corporate overheads.  We reduced corporate general and administrative (G&A) expense by slightly more than half, from $45 million in 2014 to $22 million in 2017. To accomplish this, we reduced our corporate staff from 66 at the end of 2014 to 44 currently (at the beginning of 2013, prior to my tenure as CEO, the number of corporate employees peaked at 110). We also moved the corporate headquarters from Boston to Dedham, Massachusetts, in 2015, which reduced our annual rent from approximately $1.2 million to $500,000. Later this year we will be relocating to a smaller space within our current building. As a result, we will further reduce the rent for our headquarters to $285,000 annually.

The combination of lower corporate overheads and lower cash interest payments resulted in $78 million of recurring cash savings to the Company in 2017 relative to 2014, and we expect approximately $27 million of additional interest cost savings in 2018.

Assets divested or mothballed.  In 2015, we sold all five of our wind plants (with a combined capacity of 521 megawatts) for $350 million of net proceeds, or approximately 13.5 times estimated cash distributions, and used the proceeds to redeem our remaining $311 million of 9% senior unsecured notes. The transaction was $2 million accretive to our cash flow, and we improved our leverage ratio and debt maturity profile. Separately, in early 2017, we mothballed (took out of operation for an extended period) three plants in Ontario totaling 120 megawatts of generating capacity. This was the result of a revised contractual arrangement with the plants’ customer, which produced benefits for us and for ratepayers. We will return the Nipigon plant to service in November of this year, while the Kapuskasing and North Bay plants have option value should the supply and demand balance in Ontario improve at some point, or if we are successful in repurposing the sites.

Investment in our plants.  In 2013 through 2016, we made $25 million of optimization investments in our existing plants, to improve efficiency, increase capacity, and reduce operating costs. In 2013 through 2017, we realized a cumulative cash return of approximately $32 million on these investments, and we expect a recurring cash flow contribution of $11 million to $12 million annually in 2018 and beyond. The returns on these investments were higher than what we could have achieved externally and carried lower risk, because we know these assets well.

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Culture.  Atlantic Power is a “servant leadership company,” meaning we believe leadership is a skill that can be developed. Servant leaders seek to build authority through their actions and strive to act with respect, integrity, and honesty. Servant leaders seek to be good listeners, to be humble, and to lead by example. We seek to build a safe environment for dissent, where bad news is communicated in nanoseconds and we stay well away from legal and ethical boundaries. This allows us to get problems on the table quickly and honestly so they can be dealt with by the team. This also allows us to face reality, which is necessary for good execution in our business. The best exposition of servant leadership principles we have found is in the books of James C. Hunter (The Servant: A Simple Story About the True Essence of Leadership; The World’s Most Powerful Leadership Principle: How to Become a Servant Leader, and The Culture: Creating Excellence with Those You Lead).

REVIEW OF 2017 FINANCIAL RESULTS

We posted strong financial results in 2017 as measured by Project Adjusted EBITDA and operating cash flow. Both metrics met or exceeded our estimates, which were revised upward twice in 2017.

Project Adjusted EBITDA of $289 million was $87 million higher than the 2016 level of $202 million. This significant increase was driven primarily by the favorable impact of the revised contractual and operational arrangements for three of our Ontario plants (Kapuskasing, North Bay, and Nipigon) and the expiration of an above-market gas contract in Ontario (together totaling $42 million), the settlement of the Global Adjustment litigation in Ontario (the OEFC Settlement; $29 million), increased water flows at Curtis Palmer ($13 million), more modest increases at several other plants, including Orlando and Morris, and a $3 million non-cash translation benefit to EBITDA from the appreciation of the Canadian dollar. Partially offsetting these positive factors, we had modest decreases at our Mamquam, Frederickson and Calstock plants.

Cash provided by operating activities of $169 million increased by $57 million from the 2016 level of $112 million. In 2017, we collected approximately $27 million of cash under the OEFC Settlement. Other factors that helped cash flow included the higher EBITDA at our Kapuskasing, North Bay, and Nipigon plants and the benefit to EBITDA from higher water flows at Curtis Palmer. These positive factors were partially offset by modest decreases at our Mamquam, Frederickson, and Kenilworth plants. In addition, cash provided by operating activities was reduced $24 million from 2016 due to changes in working capital.

A review of our business and financial results for 2017 immediately follows this letter.

2018 OUTLOOK

On our year-end 2017 conference call last month, we again indicated that we expect a significant decline in Project Adjusted EBITDA and operating cash flow in 2018. This is the result of several factors. In December 2017, as expected, the contracts for our Kapuskasing and North Bay plants expired and were not renewed. Also in December 2017, we executed a short-term extension of the contract for our Williams Lake plant. The EBITDA contribution under the amended contract is expected to be de minimis. In early February 2018, we shut down operations of our three plants in San Diego because we have not been successful in obtaining permission from the U.S. Navy to remain on site. We expect these developments, together with the non-recurrence of the OEFC Settlement revenues recorded in 2017, to reduce our Project Adjusted EBITDA by approximately $105 million in 2018 compared to 2017. In addition, there are other factors, both positive and negative, that will affect the level of EBITDA, but these are considerably more modest in terms of potential impact. The reduction in our operating cash flow should be less because we expect our cash interest payments to be approximately $27 million lower in 2018 than they were in 2017.

POWER MARKETS OVERVIEW

The most significant change in energy markets in recent years has been the combination of fracking, horizontal drilling and 3-D seismic, which has revolutionized oil and gas production in the United States. The impact on production levels and costs has fundamentally shifted the supply and price environment of oil and gas in the United States and globally. Not that long ago, I handed out copies of a book on peak oil to the board of a wind energy company and we thought that LNG terminals were needed for imports. Since then, the world has been turned upside down.

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The results of this technological revolution have changed the supply picture for fossil fuels in the United States for the foreseeable future. Low natural gas prices in turn have hurt the economics of coal and nuclear power plants in the United States, while the economics of gas plants have been adversely affected by capacity additions that exceed the rate of demand growth. The combination of low gas prices and oversupplied power markets has resulted in declining wholesale power prices in the United States; however, retail and industrial power prices have not fallen. The costs of integrating wind and solar into the grid as well as other factors generally have offset the benefit of lower wholesale prices.

Wind and solar projects have been receiving federal tax subsidies, which are being phased out. Both continue to benefit from Renewable Portfolio Standards (RPS) in many states, which require that a certain percentage of a utility’s generation mix be sourced from wind, solar, and other renewable technologies. The economics of wind and solar power are location-specific. A windy site far from a population center may require the building of transmission lines to the load center. Permitting construction of these lines, or windy sites near population centers, is often slow and unpopular with affected communities. Not as well understood is that wind and solar plants require lots of resources to manufacture and build per unit of capacity. Material usage is high because these are not dense sources of energy.

In addition, since wind and solar are intermittent sources of energy, the grid requires more dependable (non-intermittent) sources of power such as coal, nuclear, and natural gas plants that can provide back-up when the wind doesn’t blow or the sun doesn’t shine. Energy storage is being promoted in some states as a potential solution to the problem of intermittency, and utilities have committed to several significant projects. The cost of batteries has fallen, although they are still expensive and the costs rise the longer you need the battery to be available. Prices of wind turbines and solar panels also have fallen. The phase-out of tax subsidies is putting downward pressure on wind turbine prices. Excess capacity for solar panels manufactured in places like China has driven down costs. At the same time, the costs of natural gas plants and fossil fuels have continued to fall dramatically.

In analyzing the cost of integrating wind and solar power on a grid, you need to include the costs of intermittency. Adding intermittent resources to a grid increases the costs incurred by the grid to support the intermittent power. For example, combined-cycle gas turbine (CCGT) plants may have to cycle more frequently than they are designed to, incurring additional maintenance expense and operating less efficiently in terms of heat rate. You also have to look at the marginal economic value of intermittent resources as well as their costs. As you increase the percentage of resources that are intermittent, you not only increase costs to the grid but you also decrease the value of the incremental power produced. In Texas, for example, on a windy day you might have 50% of the power on the grid coming from wind plants. On a hot day in August with little wind, you might have very little power generated by non-coastal wind. The first, say, 10% of the generation coming on and off at roughly the same time has one value, but if you generate three or four times that amount in the same number of hours, the power you are generating has less value. You are adding supply in the same hours rather than as needed, when needed, and where needed. (For an analysis of this topic, you can read Lion Hirth’s paper: “The Economics of Wind and Solar Variability: How the Variability of Wind and Solar Power Affects their Marginal Value, Optimal Deployment, and Integration Costs,” November 2014.)

As the United States has added wind and solar to the power grids, and as utilities have made additional investments in transmission and distribution to support these resources, the gap between declining wholesale power and gas prices and the prices charged to retail and industrial customers has grown. We think this presents an opportunity to work with industrial customers at our existing plants and potentially with new customers to lower power costs for them through “inside the fence” projects such as combined heat and power (CHP) facilities.

Today, the amount of capacity being added to the grid exceeds the low growth in demand. These capacity additions to an already oversupplied market are occurring despite low power prices. About half of these additions are wind and solar, driven by state RPS and tax benefits. Low interest rates, lots of available capital, and low heat rates for new gas turbines (the lower the heat rate, the less natural gas needed to generate the same amount of electricity) have been significant factors driving gas plant additions. One analysis forecasts that 42,499 MW will be added to the U.S. electric grid in 2018, which is net of 11,573 MW scheduled to retire this year.(3) That represents an approximate 4% net increase in capacity, when demand growth is low to nil.

We can’t predict how all this will turn out. The non-utility power generation market is capital-intensive, commodity-priced, and cyclical. The old saying is “The cure for low commodity prices is low commodity prices,” as the price signals affect supply and demand. Power generation is an area heavily affected by government regulation and intervention on the one hand, but can be an easy place to deploy large pools of capital on the other hand, so the need for disciplined capital allocation is great.

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ATLANTIC POWER’S POSITION

Fuel and Market Diversity

We have a diversified fleet of plants: gas, hydro, biomass, and coal. We think that this technological diversity positions us well under various potential scenarios.

Currently, the market appears to be valuing our gas plants for the remaining cash flows under their PPAs, assuming little or no recontracting occurs when the PPAs expire. However, under a scenario in which integration of wind and solar on the grid continues at a high level and the projected economics of batteries prove optimistic, natural gas plants could benefit because they will be required to serve as back-up for intermittent resources. There might even be some pressure to provide capacity payments for non-intermittent sources of power. Our gas plants are likely beneficiaries in such a scenario.

Our management team has experience with energy storage, and we are exploring potential opportunities around our existing plants, but the economics of batteries are not currently compelling for wholesale applications for extended periods.

Alternatively, we might see the increase in wind and solar power muted by increasing NIMBY (not in my backyard) concerns in communities targeted for development. Having tried to permit two wind projects in the Green Mountain state earlier in our careers, we are more skeptical than most about the ability to achieve very high levels of wind and solar capacity given the land use and permitting issues. Under a scenario where growth in renewables slows, natural gas plants should benefit.

Several of our gas and hydro plants are in locations where it is challenging to site and build new capacity because of NIMBY opposition. That improves the prospects for these plants, where we are in a position to retain control of the site. In areas where the supply and demand outlook is currently unfavorable, such as Ontario, we have preserved our options by mothballing plants rather than dismantling them, in order to have the ability to restart them in a few years should market conditions improve.

Any scenario that results in an increase in electric demand, such as a move to electric vehicles, should be positive, including for conventional power producers.

PPAs, Cash Flow and Delevering

Our PPAs have an average remaining term of slightly less than seven years. If power prices remain low or decline further, then as our PPAs roll off, the price we receive for the power should be materially below current contract levels. In developing our estimates of intrinsic value, we assume that market prices will remain in the range of the levels of the past three years, so we expect lower EBITDA from these projects post-PPA. The market views the declining EBITDA as a negative. So do we, but the above-market revenues currently accruing under the PPAs are an asset, resulting in cash flows that are being used to pay down debt significantly, among other uses. As we have indicated on our quarterly conference calls, if we allocate the vast majority of our operating cash flow to debt repayment, by about 2025 we can be approximately net debt-free. In an environment such as we have described, EBITDA could decline from current levels by maybe $100 million during this period, but we’d have a residual business that, while smaller, still generates significant cash flow and carries little or no net debt.

An outcome of “zero” net debt is not our base case, but instead reflects a scenario where power prices stay low for many years and we do not grow. But on a base of no net debt, we’d still own hydro plants with significant long-term value, PPAs at some of our plants running as far out as 2037, and possible option value at some of the other plants for which the PPAs had already expired. We believe the equity value of the Company under that scenario is higher than what the market is currently ascribing.

More likely, though, we will have opportunities prior to 2025 that could be preferable to continued delevering. Seven years is a long time in markets that historically have been volatile. We would attempt to use any intervening price volatility to hedge our assets, to extend PPAs or to bring plants back on line to firm up or grow the back-end EBITDA. We might look to sell assets in that environment. Conversely, if markets become distressed, we might redirect discretionary cash flow into asset purchases. If things are pretty flat, then we might look to add a reasonable amount of debt, rather than getting to a zero net debt level, and use the proceeds to repurchase shares via a tender offer. When we look at the business, then, we think we can extract enough cash flow in a low power price environment to further strengthen our balance sheet, and the progress we have made to date positions us to take advantage of any compelling opportunities the market may present as either a buyer or a seller.

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GROWTH

We don’t see compelling investment opportunities in the power sector today. The psychological bias in favor of growth is strong, so we need to be disciplined. We are value investors. Bruce Greenwald once told me: When there is nothing to do, you have to be willing to do nothing. Internally, I talk about the willingness of Warren Buffett and Charlie Munger to stop underwriting insurance when returns are too low and to move with speed and scale when opportunities emerge. We want to follow that model.

Looking at the investing landscape broadly, we see high valuations implying muted returns in the future. If interest rates returned to the levels of pre-2008, that would create major downward pressure on asset values. Several years ago, James Montier of GMO wrote a paper on financial repression and the implications for value investing.(4) His analysis showed that periods of financial repression can last decades. If we have a reversion to the mean (materially higher interest rates) soon, then the best asset class today is cash. If it takes a decade or two for rates to revert to the mean, then fixed income is probably better than cash, and U.S. equities are probably better than fixed income.

Meanwhile, equity investments in power projects are the rough equivalent of high-yield bonds. Typically a non-utility generation investment is based on an Internal Rate of Return (IRR) calculation derived from a 20- to 30-year pro forma financial model. In the past, the typical structure was to sell the power output to a utility or industrial customer under a PPA, which usually had limited upside if power prices increased, thereby making the investment bond-like in my estimation. If costs increased, there was risk to the downside. Over the last 20 years or so, we have had opportunities to invest in power projects with equity returns in the mid-teens, which seems reasonable. That represented roughly a 5% spread versus a utility’s allowed equity rate of return. A utility investment goes into rate base. If the project experiences cost overruns, demand shortfalls or unforeseen issues, the utility owner can seek rate relief. There is no such recourse for non-regulated generation investments.

More recently the YieldCo model was popular on Wall Street. In 2015, I read one YieldCo investor presentation in which they estimated their weighted average cost of capital at 7%, they estimated returns from their investments at 9% and they projected a 15% annual growth rate. I was asked: “Why don’t we become a YieldCo?” My answer was that I didn’t believe the 7%, the 9% or the 15%. Instead, we sold our wind plants for $350 million (plus project debt, assumed by the buyer) and used the proceeds to pay off $311 million of our remaining 9% senior unsecured notes that we had issued previously to fund growth and which were costing us $28 million annually in interest payments. The moral of the story is that when the markets are doing things that don’t make sense to you, sometimes it is better to sell rather than following the crowd.

We don’t like the supply and demand fundamentals in this market. Given this view, M&A markets seem high-priced. Power projects are capital-intensive investments that require an adequate margin of safety. When the market starts to accept low returns, the end results are usually poor.

Wind and solar projects are being done at returns that are estimated to be in the single digits. I think power project investments are too risky to accept single-digit returns. We have no more wind or solar plants to sell, or we would be an aggressive seller of those assets today as well. Until the recent tax legislation, about two-thirds of the economics of those projects were derived from tax benefits. We have about $583 million of net operating losses, so we have little appetite for projects driven primarily by tax benefits. Looking back over the past 17 years in wind investing, it seems to me that the tax equity investors as a group have done well but the cash investors as a group have not done well, absent flipping assets. Buy-and-hold cash investors have suffered the consequences of lower-than-expected wind production versus forecasts, something that tax equity investors were structurally well protected from. As a Company, we have invested in wind in the past, and management has invested in both wind and solar at other companies. At the right return levels we are enthusiastic buyers of or investors in wind and solar projects. Not today. For institutions with tax appetites, the picture is different.

We continue to look broadly for external growth opportunities, particularly those that may arise from special situations, such as turning around a challenged asset. We look at biomass projects where we think our operations team can increase the plant’s cash flows. We look at contracted coal plants. We look at opportunities to build new projects for industrial customers (CHP projects, generally). We have reviewed the retail electric sector, as have other IPPs. We are generally not willing to invest in merchant plants (plants with no long-term contracts for the output), because that would require us to bet on higher power prices in the future.

This is an opportunistic search process. There are times when we see a multi-year prospect for investing in one asset class, such as we did in wind in 2001 — 2008 when returns were much higher than those available today. Then there are times when the obvious thing to do at the market clearing price is to sell, as we did with our wind portfolio in 2015.

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Our experience has been that market sentiment in power can shift dramatically and rapidly, so having dry powder is a good thing. We have approximately $205 million in liquidity, including $122 million of unused revolver capacity and $83 million of unrestricted cash. We can use the revolver to make investments or acquisitions but not to repurchase common or preferred shares. Approximately $32 million of the cash is at the parent and available for discretionary purposes.

Given the external investment environment that I have just described, we have focused instead on internal investments. Over a four-year period, we made $25 million of discretionary optimization investments in our own fleet, which we estimated to have cash returns of 20% and higher, although at this point these investment opportunities are effectively exhausted.

In addition, we continue to see compelling returns from repurchasing our equity securities. Since December 2015, we have purchased $27 million of our common shares and $7 million (U.S. dollar equivalent) of our preferred shares. We bought the preferred shares at a considerable discount to par, and our cash returns from the avoided dividends and related taxes were approximately 10% — 11%. The return on buying back common shares is tougher to analyze. It is more like an IRR analysis for a power plant project than straightforward cash return analysis for discretionary investments in our plants or repurchases of preferred shares. Given the discount of the common share price to our estimates of intrinsic value, we have bought much more common equity than preferred.

Power prices will have a major impact on the long-term value of our business. They will drive asset values. We are fairly agnostic on strategic outcomes in the industry. We are happy to invest in wind, solar, gas, biomass, coal, or storage if the economics are compelling. At present, we don’t see good opportunities to deploy our cash externally but that is likely to change over time. In the meantime, we are seeing good returns on our internal uses of capital.

CAPITAL ALLOCATION

Given the current power market landscape, you can see why over the past three years we have:

·                  Reduced debt by more than $900 million;

·                  Reduced our leverage ratio to 3.3 times from 6.9 times;

·                  Reduced corporate overheads by slightly more than half; and

·                  Allocated capital to purchasing $27 million of common shares and $7 million (U.S. dollar equivalent) of preferred shares at what we estimate to be double-digit returns.

We often hear the saying “You can’t shrink to greatness,” but when our estimate of intrinsic value per share exceeds the share price by a significant amount, we are willing to buy shares. At a stock price higher than our intrinsic value estimate, we would not buy shares. If we can earn better returns investing externally, then we will do that. We are not primarily motivated by growth in the absolute size of the business. We will try to maximize the discounted cash flows of our business on a per-share basis in a declining power price environment by focusing on costs, reducing debt, and buying shares if that is the best use of cash for our shareholders.

In the past, members of the management team have been involved in making billions of dollars of investments in the power sector. We love doing deals, but we insist on having an adequate margin of safety and an expected return better than we can exact out of our own business. Our sole focus is to be as rational as possible in allocating capital for ourselves and our fellow owners of the business. We want to maximize the benefit to the shareholders of a declining business and redirect our capital only when the benefits of external growth are obvious.

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QUESTIONS

Let me conclude this letter by addressing a few questions that we are frequently asked by shareholders:

Why not pay a cash dividend?

Given the business and industry profile laid out above, we don’t think dividends make sense. A cash dividend paid out quarterly implies a fair level of confidence in maintaining that dividend. In a volatile, capital-intensive, cyclical business prone to presenting market opportunities to be a buyer or a seller, we think we ought to focus on intrinsic value per share rather than quarterly dividend payments. Investors looking for steady income have better opportunities elsewhere. Also, our shares are well below our estimate of intrinsic value per share, and they have been for the last several years. Buying them in ought to accrete value to remaining shareholders if our estimates are roughly correct. We have no expectation of reinstating a cash dividend anytime in the foreseeable future.

What can you do about the share price?

Our approach is to focus on protecting and, if possible, growing the intrinsic value per share of the business. We try not to promote the shares. We view the market quotation as an invitation to buy (as we have been doing, with $31 million of Company and insider purchases) or to sell shares. We try to provide investors as much information as we can, but to make an estimate of value you must have a view of what power prices will be in five, seven, or ten years.

We have made enormous improvements in the business. The share price has not reflected those improvements. Although we are not focused on moving the share price over short time periods, we believe it would be better if our shares traded closer to intrinsic value.

Things that might narrow the valuation gap over time include higher power prices, growth, or significant share repurchases. Higher power prices would drive better post-PPA outcomes for us. Such an environment might rerate the sector, including our shares.

Growth, organic or external, is highly unlikely to totally offset the expected decline in EBITDA from current levels to post-PPA pricing as the decline is too large. As noted earlier, our debt should decline faster than EBITDA if we continue aggressive debt repayment, resulting in declining leverage ratios in 2019 and beyond. At that point the lower leverage may rerate the shares.

In either case (higher power prices or growth), if we continue to shrink the number of shares outstanding, the value of the Company on a per-share basis should grow. We will remain focused on improving the value of the business and we believe that at some point the public market will reflect that value, or a buyer will emerge for the Company.

Is Atlantic Power too small?

We don’t think so. Our enterprise value is approximately $1.2 billion. The market value of the common equity is approximately $245 million at recent prices. We have $205 million of liquidity. We think of ourselves as akin to a deep value small cap equity investor. Today, there is nothing to get excited about, but at our size investments that are too small for others can move the needle for us. If we had a few billion dollars to invest, there isn’t anything we’d want to do with it in the power sector today anyhow.

We look forward to meeting those shareholders who can attend our Annual General Meeting this year, which will be held at the King Edward Hotel in Toronto on June 19, beginning at 10:00 a.m.

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2017 Business and Financial Highlights

Cultural

·                 Environmental, health and safety performance.  We had one lost-time incident in 2017 as compared to two in 2016. Our lost-time incident rate improved to 0.38 from 0.69. Although we had three recordable injuries in 2017 (all relatively minor) as compared to two in 2016, our total recordable injury rate of 1.16 was better than our performance in 2014 and 2015. Three of our plants—Kenilworth, Manchief and Piedmont—completed five years of operation without a lost-time incident. We had no notices of violation in 2017 from either the Federal Energy Regulatory Commission or the North American Electric Reliability Council. Our Kenilworth plant received an Environmental Stewardship Certificate from the New Jersey Department of Environmental Protection for its voluntary and proactive measures to improve the environment and ensure a sustainable future.

·                  Servant leadership.  We continued to focus on promoting a culture of servant leadership throughout the Company. In 2017, we continued to roll out training throughout the organization. All members of senior management and all plant managers have now participated in the training.

Operational

·                 Availability.  Our plants had an availability factor of 90.3%, which was a strong performance although modestly lower than the 93.3% availability recorded in 2016, due to planned outages in 2017 at our Frederickson and Kenilworth plants and forced outages at our Mamquam and Williams Lake plants.

·                  Maintenance and optimization initiatives.  We upgraded the third of the three gas turbines at our Morris plant. This completed a major undertaking at the Morris plant begun in 2016 to increase output and improve efficiency of the gas turbines and add fast-start capability to the second of two auxiliary boilers. We also replaced the control system at our Cadillac plant and upgraded the gas turbine at our equity-owned Frederickson plant.

·                  Launched plant cost savings initiative.  In late 2016, we began a program to analyze and benchmark our plant operating costs with a goal of achieving cost savings. In 2017, we completed the internal benchmarking effort and held both operations and maintenance summits for our plant employees to identify and implement best practices, with a focus on outage frequency and maintenance intervals. We have implemented $2 million of non-fuel permanent cost reductions for 2018 and eliminated $2 million of planned maintenance spending from future years. We also reduced our overall fleet fuel usage (on a load-adjusted basis) by approximately 3% in 2017, resulting in fuel cost savings of approximately $3 million. In addition, we deployed Predictive Analytic maintenance software (PRISM) at three plants and expect to deploy it at another three sites this year. This software should improve reliability and operational performance.

Commercial

·                 Revised contract for Nipigon.  We negotiated a new long-term enhanced dispatch contract for our Nipigon plant for the period November 2018 through December 2022. Under the revised contract, the Nipigon plant will return to service in November 2018 as a simple-cycle plant and will operate on a flexible basis. The new contract reduces the operating risk of the plant and results in improved economic outcomes for the plant as well as Ontario ratepayers as compared to the original PPA.

·                  Amended PPA for our Tunis plant.  We reached agreement with the customer on amendments to the Tunis PPA that provide for the plant to operate in simple-cycle mode, which we expect will result in a lower risk profile. We also were successful in obtaining an amended permit for the plant. We commenced work on returning the plant to service in late 2017 and expect it to return to operation under the 15-year PPA in the third quarter of 2018.

·                  Short-term contract extension for our Williams Lake plant.  We amended and extended our existing contract with BC Hydro for our Williams Lake plant by approximately 15 months, or 18 months at the option of BC Hydro. Although the economic contribution during the extension is expected to be de minimis, the purpose of the extension is to bridge operations of the plant to a possible longer-term extension of the contract, depending on the outcome of BC Hydro’s Integrated Resource Plan in the second or third quarter of 2019.

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·                  Executed new contracts for the three San Diego plants, although have not achieved site control.  We signed new seven-year contracts for our Naval Station and North Island plants with San Diego Gas & Electric and for our Naval Training Center plant with Southern California Edison, but have not succeeded in obtaining site control with the U.S. Navy, which is required for us to restart operations at the plants.

·                  Amended existing PPAs for the three San Diego plants.  The amendment provides for early termination of the PPAs without any potential liabilities to the customer. The amendments were approved by the California Public Utilities Commission in March 2018.

·                  Negotiated final adjustments to OEFC Settlement.  These efforts resulted in an additional Cdn$1.7 million of revenue received under the Global Adjustment settlement with the Ontario Electricity Financial Corporation, bringing the total to Cdn$37.8 million.

Financial

·                 Strong financial results.  For 2017, Cash provided by operating activities (a GAAP measure) was $169 million, which was in the upper half of our estimated range of $160 million to $175 million. Project Adjusted EBITDA was $289 million, which exceeded our guidance range of $260 million to $275 million. Both guidance ranges were revised upward twice during 2017.

·                  Debt reduction.  We repaid $166 million of debt in 2017, reducing our leverage ratio at year-end to 3.3 times.

·                  Two successful re-pricings of our term loan.  In April 2017 and again in October 2017, we successfully re-priced the spread on our term loan and revolver by a total of 150 basis points, to LIBOR plus 350 basis points. The combined savings of both re-pricing transactions is estimated to be approximately $33 million over the remaining terms of the facilities.

·                  Improved debt maturity profile.  By repaying the Piedmont project debt in full, we eliminated our only 2018 bullet maturity. In October 2017, we extended the maturity date of our $200 million corporate revolver by one year, to April 2022, which ensures a stable liquidity profile during this period.

·                  Strong liquidity.  Our liquidity at year-end 2017 was $198 million, including approximately $40 million of discretionary cash, after allocating approximately $71 million of liquidity to the Piedmont debt repayment in October 2017.

·                  Improved credit profile.  In October 2017, Moody’s upgraded our corporate family credit rating to Ba3 from B1, representing the second upgrade from Moody’s in a two-year period.

·                  Stable overhead costs.  Corporate general and administrative (G&A) costs for 2017 of $22 million were approximately $0.6 million lower than in 2016. Although the most significant cost reductions are behind us, we continue to look for additional cost reduction opportunities. In 2017, we eliminated seven positions for estimated savings of $1.2 million annually and absorbed this work within existing teams. We also further reduced our property and casualty insurance costs modestly.

Capital Allocation

·                 Piedmont debt repayment.  After considering an asset sale and refinancing options for the plant’s August 2018 debt maturity, we elected to allocate a portion of our liquidity to repayment of the $54.6 million project debt. This improved our maturity profile by eliminating our only 2018 bullet maturity. It also results in $4.4 million of annual interest cost savings and allowed the project to make cash distributions to the parent for the first time. Piedmont generates Project Adjusted EBITDA of approximately $9 million to $10 million annually and has a PPA with an investment-grade customer that runs through 2032, which will help to support our long-term cash flows. We considered this debt repayment to be an excellent use of our discretionary capital.

·                  Repurchases of preferred and common shares.  During 2017, we repurchased 250,000 preferred shares and 93,391 common shares, at a total investment of approximately $3.3 million (U.S. dollar equivalent). We consider the returns on these investments to be more compelling than the returns available in the current power market environment.

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Notes

(1)                                 Leverage ratio is defined as the ratio of Consolidated Debt to Adjusted EBITDA, calculated for the trailing four quarters. Note that we calculate this ratio on a gross debt basis, not net of cash.

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

(3)                                 Cotting, Ashleigh. “U.S. grid expected to add a net 42,500 MW of capacity in 2018.” S&P Global Market Intelligence, January 30, 2018.

(4)                                 Montier, James. “The 13th Labour of Hercules: Capital Preservation in the Age of Financial Repression.” GMO white paper, November 29, 2012.

Cautionary Note Regarding Forward-Looking Statements

To the extent any statements made in this letter contain information that is not historical, these statements are forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended, and under Canadian securities law (collectively, “forward-looking statements”).

Certain statements in this letter may constitute “forward-looking statements”, which reflect the expectations of management regarding the future growth, results of operations, performance and business prospects and opportunities of the Company and its projects. These statements, which are based on certain assumptions and describe the Company’s future plans, strategies and expectations, can generally be identified by the use of the words “may,” “will,” “project,” “continue,” “believe,” “intend,” “anticipate,” “expect” or similar expressions that are predictions of or indicate future events or trends and which do not relate solely to present or historical matters. Examples of such statements in this letter include, but are not limited, to statements with respect to the following:

·                  the Company’s plan to repay another $100 million of debt in 2018;

·                  the Company’s expectation that its leverage ratio will increase to the high 4 times range by year-end 2018 because of lower expected Project Adjusted EBITDA;

·                  the Company’s expectation that its leverage ratio will begin to decline again in 2019 and beyond;

·                  the Company’s expectation that it will amortize approximately $470 million of term loan and project debt from 2018 through 2022;

·                  the Company’s estimate that its interest payments will decline to approximately $45 million in 2018, which is $27 million below the 2017 level;

·                  the Company’s expectation that it will return the Nipigon plant to service in November 2018;

·                  the Company’s estimate that its optimization investments produced a cumulative cash return of approximately $32 million in 2013 through 2017, and should produce a recurring cash return of approximately $11 million to $12 million annually in 2018 and beyond;

·                  the Company’s expectations with respect to the level of Project Adjusted EBITDA and operating cash flow in 2018;

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·                  the Company’s estimate that the impact of PPA expirations and extensions and the non-recurrence of the OEFC Settlement will reduce 2018 Project Adjusted EBITDA by approximately $105 million relative to 2017;

·                  the Company’s view that the fuel diversity of its plants positions it well under various potential scenarios;

·                  the Company’s expectations with respect to future levels of Project Adjusted EBITDA following the expiration of its PPAs;

·                  the Company’s estimate that it should have net debt of approximately zero by about 2025, assuming planned levels of debt repayment;

·                  the Company’s view of the equity value of the Company under a low power price and significant debt repayment scenario;

·                  the Company’s view that returns from repurchasing its equity securities are compelling, and that its shares are trading well below its estimates of intrinsic value; and

·                  the Company’s indication that it has no expectation of reinstating a cash dividend in the foreseeable future.

Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not or the times at or by which such performance or results will be achieved. Please refer to the factors discussed under “Risk Factors” and “Forward-Looking Information” in the Company’s periodic reports as filed with the U.S. Securities and Exchange Commission (the “SEC”) from time to time for a detailed discussion of the risks and uncertainties affecting the Company. Although the forward-looking statements contained in this news release are based upon what are believed to be reasonable assumptions, investors cannot be assured that actual results will be consistent with these forward-looking statements, and the differences may be material. These forward-looking statements are made as of the date of this letter and, except as expressly required by applicable law, the Company assumes no obligation to update or revise them to reflect new events or circumstances.

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ANNEX A

ATLANTIC POWER CORPORATION

RECONCILIATION OF NET LOSS (A GAAP MEASURE) TO PROJECT ADJUSTED EBITDA FOR

THE YEARS ENDED DECEMBER 31, 2017 AND DECEMBER 31, 2016 (UNAUDITED)

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

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