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Atlantic Power (NYSE:AT)

Q4 2012 Earnings Call

March 01, 2013 8:30 am ET

Executives

Amanda Wagemaker

Barry E. Welch - Chief Executive Officer, President and Director

Paul H. Rapisarda - Executive Vice President of Commercial Development

Terrence Ronan - Chief Financial Officer, Principal Accounting Officer, Executive Vice President and Corporate Secretary

Analysts

Benjamin Pham - BMO Capital Markets Canada

Sean Steuart - TD Securities Equity Research

Nelson Ng - RBC Capital Markets, LLC, Research Division

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Ian Tharp - CIBC World Markets Inc., Research Division

Operator

Good morning, and welcome to the Atlantic Power Corporation Fourth Quarter and Year End 2012 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Amanda Wagemaker, Investor Relations Associate. Please go ahead.

Amanda Wagemaker

Welcome, and thank you for joining us this morning. Please note that we have provided slides to accompany today's call and webcast, which can be found in the Investor Relations section of our website, www.atlanticpower.com. This call will be available for replay on our website for a period of 3 months.

Our results for the 3 months and year ended December 31, 2012, were issued by press release yesterday afternoon and are available on our website and on EDGAR and SEDAR. Financial figures that we'll presenting are stated in U.S. dollars unless otherwise noted. The financial results in yesterday's press release and the matters we will be discussing today include both GAAP and non-GAAP measures. GAAP to non-GAAP reconciliation information for our historical results is appended to our press and annual report on Form 10-K, each of which can be found in the Investor Relations section of our website. We have not provided a reconciliation of forward-looking non-GAAP measures to the directly comparable GAAP measures because due primarily to variability and difficulty in making accurate forecasts and projections, not all of the information necessary for a quantitative reconciliation is available to the company without unreasonable effort.

We have also not reconciled non-GAAP financial measures relating to the projects held-for-sale to the directly comparable GAAP measures due to the difficulty in making the relevant adjustments on an individual project basis. Joining us on today's call are Barry Welch, President and CEO of Atlantic Power; Paul Rapisarda, our Executive Vice President of Commercial Development; and Terry Ronan, our Executive Vice President and Chief Financial Officer.

Before we begin, let me remind everyone that this conference call may contain forward-looking statements. These statements are not guarantees of future performance and involve certain risks and uncertainties that are more fully described in our various securities filings. Actual results may differ materially from such forward-looking statements.

Now let me turn the call over to Barry Welch.

Barry E. Welch

Good morning. I'd' like to extend my thanks as well for everyone joining us this morning. Today, I'd like to review the highlights of 2012, discuss our growth strategy and address the results of a recently completed Annual Review by our Board. Paul will provide an update on our construction projects, as well as development and acquisition opportunities. Terry will review our 2012 financial performance and 2013 guidance.

Moving to Slide 4. For the year 2012, we reported record levels of Project Adjusted EBITDA and Cash Available for Distribution. Project cash distributions of $275 million exceeded the high end of our guidance range by $10 million. We also were within our guidance range for dividend Payout Ratio, which came in at 100% for the year. As we've indicated on previous quarterly calls, the most significant driver of our higher EBITDA and cash flow results in 2012 has been the addition of the 18 projects acquired as part of the Capital Power transaction in November of 2011.

On the growth side, we successfully added 450 megawatts of capacity to our portfolio and now have net ownership of 2,117 megawatts in operation. The 2012 additions include the 300-megawatt Canadian Hills Wind project in Oklahoma, which we brought online in December within budget and in time to qualify for production tax credits. The acquisition of Ridgeline Energy in December added another 150 megawatts to our operating portfolio, including the 120-megawatt Meadow Creek Wind Project in Idaho, which also entered commercial operation in December. Ridgeline also brings with it a strong renewable energy team and a development pipeline.

In January, we announced the sale of 3 of our Florida projects. As you know, the PPAs for Lake and Auburndale will expire in July and December of this year. Market conditions for recontract in these assets became increasingly unfavorable due to the impact on electric demand of a slower-than-anticipated economic recovery, as we indicated on our third quarter call.

As we also mentioned, since it would not be consistent with our business model to operate these projects on a merchant basis and/or at a loss until the markets recovered, we agreed to sell them, along with our Pasco project in Florida, for $136 million, and we'll be using $64 million of the proceeds to repay all outstanding debt under our revolver.

Pro forma for all of our announced asset sales, as well as the addition of Canadian Hills, Piedmont and Ridgeline, our remaining weighted average PPA life improved to nearly -- by nearly 60% to 11.4 years from previously 7.2 years.

Next, on Slide 5, I'd like to cover with you a recently completed review by management and the Board. The review considered all aspects of our business, including our strategy, operating commercial environment, recontracting assumptions, growth prospects, cost of capital, financial leverage and financial projections. An important outcome of this process was a reaffirmation of our commitment to providing shareholders with an attractive total return, with a view toward ensuring a balance between first, a sustainable dividend, and second, solid growth in our cash flows that we believe should translate to higher shareholder value over time.

With respect to the growth component of that total return, our plan is to continue utilizing our core competencies of acquiring, developing, financing, constructing and operating power plants and our proven track record of acquisitions. We continue to see very attractive opportunities in the market to acquire both operating and mid- to late stage development projects. And as I mentioned earlier, Ridgeline, brought us a robust development pipeline of wind and solar projects.

Our focus remains on projects with long-term PPAs and limited commodity exposure. Paul will provide some additional detail and opportunities that we see. Although it's possible to predict the exact mix of investments that we'll make, our base case plan is that capital will be allocated on average approximately 2/3 to operating projects and 1/3 to construction and development projects.

Certainly, in evaluating construction and development opportunities, we do consider the impact on our cash flows of a 1- to 2-year lag in realizing cash contributions. We continue to be very disciplined in our approach, prioritizing only those projects that will be accretive to cash flow either immediately for operating projects or in the first full year of operation for construction and development projects.

As part of this review with the board, we updated our cash flow projections for a number of variables, which we listed on Slide 6. First, many of you are probably aware of recent developments in Ontario. Our Tunis project in Ontario has a contract expiring in 2014, and is not in the first group for which recontacting discussions are already underway with the Ontario government. That process is running significantly behind the government's timetable, and is by design not at all transparent. So the outcome is uncertain, but these recent signals seem increasingly challenging.

The other factor, which is affecting our projects in Ontario currently, is that decreasing flows on the TransCanada pipeline have resulted in significantly higher tolls and also reduced weight heat used by our projects from TCPL's adjacent gas compressors, both of which factors have reduced operating margins at all of our Ontario projects. So we thought it was appropriate to adjust expectations for these projects at least until we can get clarity or there are more positive signals.

In addition to Ontario, Florida was a very significant factor in the adjustment to our cash flow outlook. As I mentioned earlier this year, we reached an agreement to sell 3 of our projects in Florida. We determined that a sale was the best alternative only after we were not selected in the RFP process by Florida Progress Energy, and TECO, Tampa Electric, subsequently announced its own combined cycle plant.

The loss of cash flows from those 3 projects and Path 15, which we're in the active process of selling, had a material impact on our cash flow outlook. We also lowered our expectations for recontacting Selkirk after 2014, based on a longer-than-expected continuation of lower demand levels and market price projections in that part of New York.

Lastly, we also reflected the impact on our cash needs of a greater share of our growth investments, consistent with the 1/3 allocation I mentioned earlier, coming from construction and development projects.

Turning to Slide 7. In evaluating our financial position, cost of capital and updated financial projections, and how they fit with our growth strategy and ability to deliver attractive total return to shareholders, the board, supported by management's recommendation, determined that it was in the best interest of the company and its shareholders to establish a lower and more sustainable Payout Ratio that balances yield and growth and is at the same time consistent with our outlook for current and prospective projects under a range of scenarios. We believe a lower Payout Ratio will improve our financial flexibility in order to deliver on our objective of providing a combination of sustainable income and solid growth from accretive acquisitions, construction ready and development projects, which we believe will enhance shareholder value over time.

Accordingly, the board unanimously approved a reduction in the dividend to an annual rate of CAD 0.40, beginning with the March dividend to be paid in April. The board made this decision only after a very thorough and compressive analysis. The very important consideration at determining the level of dividend going forward was that it would be sustainable under a wide range of scenarios, including adverse ones that we don't anticipate, but where our operating environment is under pressure, growth opportunities could be constrained and/or our access to capital markets could temporarily be limited. These are not our base case assumptions or expected outcomes. But in making the dividend decision, the board believed it was prudent to review downside scenarios. As part of this analysis, we also considered plans for addressing our debt maturities, and Terry will speak to that later.

Given our track record and what we see in the acquisition market, as well as our proprietary opportunities at present, we believe we'll be able to continue making investments that meet our risk-adjusted return hurdles and our accretion criteria that I discussed earlier. We expect these investments to increase shareholder value, contributing to an attractive total return underpinned by a stable dividend. At this point, I'd like to turn the call over to Paul.

Paul H. Rapisarda

Thank you, Barry. I'll be reviewing our construction and development projects, as well as asset sales process. Let me start on Slide 8 by providing an update on our 53-megawatt Piedmont Green Power biomass project in Georgia. In the fourth quarter of last year, we indicated that the commercial operation of Piedmont would be delayed to the first quarter of 2013 due to start-up issues identified in late stage testing. The last section of blades in the project's steam turbine sustained damage during commissioning in mid-November, which in turn caused the rotor to need to be repaired. We've been working with Siemens, the turbine manufacturer, and Zachry, the EPC contractor, to identify the causes of the problem and to repair the components of the turbine that were damaged in a timely manner. I'm happy to report that the repaired steam turbine is now back on site and restart efforts are well underway. We anticipate that the project will be commissioned in late March. At the same time, liquidated damage payments by the contractors are covering such items as ongoing interest costs and payments to the utility customer for delayed in-service. Therefore, the project is still within budget.

Separately, we have lowered our expectation for cash distributions from Piedmont to a range of $6 million to $8 million annually, down from our prior guidance of $8 million to $10 million. This is primarily due to reduced expectations regarding the value of the project's renewable energy credits. Although this delay does affect the timing of our application for the 1603 federal cash grant for Piedmont, it will not affect our entitlement to the program's benefits, as biomass projects under the program had until the end of 2013 to achieve commercial operation. Proceeds from the grant will be used to repay the $50 million bridge loan at Piedmont. Similarly, our Meadow Creek Wind Project also qualifies for this type of grant, and we expect to use the proceeds of its grant to repay its approximately $57 million cash grant loan.

Both Piedmont and Meadow Creek may be affected by the U.S. budget reductions currently being discussed and known as sequestration. We're obviously monitoring this discussion very closely. Each project has a unique in-service date, capital structure and other risk-sharing mechanisms that make it difficult to predict the impact that sequestration may have on each of these projects. However, in no event do we anticipate the impact to be material to our projections.

Now I would like to take a moment to discuss the continued rationalization of our current portfolio. As Barry mentioned, we announced in January the agreement to sell 3 of our Florida assets. Other assets that we have identified as candidates for divestiture are those where we are not the majority owner or operator or which do not make meaningful cash flow contributions. In that vein, we have executed an agreement to sell our 40% interest in the Delta Person generating station to the current power purchaser, Public Service of New Mexico. We expect to receive net proceeds of approximately $9 million and closing is currently expected in the third quarter.

We're also in an active process to sell our 17% interest in the Gregory project in Texas. Both Delta and Gregory are being sold together with the interests of the other partners in the projects, which tends to maximize the value for minority interests, such as ours.

Finally, we're also conducting a sale process for our 100% interest in the Path 15 transmission line in California, which is our most highly levered asset, and for which the cash flow contribution is modest in the context of our overall portfolio. These efforts are progressing along a track where we expect to have more specific details to announce later in the first half of this year.

Turning now on the development front slide, as outlined on Slide 9. The integration of Ridgeline Energy is progressing well. We spent the last few months prioritizing the development projects in their pipeline and determining how to best allocate Ridgeline's renewable energy expertise and resources to both development, as well as supporting our acquisition efforts. The extension of the production tax credit in the U.S. has caused us to take a fresh look at Ridgeline's 600-megawatt development pipeline. And we're now focusing our efforts on those wind and solar projects that can take advantage of the extended PTC program for wind and the investment tax credit program for solar. We're likely to allocate more effort to wind prospects in the near term.

At the same time, the Ridgeline team is making good progress on securing PPAs for a number of its solar development projects in several U.S. markets. This tax credit extension also does apply to biomass facilities. To that end, we're taking a fresh look at a Rollcast project that would be very similar to Piedmont. The Greenway Project is a 53-megawatt biomass facility, also in Georgia, with an executed 20-year PPA that we had put on hold when it became obvious that it could not meet the previous 2013 in-service deadline for commercial operation. Rollcast is in the process of talking to potential EPC contractors, as well as refreshing the economics of the project.

Apart from Ridgeline and Rollcast, we continue to pursue other near-term acquisition opportunities. Although none are at a stage warranting specific disclosure at this time, they do include possible solar-, wind- and gas-fired projects, any one of which could contribute meaningfully to our portfolio project distributions.

More generally, the overall outlook for acquisition opportunities appears to be at least as strong as the market environment was in 2012. We certainly expect to be able to invest a meaningful amount of the $140 million to $150 million of cash that we expect to have available as early as the second half of this year.

Even within this competitive environment, our ability to access proprietary transactions and our willingness to look at more complex deals, such as the Capital Power transaction in 2011, enabled us to successfully invest $300 million in 2012, including the 150 megawatts of operating projects at Ridgeline, which Barry mentioned.

Finally, I'd like to provide an update on operations on Slide 10. At our Nipigon project, we are planning a replacement of the heat recovery steam generator this fall, subject to receiving favorable outcomes on our permit application and certain other approvals. The cost of the steam gener replacement will be approximately $11 million, which will be capitalized. We expect payback for this significant investment to come through more efficient use of the waste heat and increased output over the remaining term of the PPA. The other major scheduled outage this year is at Tunis, where the gas turbine is due for its hot gas path inspection. These 2 outages contribute to an increase in our major maintenance expense this year to an estimated $34 million, excluding the $11 million equipment cost at Nipigon from about $31 million this past year.

An important part of our strategy has always been to optimize the financial performance of our existing assets, whether that be through improving operations of the plants, investing in equipment upgrades where necessary, putting better fuel contracts or hedges in place, or arranging better commercial or contractual terms for the sale of the output. Examples from the past year include 10-year extensions of both the PPA and fuel supply agreement at our Nipigon project; the installation of in line fogging equipment at Tunis, which improves the efficiency of the gas turbine during periods of high ambient temperature; and finally, in conjunction with the scheduled maintenance at Mamquam, we installed a new programmable logic controller and flow-enhancing equipment, which has enabled us to significantly reduce ramping at the project, as well as increasing the amount of water that we can run through the turbine. We certainly will continue to develop more such opportunities in 2013. At this point, I'd like to turn the call over to Terry.

Terrence Ronan

Thank you, Paul, and good morning, everyone. Before turning to a review of the financial results for the year, let me start on Slide 11, by noting how the sale of several of our projects affected the presentation of our financial statements. As you know, several of our projects, specifically the Path 15 transmission line and our Auburndale, Lake and Pasco projects in Florida, are classified as assets held-for-sale. Under GAAP accounting, this means that for 2012, as well as for 2011 and '10, the income attributable to these projects is included in the income from discontinued operations line of the statement of operations. Thus, we exclude the results of these projects from revenues, project income and Project Adjusted EBITDA, as shown on the tables in the press release. The assets of these projects and the related liabilities are also presented separately on our balance sheet.

However, under GAAP accounting, cash flow reporting for these discontinued businesses can be treated differently. The cash flow attributable to these projects is included in the cash flow from operating activities, as shown on the statement of cash flows, as well as in our calculation of Cash Available for Distribution and Payout Ratio shown in the press release. I'd note that the cash flows from the projects held-for-sale have been received by us and will continue to be received in 2013 until the closing of the asset sales.

The cash flow attributable to the 3 Florida projects being held-for-sale will then be deducted from the final purchase price, with the adjusted purchase price being recorded in investing cash flow rather than as a deduction to operating cash flow. I think it will be helpful to keep this distinction in mind in reviewing the 2012 results as well as our guidance for 2013.

For the full year 2012, Project Adjusted EBITDA increased to $226 million from $85 million in 2011. As you can see on Slide 12, approximately $120 million of the year-over-year increase was attributable to contributions from the 18 partnership projects, which we owned for approximately 2 months in 2011. Another factor was the settlement of our litigation with DuPont at our Chambers project in the second and the fourth quarters, which added $9.6 million to 2012 Project Adjusted EBITDA.

Slide 13 provides an overview for our full year 2012 results. Cash flows from operating activities for the full year 2012 increased to $167 million from $56 million in 2011. Again, this increase is primarily due to contributions from the 18 partnership projects and distributions from several other projects. Cash Available for Distribution increased to $132 million in 2012 from $79 million in 2011. These increases were primarily attributable to the higher levels of Project Adjusted EBITDA.

Our dividend Payout Ratio for the full year 2012 was 100%, compared to 109% in 2011. The 2012 Payout Ratio was within the company's guidance range of 96% to 102%.

Turning to Slide 14 of our balance sheet. At December 31, 2012, we have $1.65 billion of debt, excluding the liabilities associated with the assets held for sale, in addition to $424 million of convertible debentures. Approximately 90% of the debt was long term. We also have $221 million of preferred equity at the corporate level.

Our debt balances include $336 million of construction debt from Meadow Creek and Piedmont. This includes approximately $108 million associated with Piedmont and Meadow Creek that we expect to repay with proceeds of cash grants that these projects are eligible for under the 1603 program, as Paul described. The remaining Meadow Creek construction debt will convert to term loan in June, and the remaining Piedmont construction debt will convert to a term loan following its placement of service.

I'd also note that our year end 2012 balance sheet reflects the acquisition of Ridgeline on December 31. This resulted in the consolidation of $295 million of nonrecourse project and construction debt mostly related to Meadow Creek, although there was no benefit to our income or cash flows in 2012.

As you can see from Slide 15, our total liquidity at year end 2012 was $209 million. This includes cash on hand of $89 million and $120 million of borrowing capacity under our senior credit facility, net of letters of credit and existing borrowings of $67 million.

In December 2012, we drew $44 million on our senior credit facility to fund the remaining amount of a $270 million tax equity investment in our Canadian Hills Wind project, after funding $225 million through 4 other tax equity investors. We anticipate that we'll syndicate our $44 million tax equity investment in Canadian Hills in the first half of this year.

We anticipate closing on the sale of the Florida assets by the end of this month and expect to receive net proceeds of $111 million after repayment of project level debt at Auburndale and settlement of all outstanding natural gas swap agreements at Lake and Auburndale. We expect to use the proceeds first to fully repay the $64 million drawn on the senior credit facility and the remainder will be available for general corporate purposes, including potential acquisitions. Our senior revolving credit facility is a primary source of liquidity, and it matures in November 2015. Although we expect to remain in compliance with the covenants of the credit facility through late 2014, we're considering a variety of measures to reduce our leverage to remain in compliance with the covenants beyond such time.

By mid 2013, we expect to have approximately $140 million to $150 million available for investments in new projects net of a planned $50 million cash reserve. To walk you through how we get there, we start with our year end 2012 cash balance of $60 million. Next, we add the proceeds from the Florida asset sales and the expected sale of our Path 15, Delta Person and Gregory assets; the expected proceeds from syndicating our $44 million tax equity in Canadian Hills; and our cash generation in the first half of the year. We then subtract the paydown of the $64 million outstanding under our revolver, CapEx from the first half and dividends in first half. That would get us to $190 million to $200 million of cash before the $50 million reserve. In addition, our revolver capacity would be between $210 million and $225 million net of letters of credit outstanding.

With respect to revolver availability, the 2 drivers of the increase from year end 2012 to mid-2013 are the paydown of the outstanding borrowings and an expected reduction in letters of credit posted related to the asset sales.

Next, I'd like to turn to our 2013 guidance on Slide 16. In past years, we had provided guidance for the Payout Ratio and project cash distributions. As you can see from the press release on Slide 16, for 2013, we have provided guidance for Project Adjusted EBITDA, Cash Available for Distribution and Payout Ratio. We've also provided some supplementary guidance that we think should be helpful in modeling the reconciliation of Project Adjusted EBITDA and Cash Available for Distribution. We hope you find these additional disclosures to be useful.

Let me walk through Slide 17, which bridges our 2012 Project Adjusted EBITDA to our 2013 guidance for Project Adjusted EBITDA of $250 million to $275 million. As I've previously mentioned, 2012 Project Adjusted EBITDA was $226 million, excluding $107 million from the assets held for sale. Key year-over-year drivers include 2012 results included a $10 million onetime benefit from the settlement of litigations at our Chambers project that I had mentioned earlier. By its nature, this will not recur in 2013.

Secondly, the planned outages and other factors that our Nipigon and Tunis projects have an impact of about $12 million or so year-over-year. About 2/3 of this impact is attributable to maintenance expense and reduced output during the outages, and the remaining 1/3 relates to the change in the dispatch profile at Tunis, as well as higher gas costs for both plants.

Third, we're expecting the rest of the portfolio, excluding new projects, to be up a few million dollars year-over-year.

Lastly, new projects, primarily Canadian Hills, Meadow Creek, Piedmont and our increased ownership interest in Rockland are expected to account for between $48 million and $65 million of the year-over-year increase. The net of these factors takes you to right about the midpoint of our guidance range of $250 million to $275 million.

Although they're still included our results and our guidance, we have an agreement to sell Delta Person and are pursuing the sale of Gregory. These 2 projects represent about $2 million of projected adjusted -- Project Adjusted EBITDA this year, assuming a midyear closing. If we are successful in selling them, we would not have those earnings in 2014.

in Slide 18, we've reconciled Project Adjusted EBITDA to Cash Available for Distribution for 2012, as well as for 2013 guidance. As you can see, the primary deductions from Project Adjusted EBITDA before getting to Cash Available for Distribution are: nonrecourse project level debt service, including interest expense as well as amortization of project debt; corporate interest expense, including preferred dividends -- we did not have any mandatory corporate debt repayments in 2012 and there are none scheduled for 2013; capitalized portion of maintenance CapEx for our existing projects -- this does not include CapEx associated with projects under construction, which we would consider to be growth CapEx; corporate G&A expense, including project development expenses and cash income taxes; finally, changes in working capital and other.

In looking at these changes in these categories year-over-year, I'd point out the following. First, project level debt service is about $20 million larger, or greater, largely due to the addition of Meadow Creek, Piedmont and an increased ownership interest in Rockland. Corporate debt costs are expected to be up about $3 million year-on-year. The capitalized portion of maintenance CapEx is substantially higher due to the $11 million steam generator replacement at Nipigon that Paul discussed. Typically, our capitalized maintenance expense -- expenditures for the existing portfolio average about $3 million to $5 million per year. Corporate G&A expense is about $10 million higher, due primarily to increased G&A expense and development costs attributable to our acquisition of Ridgeline.

As I mentioned at the beginning of my remarks, it's important to keep in mind that the cash flow attributable to the assets held for sale is included in the cash flow from operations, and therefore, not a calculation of Cash Available for Distribution. As you can see from the slide, approximately $77 million of Cash Available for Distribution in 2012 was attributable to assets held for sale. For 2013, we expect that approximately $44 million of our Cash Available for Distribution will come from the assets held for sale.

Our guidance is a dividend Payout Ratio in the range of 65% to 75% in 2013, reflecting actual dividends declared as a percentage of Cash Available for Distribution. However, as I mentioned, this includes the benefit of cash flow attributable to the assets being sold.

To provide more extensive disclosure, we've also shown the Payout Ratio on a pro forma basis for the year on Slide 19. This reflects 2 adjustments. First, it annualizes the lower dividend rate as if it had been in effect for the entire 12 months. Secondly, it excludes the cash flows attributable to the assets held for sale, as those cash flows will not continue beyond this year. On this pro forma basis, our 2013 guidance for the Payout Ratio would be approximately 100% using the midpoint of our cash flow guidance. This is the higher but more conservative approach to presenting this ratio for this year.

More relevant though is that we expect our 2014 Payout Ratio to decline to approximately 75% to 85%, due to higher levels of Cash Available for Distribution, in part resulting from more favorable gas arrangements at our Orlando project, lower outage-related expenses and lower capitalized maintenance with the completion of the Nipigon outage and an initial return of the $140 million to $150 million that we plan to invest, partly offset by declines in some of our existing projects, such as Selkirk, where the PPA expires in 2014.

Turning to Slide 20, our plan is to delever gradually over time. The majority of our nonrecourse project debt amortizes over the remaining life of the PPA, which reduces our exposure to bullet maturities and provides some degree of delevering on a scheduled basis. Consistent with what we've said in the past about refinancing debt associated with the partnership projects, we intend to pursue an approach of refinancing partnership level debt on a 50-50 debt-to-equity basis. We're also considering a number of other measures to reduce leverage, including tax equity structures at our Piedmont and Meadow Creek projects, or at new Ridgeline development projects to monetize tax benefits that we cannot efficiently use.

In terms of financing our growth strategy, our focus remains on projects with long-term PPAs with investment grade counterparties and limited commodity exposure. We're targeting 50% project debt and 50% capital raise at the parent. Project finance market remains strong, with attractive terms for quality projects.

With respect to our equity contribution to these projects, we expect to have approximately $140 million to $150 million available at mid-2013 for investments in growth. Beyond this availability, we expect that we would fund our equity commitments, primarily through the capital markets. As Barry indicated, our threshold for investment in these projects is that they be accretive to our cost of capital and that they generate cash flow and earnings accretion as early as possible. In addition, we're looking to achieve a mix of incremental investments that will potentially benefit the leverage metrics of our overall portfolio.

As you can see from Slide 21, we do not have any corporate debt maturities this year. In 2014, we have $190 million of senior unsecured notes at our Curtis Palmer project maturing in July and a $45 million convertible debenture maturing in October. Our base case plan is to refinance the debenture in the convertible market and to refinance Curtis Palmer with a 50-50 split of debt and equity. We've also looked at alternatives that would not require access to the capital markets for these maturities.

As I noted previously, we expect that once we have repaid the outstanding balance under our revolving credit facility with proceeds from the Florida asset sales, it will remain undrawn, leaving $210 million to $225 million available to us net of letters of credit. With respect to 2015, obviously, a couple of years away, but as of now, we would expect to refinance the $150 million Atlantic Power U.S. GP note in the capital markets with a 50-50 split of debt and equity. Thank you, and now I'll turn the call back to Barry.

Barry E. Welch

Thanks, Terry. So let me sum up on Slide 22. We have a well-diversified portfolio with stable contracted cash flows, whose remaining average PPA life is now more than 11 years. Portfolio consists of environmentally friendly fuels, with an increasing component of wind and soon, solar. We've got a proactive approach to managing our physical assets and commercial arrangements to optimize cash flows. We manage risk through contractual and other hedging structures, and we will be reducing our leverage over time. The dividend is sustainable for the long term and should underpin attractive total returns that are appropriately balanced, income and growth. We see robust growth opportunities and are taking a disciplined approach that we believe will result in strong value creation for shareholders. That concludes our prepared remarks, and I'd like to thank you for your time and attention this morning. We're now pleased to answer any questions you may have.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Ben Pham at BMO Capital Markets.

Benjamin Pham - BMO Capital Markets Canada

My first question is on the capital allocation and I'm just curious on the degree that you would consider a stock buyback program. And also, what's your plan for the DRIP?

Barry E. Welch

Ben, we have no interest right now or intention to initiate a stock buyback program. I think it would be inconsistent with how we're resetting the dividend for sustainability in order to conserve cash and refocus that cash into the growth side of our model. And with respect to DRIP -- by the way, it would also be inconsistent in terms of our goals of reducing leverage. With respect to the DRIP, I believe the levels that we're seeing are only around the 5% level. There have been some difficulties on the U.S. side with people implementing their intended election to try to get the DRIP, and so that's all we have on the DRIP for now.

Benjamin Pham - BMO Capital Markets Canada

And then the follow-up is more of a detailed question on your corporate G&A. And you do note increased to $40 million. And you did cite the development team at Ridgeline driving that and so going forward, though, is that uplift a structural lift upwards?

Barry E. Welch

Well, it is. Let me go back to the Ridgeline acquisition release and try to go over that. We mentioned that we have the addition from the operating projects that we got it to $9 million to $12 million of cash flow, but we also mentioned that we'd be roughly neutral, at least, for the first 3 years with respect to the G&A and development costs that we will put back into Ridgeline, which is a company, part of Atlantic now of 30-plus employees and so on. And so that sort of G&A and development cost outlay is somewhere in the $12 million range, and that would explain the bulk of the difference that you alluded to.

Operator

Our next question is from Sean Steuart at TD Securities.

Sean Steuart - TD Securities Equity Research

A couple of questions. You've given us a good bridge to get to the 2013 guidance. But I guess looking further ahead, I'm wondering if you can give some context around a commentary made around, I guess, expectations for the NG [ph] recontracting starting with Tunis. And any magnitude you can give us on expectations for TCPL tolls that are going into your longer-term thinking?

Barry E. Welch

Sure. So taking the first one, Sean, first of all, the process, as I mentioned, is anything but transparent. And so our decision-making around assumptions there for recontact is really based on the sort of the symptoms that we can look at of the delayed process and wondering if that doesn't have to do with difficulty of the parties reaching a price. And so we can't, other than that, since we're about to go into the room at some point and negotiate we would like to not signal publicly, more specifically on our expectations. And with respect to TCPL, I think you're aware that it's been an ongoing back and forth and that, that's in front of the NEB now. And so I think basically, our approach has been to remain conservative, given some of the seesawing that we've seen in terms of expectations, at one point, that would be reduced, which NEB seemed to agree with, and it went back the other way. And so we've chosen, as I say, to be relatively conservative about where those will be in the near term, and in addition, to remain conservative about the flows coming through where -- it affects just in the winter, the compressors are just not running nearly as much, if at all, and so that drops off the waste heat. If we don't have the waste heat, we have to put natural gas into the boilers to make up for it.

Sean Steuart - TD Securities Equity Research

Okay. And the second question is on the Ridgeline prospective pipeline. You're talking about, I guess, 10 projects with 600 megawatts and I think when you announced the deal initially, you were talking about 20 projects with 1,000 megawatts, and I'm wondering if you can bridge that gap? And then also, discuss, I mean, the portion of that, that you think might be ready to go by year end and qualify for the PTC?

Paul H. Rapisarda

Yes. So Sean, this is Paul. I think it -- when we did the announcement, we also made it clear that while it was a very attractive development portfolio, there were no projects in it that had PPAs. So we have continued to work with the Ridgeline team to refine the portfolio to try to prioritize things that could get PPAs before the end of the year, and so I wouldn't put too much emphasis on the specific number of projects or the specific amount of megawatts. I think we are optimistic that we should get at least one project to the stage where we have a signed PPA before the end of the year and enable us to meet the definition for start of construction, so it will qualify for the extension of the tax credits.

Operator

The next question comes from Nelson Ng at RBC Capital Markets.

Nelson Ng - RBC Capital Markets, LLC, Research Division

In terms of Piedmont, you mentioned that the cash flow expectations have come down a bit due to the weakness in the RECs market. Can you remind me whether any other facilities have exposure to the RECs --or sorry, any other like facilities like whether it's a Canadian Hills or a Cadillac or any other ones where you'd expect the RECs market could have impact on the cash flows?

Paul H. Rapisarda

Yes. So within the current renewables portfolio, the 2 other projects that do have REC opportunities, one is Cadillac, where the majority of the RECs go to consumers' power under the PPA. We do sell a very modest amount, and I think the total contribution is less than $0.5 million a year, so I wouldn't view that as material. The other project where we have RECs that we're selling is Idaho Wind. In that, we've got, as you know, the 27% interest. We have a contract there, but it doesn't start until, I believe, 2015 or 2017. So we have some exposure in the short term there, but we haven't put a substantial amount of RECs in our guidance for Idaho Wind.

Nelson Ng - RBC Capital Markets, LLC, Research Division

Okay. And then in terms of Tunis and Selkirk, could you remind me which month in 2014 the PPAs expire? And also, I guess, have you taken this approach for Lake and Auburndale in terms of whether you would look to sell those 2 assets as well?

Barry E. Welch

So I know Tunis is the end of '14, and Selkirk, I think, we're sort of checking our chart. And your other question was on which others, Nelson?

Nelson Ng - RBC Capital Markets, LLC, Research Division

Sorry. Yes, it's just Tunis and Selkirk, the timing of the PPA exploration and then also -- sorry, go on.

Barry E. Welch

Sorry, Selkirk is September 14.

Nelson Ng - RBC Capital Markets, LLC, Research Division

Okay. And the question was whether you would look to sell these assets?

Barry E. Welch

Tunis hasn't been on our list to consider. Selkirk certainly has more of a look with respect to some of the themes we've mentioned on rationalizing noncore, i.e., it is a minority interest. We are not the operator. And relative contribution on a go forward, we do have that on a list where we would consider that.

Operator

The next question comes from Matthew Akman at Scotiabank.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

My question, I guess, is around what has happened on the variance in the dividend level in your guidance? And I'm just wondering when the board raised the dividend, I guess, just 16 months ago now, did it have a reasonable projection in front of it to dividend sustainability over the next 3 to 5 years from when it did so? And I guess if it did, and I would hope that it did, what changed in such a short period of time to have such a dramatic reduction in the outlook?

Barry E. Welch

Sure, Matt. Yes, we did have, at that point, in front of us a projection we felt supported the sustainability. And so a number of things that we've talked about, some on the call and some not, I'll sort of tick through them. Out of the opening box in terms of financing the acquisition, we've mentioned that our entry into the high-yield market at the time as a first tier time issuer in a very, very tough market, where a number of high-yield issuances we're actually pulled left us with a price of about 9.5% on that. Having said that, that bond has performed the way we would have expected. It has traded in to very close to 7%. We had shortened the tenure and the time of the first call to 3 years, which is November '14. And so depending on how the market hangs in, obviously, we'll be trying to get some of that back. Another component, staying on the significant ones with respect to CPILP acquisition, specifically, is Ontario, where the multiple impacts that have led us from a TCPL flow point of view, increased tolls, reduced waste heat, have impacted us. And then on a go forward basis, we mentioned the expectations that we're resetting for the time being on recontracting for Tunis at the end of '14. And that's a different picture than we had at the time. And then ticking through the others, Florida has continued to deteriorate as a market. Put it the other way around, it has continued to not recover like the rest of the economy, et cetera. And so obviously, that lead us through an expectation, we'd get a contract with Progress to the change, even since the third quarter call, where, in December, we were not selected in the second round to go forward. Tampa Electric announced the large self-build, very efficient combined cycle that we intended to be the hoped-for buyer, still could be potentially, but of the Auburndale output, Selkirk is really -- it's a little bit like a Florida market in terms of its sluggishness on recovery. Different, however, than Florida in that it's a very liquid market, and so we have pricing visibility on the forward markets, and people can give us projections. So we've stared at those, and those are worse. And you can sort of look at different third parties, and capacity needs have pushed out. And pricing on NYMEX, if you look at NYISO Zone G, you'll see that, that has not looked like what would have expected. Shift in business mix, we talked about including additional development side projects with the lag to cash flows. And then I'd say at -- somewhere in mix, when you're doing the projections, you want to run up and down your cost of capital in terms of what it does with respect to the growth component of your projections, and that obviously has moved some over time. So there were quite a few things coming together that were not evident at the time.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

Can I just -- my follow-up is on Ontario because I understand why for 2013 it's weaker with the Nipigon turnaround. You've quantified that as $11 million to $14 million, but does that continue into 2014 in your guidance or isn't that kind of a onetime due to the turnaround?

Barry E. Welch

Yes. With respect to Nipigon, specifically, that $11 million CapEx is absolutely a year -- is not -- it's capitalized CapEx, and so it's not in the cash for operations or Payout Ratio per se. And we do expect to get a payback from, but that is strictly a '13 item if -- again, if we are able to get the permits, et cetera, to move forward. If we don't, then we obviously will not be spending $11 million.

Matthew Akman - Scotiabank Global Banking and Markets, Research Division

So that really has very little to do with your 2014 guidance?

Barry E. Welch

That's right. I think I understand how you're asking the question. That's right.

Operator

The next question is from Ian Tharp at CIBC World Markets.

Ian Tharp - CIBC World Markets Inc., Research Division

So first question for Paul. I think in calls past, we've talked about opportunities I think you mentioned one now through Rollcast. In light if your revised reviews on RECs, it sounds like you're doing some more costing and looking at your EPC provider there. But are you fairly confident at this point that the economics will hold together on that next Rollcast biomass project given the REC changes?

Paul H. Rapisarda

Well, I think one of the things we want to make sure is that it does. I think it is early for us to speculate, and that's why I said we are reviewing and Rollcast has gone back out to get new EPC quotes. But I wouldn't venture to tell you, at this point, Ian, whether we think that's a project that will meet our hurdle rates yet or not.

Ian Tharp - CIBC World Markets Inc., Research Division

Okay. Fair enough. Okay. And then moving to Ridgeline, I think Sean asked some questions around the portfolio opportunities there, and I think you alluded both in your MD&A and comments today around the potential for at PPA. I guess that the risk is that it's a 10-megawatt solar project versus a 100-megawatt wind. So I wonder if you can talk a little bit about the size of projects you're looking at in solar, and maybe some of the places that you see some the nearest opportunity for PPA awards and contracts.

Paul H. Rapisarda

Sure. And this is a combination of both what Ridgeline is actively looking at within its portfolio and then with respect to the extension of the tax benefits, we're collectively looking at a broader range of things. But specifically, with respect to Ridgeline, I think their strategy, which we certainly concur with, is they're looking in markets where the initial projects may be in the size range, Ian, that you alluded to, i.e. 20 megawatts to 40 megawatts, but they're also in markets where we believe we'll be able to do multiple projects. So the expectation would be not to just do one 20-megawatt project, for example, in a given state.

Ian Tharp - CIBC World Markets Inc., Research Division

Okay, so that's on the solar side. And then, wind, what kind of sweet spot do they have in terms of project size?

Paul H. Rapisarda

Yes. I think on wind, we'll continue to be focused on the kind of projects that they've done, i.e. Meadow Creek, which was 120 megawatts on up to the size of Canadian Hills, which we did last year, which is 300 megawatts.

Ian Tharp - CIBC World Markets Inc., Research Division

Okay, helpful. Okay. And then moving on to, I guess, just briefly on Nipigon. When do you expect to take it out and how long does it get taken out of service for the maintenance this year?

Paul H. Rapisarda

So the current schedule outage is going to start this fall in September, I believe. And the length of it will depend in part, as Barry mentioned, as to whether we get the permits to do the HRSG upgrade.

Ian Tharp - CIBC World Markets Inc., Research Division

Okay. But if you get the HRSG upgrade permit, what do you expect on timing?

Paul H. Rapisarda

I believe it's a couple of months, but we'll confirm that for you.

Ian Tharp - CIBC World Markets Inc., Research Division

Okay, great. And then on the debt reserve, Terry, you've set aside the $50 million of the cash available. I'm just wondering what the origins of that. Is that just the board's approach to kind of a rainy day fund on the balance sheet or is that more a requirement of some of your creditors?

Terrence Ronan

No, it's not a requirement by any creditors nor is the board involved in that decision. That's just something that we feel comfortable with having on the balance sheet, paying a monthly dividend and all.

Ian Tharp - CIBC World Markets Inc., Research Division

Okay, great. And then finally on Path 15, last conference call, you talked about a process. I think first round bids were due. So if you can give a little bit more color on how that's progressing, that would be helpful.

Paul H. Rapisarda

Yes. So we have gone through the first round and selected a smaller group of shortlisted second round bidders and have actually gotten it down to where we're close to signing something with the preferred bidder. As we've done in the past, we wouldn't announce anything until we have a signed purchase and sale agreement on that.

Operator

The next question comes from Sean Steuart at TD Securities.

Sean Steuart - TD Securities Equity Research

Just one follow-up guys. You talked about, I guess, your target investment mix of 2/3 operating and 1/3 construction development in terms of your longer-term growth. I'm just wondering how you can -- how you'd target those numbers, and I would think with respect to operating assets in a competitive environment with low cost of debt, it's increasingly difficult to find accretive deals. Can you talk a little bit about the thinking that goes into that long-term mix?

Barry E. Welch

Sure, Sean. I'll take one cut at it and then Paul may want to add something as well. I think what you're alluding to is correct. That certain of the operating projects are highly competitive and would be likely to go to somebody with a lower cost of capital, those being the ones with beautiful power purchase agreements all set, no technical issues, not much complexity, sort of a single asset at time would be exactly that kind of an asset. It is a pretty competitive market. On the other hand, and Ridgeline is a bit of a hybrid obviously, but in the case of Ridgeline, much more complex investment. They got us a combination of 150 megawatts of spinning cash-flowing assets, along with the opportunity to do the development work. And so it's a sort of an in between, where that was a complicated transaction. It involved our starting a relationship long before that with a small investment in Rockland. We had in mind the idea of some kind of a partnership. We got lucky that [indiscernible] decided, maybe 6 months after our investment in Rockland, that they were looking to sell their renewables in both North America and Europe. And so it's an example of sort of capitalizing on somewhat more proprietary channels and relationships that we're working on all the time.

Sean Steuart - TD Securities Equity Research

And just a second follow-up. On Chambers, I'm not sure if you can give specifics, but can you talk a little bit about distribution expectations from that asset and timing around that?

Barry E. Welch

Do you mean for '13?

Sean Steuart - TD Securities Equity Research

Yes. '13 and beyond, I guess.

Barry E. Welch

I don't if we've guided Chambers specifically, and at the current time, we have a piece of HoldCo debt that we've put in place at the acquisition. And we've cleared through the cash traps that were there because of the settlement being paid last year. And so it will be -- we will be pulling cash flow through on that, but I don't think we've given a specific number.

Sean Steuart - TD Securities Equity Research

But starting right about now? In terms of ...

Barry E. Welch

Yes. We've cleared the cash flow test at that holding company, as I say, because of the payment that did come through on the settlement with DuPont.

Operator

This concludes today's question-and-answer session. I'd like to turn the conference back over to Barry Welch for any closing remarks.

Barry E. Welch

Thanks very much for your time and attention today and your interest in Atlantic Power. Goodbye.

Operator

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.

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