Atlantic Power's CEO Discusses Q4 2013 Earnings Results - Earnings Call Transcript

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Atlantic Power Corporation (NYSE:AT)

Q4 2013 Results Earnings Conference Call

February 28, 2014 8:30 pm ET

Executives

Amanda Wagemaker – Investor Relations

Barry E. Welch – President, Chief Executive Officer & Director

Edward C. Hall, III – Chief Operating Officer & Executive Vice President

Paul H. Rapisarda – Executive Vice President Commercial Development

Terrence Ronan – Executive Vice President, Chief Financial Officer, Principle Financial and Accounting Officer & Corporate Secretary

Analyst

Nelson NG – RBC Capital Markets

Rupert M. Mere – National Bank Financial

Sean Steuart – TD Newcrest

Matthew Akman – Scotia Capital

Ben Pham – BMO Capital Markets

Jeremy Rosenfield – Desjardins Securities

Operator

Welcome to the Atlantic Power Corporation fourth quarter and year end 2013 earnings conference call. All participants will be in listen-only mode. (Operator Instructions) After today’s presentation there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Amanda Wagemaker.

Amanda Wagemaker

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 three months. Our results for the three months and year ended December 31, 2013 were issued by press release yesterday afternoon and are available on our website and on EDGAR and [CGAR].

Financial figures that we’ll be presenting are stated in US dollars unless otherwise noted. The financial results in yesterday’s press release and the matters we’ll be discussing today include both GAAP and non-GAAP measures. GAAP to non-GAAP reconciliation information for our historical results is appended to the press release and annual report on Form 10K, 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 not all of the information necessary for a quantitative reconciliation is available to the company without unreasonable efforts primarily as a result of the variability and difficulty in making accurate forecasts and projections. We also have not reconciled non-GAAP financial measures relating to individual projects to the directly comparable GAAP measures due to the difficulty in making the relative adjustments on an individual project basis.

Joining us on today’s call are Barry Welch, President and CEO of Atlantic Power, Ned Hall, our Executive Vice President and Chief Operating Officer, 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

First, I’d like to briefly review our ’13 results and then provide a strategic update including a review of the progress we’ve made on our financial objectives. I will also highlight the benefits of our refinancing transaction that closed earlier this week and then provide a brief summary of the ’14 guidance that we initiated. Ned will discuss our operating performance and provide an update on our asset optimization initiatives. Paul will provide a commercial update on a few of our projects and markets. Terry will cover the refinancing in a bit more detail, review our ’13 results and discuss ’14 guidance.

Turning to Slide Four in our 2013 financial results, we reported $270.5 million of project adjusted EBITDA which was slightly above the midpoint of our revised guidance range of $260 million to $275 million. Results were up 19% versus 2012 with the most significant drivers being the addition of our Canadian Hills, Meadow Creek and Rockland projects. In 2013 our cash available for distribution came in at $109 million which was above the upper end of our guidance range of $85 million to $100 million.

In addition to meeting or exceeding our guidance for 2013 we are projecting a $22 million increase in project adjusted EBITDA for 2014 based on the midpoints of our guidance. We’re on track to realize the benefit of $8 million of administrative cost reductions that we began implementing last summer. We’ve also significantly ramped up our optimization efforts [inaudible] attractive investments in our existing portfolio of projects that are already producing incremental EBITDA beginning this year.

On our previous call I indicated that our highest priority objectives were to address our near term maturities and increase our financial flexibility. We’re very pleased that we were able to implement a comprehensive refinancing that represents considerable progress in meeting those goals and helps us simplify our capital structure. I’ll talk more about the transaction in a moment. With this financing behind us, management and the board will be evaluating additional proactive steps. We understand that investors have questions about the sustainability of our dividend.

As we indicated on our previous call, the approach that we had under consideration and ultimately decided upon to refinance some of our debt maturities results in a significant amount of our cash being applied to reduce debt which reduces the availability of cash flow for other uses. We expect to take this into consideration in evaluating our dividend level going forward.

Another area of investor focus has been our ability to grow in view of our cost of capital and our modest level of cash generation after debt service. As I mentioned, we have a significant program of attractive organic growth opportunities where we believe the risk adjusted returns are compelling, capital requirements are modest, and the lack between investment and cash returns is typically much shorter than a construction project.

Ned will review today our effort to ramp these investments from about $20 million in 2013 and ’14 to $27 million over the two years. We expect these projects to contribute at least $8 million annually to project adjusted EBITDA beginning in 2015 with about half that expected to be recognized this year. With respect to external growth we have been evaluating alternatives such as partnerships or joint venture structures that would raise capital more effectively for growth and/or further debt reduction and to bring value to the table with our expertise in project development and due diligence, our financial knowledge including tax equity, and our construction management and operations and maintenance experience.

Our goal would be to continue operating and to hold an ownership interest in the projects and perhaps be in a better position, along with our partner, to grow over time using that platform as a base. As we continue to access how best to position the company to maximize value for our shareholders, we’ll consider the relative merits of additional debt reduction, investment in growth opportunities both internal and external, and other potential allocation of our available cash. In this context we’ll evaluate a broad range of potential options including further selected asset sales or joint ventures to raise additional capital for growth and/or debt reduction, the dividend level, as well as broader strategic options.

Now, let me cover the highlights of the $600 million term loan and $210 million revolving credit facility that we closed earlier this week. As I mentioned before, we consider this a very successful outcome. We had looked at a number of options including individual financing at assets like Curtis Palmer and concluded that there were many benefits to this more comprehensive approach and that it took advantage of the current strength of the bank loan market. The transaction is beneficial in a number of key respects. First, it eliminates the majority of our debt maturities for the next three years. We have only a modest convert maturities this October which we respect to redeem with cash and then no maturities until March of 2017.


Second, it reduces our debt overtime through the 1% mandatory amortization and 2% cash sweep at Atlantic Power Partnership. In addition, we may reduce debt by another $150 million with excess proceeds from the transaction and cash on hand by taking steps to purchase or redeem up to $150 million of our 9% senior notes. Third, it increases our financial flexibility. The $210 million revolving credit facility has a 2018 maturity and provides us greater financial flexibility and additional liquidity relative to our previous $150 million facility that would have expired early next year. Fourth and finally, we accomplished all of this on attractive terms. The loan was significantly oversubscribed and the all in interest rate on the term loan was set at 4.75% all in as compared to weighted average interest rate of 5.9% on the $415 million of debt that we redeemed.

Turning now to 2014 guidance, we are expecting project adjusted EBITDA of $280 million to $305 million. At the midpoint this represents growth of 8% compared to 2013 results. Terry will address the key drivers of the increase. We expect free cash flow in 2014 in the range of neutral to $25 million. We define this as operating cash flow after capital expenditures including discretionary growth in optimization investments and after project debt repayments including the pay down of the new term loan through the mandatory amortization and sweep features.

This is comparable to our previous cash flow metric cash available for distribution but presented in a way that hopefully you find more useful. This guidance excludes the impact of significant fees and expenses associated with our refinancing transaction some of which will be recorded in interest expense in the first quarter of this year.

Our free cash flow guidance is after project debt repayment of approximately $27 million this year and an estimated partial year pay down of the term loan of approximately $52 million. The allocation of a significant amount of our operating cash flows to debt repayment, although helpful in accomplishing our goal of debt reduction, does put pressure on the availability of cash for other purposes including dividends.

Our free cash flow guidance is also after making $18 million of discretionary investments in a number of our projects that will produce strong cash returns beginning this year. We consider these investments to be a highly attractive use of our cash flow. Going forward we expect to analyze and compare the returns from all possible uses of our free cash flow and make decisions about investments, additional debt reduction, and dividends within that framework.

At this time let me turn it over to Ned.

Edward C. Hall, III

2013 was another year of strong operational performance. As you can see from Slide Seven, our availability factor of 95% was roughly level with the prior year. Our operational excellence across the portfolio offset the impact of the late start up at Peidmont. With the exception of Peidmont, all of our businesses met the requirements under their PPAs and earned their expected capacity payments in both the fourth quarter and for the full year and we have achieved these results while sustaining our commitment to an environmentally responsible and injury free workplace.

Generation volumes increased 43% for the year. The increases were driven primarily by the additional of our new businesses specifically, Canadian Hills and Meadow Creek in December 2012 and Piedmont which came online in April of 2013. For the year the operating performance of our wind businesses was favorable to budget primarily due to higher availability in wind flow in Canadian Hills and Goshen offset by lower wind at Meadow Creek.

Water levels for all of our hydro businesses were below normal in 2013 and we completed a major outage at Mamquam. The thermal businesses generally performed better than expected contributing the bulk of the company’s positive variance on both cash and EBITDA in 2013. At our Ontario businesses, waste heat levels were higher than expected and gas transportation costs lower than expected. In addition Manchief and Frederickson operated at higher capacity factors than expected.

As discussed on previous calls, our Piedmont business underperformed due to delays in achieving commercial operation. We continue to take steps to improve the operating performance. The delays in startup at the beginning of the year affected our ability to purchase fuel. We have had to source fuel from a wider range of suppliers than originally envisioned and at higher costs but are continuing our efforts to develop reliable sources of lower cost fuel. We’re also working on improving the efficiency of the plant focusing on optimizing the [boiler]. We reached agreement to assume responsibility for operation and maintenance of the plant which we expect should have a positive impact on the operating results.

Turning to Slide Eight, next I’d like to provide an update on our optimization initiatives. These are projects that we’ve identified to increase the cash flows from our existing assets and enhance the value of these businesses. On the third quarter call I indicated that we planned to invest approximately $20 million during 2013 and ’14 that would result in incremental EBITDA in 2015 of at least $6 million. The most significant of these investments is the Nipigon steam generator upgrade which is a total cost of approximately $11 million of which about $8 million is expected to be incurred this year. The project is on track with regard to budget and timing with a fall outage scheduled to complete the work.

Last year we completed repowering the Curtis Palmer unit four turbine and this year we are in the process of a similar repowering of the unit five turbine which again, is on track to be completed in the second quarter. Total cost for both units is approximately $5.6 million of which $1.6 million is expected to be spent this year. At our North Island business in California we accelerated into 2014 a major outage to increase the output of the plant in order to take advantage of an increase to the interconnection capacity recently approved by the California ISO. Once completed we can sell the additional output into the short run avoided cost market in California.

Since the third quarter conference call we have identified and expect to proceed with additional discretionary investments totaling $7 million including the $2.2 million investment to boost output at our Morris station. With this addition we now expect our optimization investments to total approximately $27 million with an expected project adjusted EBITDA run rate contribution of at least $8 million beginning in 2015. As Barry noted we expect to realize about half of that beginning in 2014 from projects already completed or those we expect to complete in the early part of this year.

We expect total major maintenance and capital expenditures this year to be on the order of $38 million including about $18 million of optimization related spending. This is less than last year’s $41 million despite a higher level of optimization investments because of the lower number of scheduled gas turbine outages in 2014. Going forward we expect major maintenance and cap ex to average about $25 million annual.

We have set a target to identify $5 million to $10 million annual of additional optimization investments. Our optimization investments are discretionary and the level of opportunity will vary from year-to-year and we will continue to prioritize those with the shortest paybacks.

Now, let me turn it over to Paul.

Paul H. Rapisarda

Let me start by providing a brief update on Delta-Person, the New Mexico project in which we have a 40% ownership interest. In December of 2012 together with our partners, we announced the sale of this project to Public Service of New Mexico. We have experienced some delays in the transfer of the permits required for the sale although we are still confident the transaction will go forward, the timing is now more likely to be in the second quarter of this year. Sale proceeds are still expected to be approximately $9 million to Atlantic.

Next, I’d like to provide a brief commercial update on Selkirk. As you all know we have a 17.7% interest in the facility for which the remaining PPA and steam contracts will be expiring at the end of August this year. Approximately 23% of the capacity from Selkirk is not contracted currently and has been sold at market prices or not sold at all if prices don’t support profitable operation. If we do not obtain a new PPA this could increase to 100%. The partners are still in ongoing discussion with the steam host regarding an extension of the existing agreement and we are also exploring all feasible options regarding the sale of power from the project.

Our Tunis project in Ontario has a PPA which expires at the end of this year. In December Ontario released its revised long term energy plan. Its focus is on increased conservation and demand side management along with the provinces ongoing nuclear refurbishment program to largely meet Ontario’s projected electricity needs. The plan did reiterate the government’s position that eligible [NUGs] such as Tunis will only obtain new contract if they can demonstrate cost and reliability benefits for its customers.

Although there have been no significant developments regarding our Tunis recontracting discussions the OPA recently indicated that in addition to one previously announced agreement, they now have three other [NUG] contracts out of the original group of six in documentation and thus consider themselves to achieve four quote unquote successful outcomes. We believe that this bodes well for an acceleration of our discussion and hope to provide more specifics on upcoming calls. I would also remind you that beyond Selkirk and Tunis the next of our PPAs to expire is not until year end 2017, both of which are in Ontario as well.

The Ontario market is quite challenging in the near term and we therefore expect a significant reduction in the contribution from Tunis after its PPA expires. We do however see the potential for an improvement in the supply/demand fundamentals for the province as a result of these nuclear refurbishments, some growth in demand, and other factors over the next several years which may be helpful to the recontracting outlook for our other Ontario projects.

Turning to another province in Canada where we have projects, in November BC Hydro submitted its integrated resource plan as required under The Clean Energy Act. Although there is substantial planning complexity around the scale and pace of LNG development in the province, BC Hydro did acknowledge the important role that the 81 operating IPP projects play in the overall system supply. In particular, BC Hydro recommended optimizing the current portfolio of IPP resources while maintain cost effective options for long term needs. We believe that our 60 megawatt Williams Lake biomass facility as a renewable fuel base load project is an important element in this plan.

Lastly, I’d like to briefly touch on the US production tax credits. This credit has been an important driver of new growth in new energy projects in the US including in our own wind portfolio. You may recall that the PCC expired at the end of 2012 but was extended to include those projects that were under construction or could show a significant level of commitment by year end 2013. Some of those projects will be seeking partners which should create opportunities for us as acquisitions or joint venture candidates along the lines as Barry discussed earlier. Although there is some speculation that additional incentives may be reintroduced in Congress later this year, there are no current plans to extend tax incentives to new wind projects. Our existing projects, all of which qualified under prior law are not affected by these uncertainties.

Now I’d like to turn it over to Terry.

Terrence Ronan

This morning I’ll expand a bit on Barry’s remarks on our recent refinancing and address the impacts on our debt balances and liquidity. Then I’ll review our financial results for the year as well as the guidance we initiated for 2014. I’ll also provide an update on our Piedmont financing. Turning first to the refinancing on Slide 11, as Barry indicated we were very pleased to have such a successful outcome. The $210 million senior secured revolving credit facility at APLP provides us with enhanced liquidity relative to the previous facility of $150 million which had a $25 million cap on borrowings and also required us to maintain a $75 million restricted cash reserve.

The new facility allows us to borrow at the APLP level up to $210 million less letters of credit outstanding and does not require us to maintain a cash reserve. Of course, our plan is to use this facility primarily for LCs but we have flexibility to draw at our option. The revolver does not mature until 2018 whereas the previous facility would have matured in March of next year. In addition, we’re not required to obtain approval for any asset sales other than Curtis Palmer, although proceeds from any asset sales at APLP must be applied to reduce the balance of the term loan.

We also have a group of eight banks in the revolver, up from the previous four and we view this as a positive change. Both the term loan and revolver have leverage and interest coverage ratio tests that require us to maintain a debt to EBITDA level of no more than 5.5 times and an interest coverage ratio of at least 2.5 times in 2014. Beginning in 2016 the required debt to EBITDA level under the covenant steps down over time and the interest coverage ratio steps up. Note that these are calculated at the APLP level rather than on a total company basis and we expect APLP to remain in compliance with these ratios for at least the next 12 months.

As you can see on the Slide, the refinancing significantly improved our maturity profile. We intend to redeem the $45 million convertible debt maturing in October using cash at which point we have no maturities until March 2017. Including the $600 million term loan, approximately half of our total debt is not amortizing debt. About three-quarters of the term loan is expected to be paid down by maturity in 2021 through a combination of the 1% annual mandatory amortization of principle plus the 50% sweep of APLP’s cash flows after its debt service. Amortization and the sweep will not only begin to reduce debt over time but will also drive a reduction in interest expense beginning next year.

We view this helpful to our debt reduction goals but we know we have more to do. We intend to redeem the $45 million converts in October as I mentioned and may, subject to market conditions, apply the remaining net proceeds from the refinancing transaction and some cash on hand to redeem or repurchase by means of a tender or otherwise up to $150 million of our 9% notes [inaudible] $27 million of project level debt this year, including a repayment of Piedmont construction debt which I’ll discuss next.

Turning to Slide 12, earlier this month we successfully converted our Piedmont construction debt to a $68.5 million term loan financing structured with 17 year amortization and maturing in August, 2018. The loan as a fixed all-in interest rate of 5.2% through February 2016. In order to facilitate term conversion, we paid down $8.1 million of construction debt and made a $6.1 million equity contribution to the project to fund various required reserves. As Ned indicated, we are expecting better operating performance and increased EBITDA from the project but we do not expect to receive any distributions in 2014. We now believe that distributions from Piedmont will average about $4 million to $6 million after 2014 down from the $6 million to $8 million we had expected prior to commercial operation.

Slide 13 summarizes year end 2013 debt and then walks through the changes that occurred as a result of the refinancing transaction. The pro forma figure reflects the term loan financing, Curtis Palmer and USGP redemptions and the repayment of Piedmont project debt. We’ve also shown a year end projected debt balance which also incorporates the redemptions of the convertible debentures in October, project level debt amortization of $19 million, amortization of the term loan estimated to be approximately $52 million on a partial year basis, and the potential to repurchase up to $150 million of other debt subject to market conditions. The net result would be about an $85 million reduction in consolidated debt by year end 2014 versus year end 2013.

Slide 14 provides adjustments to our year end 2013 cash and liquidity to reflect the impact of the refinancing transaction and the Piedmont conversion on a pro forma basis. Pro forma for these adjustments unrestricted cash will be about $325 million. Of this, we plan to use at least $45 million to redeem the convertible debentures in October and again, may use an additional $150 million for debt reduction this year subject to market conditions.

At year end, our posted LCs totaled $98 million. As of February 26, 2014 this had increased to $144 million reflecting net changes with various counterparties including mark-to-market adjustments, an increase associated with debt service reserve for the new term loan, a reduction associated with the Piedmont term loan conversion, and the resolution of discussions with an existing gas supplier that resulted in additional [inaudible]. All in capacity under the new revolver is thus $66 million currently up from $25 million at year end and total liquidity on a pro forma basis is about $391 million versus $184 million at year end.

We expect LCs to be reduced by $16 million, most likely in March as a result of agreements or actions that we are taking. Wrapping up our discussion of this transaction, I would note that the charges associated with the refinancing that we expect to record in the first quarter will result in us not being able to meet the fixed charge coverage ratio test under the restricted payments covenant in our high yield indenture. However, the ratio is calculated on a rolling four quarter basis so these charges will drop out of the calculation after the first reporting quarter of 2015. Interest expense savings from potential debt reduction would be rolled into the test in the quarter in which debt reduction occurs.

For as long as we are not in compliance with this test however, the restricted payment covenant limits the company’s ability to pay common dividends in the aggregate to the greater of $50 million or 2% of net assets which was $61 million as of December 31st. I want to emphasis however, that the restricted payment [inaudible] limitation is a minor factor among all the factors that were considered in evaluating the dividend level as the company analyzes a range of options going forward.

Slide 15 provides an overview of our financial results for the full year 2013. Project adjusted EBITDA of $270.5 million came in at the upper end of our initial guidance range at $250 million to $275 million and above the midpoint of our revised guidance of $260 million to $275 million. Cash available for distribution of $109 million was $9 million above the upper end of our guidance range. We had indicated on the third quarter call that our expectations and for several factors to reduce our cash available for distribution in the fourth quarter such as cash required for additional collateral posting or for injecting equity into Piedmont, these did not occur until the first quarter 2014. Cap ex in the fourth quarter was also slightly lower than we had expected.

Slide 16 provides a bridge of our project adjusted EBITDA from 2012 to 2013. Key drivers for the new project additions, particularly Canadian Hills and Meadow Creek as well as the consolidation of Rockland. I’d not that Slide 23 in the appendix provides a breakout of the more significant changes by project.

Before moving to our 2014 guidance I’d briefly mention that in 2013 we changed our geographic segments as the result of the sale of several projects last year. The current segments of east, west, and wind are more consistent with how the projects are being managed internally. Slide 32 in the appendix provides a mapping of the old geographic segments to the new.

Turning to Slide 17, it shows a bridge of our projected adjusted EBITDA from 2013 actual of $270.5 million to a range of $280 million to $305 million for 2014. Key drivers of the increase include full year of operations and improved performance at Piedmont, favorable changes to PPA and gas contracts at Orlando, expected increase from the company’s Meadow Creek and hydro projects due to assumed normal generation levels which would generally be better than the levels we experienced in 2013.

These positive factors are partly offset by the expiration of the Selkirk PPA in August and projected lower energy prices realized by the project for the full year and the sale or closure of three projects that contributed to our 2013 project adjusted EBITDA but will not contribute materially or at all in 2014. We’re also providing 2014 guidance for APLP project adjusted EBITDA in the range of $165 million to $175 million.

Turning to Slide 18, we’re initiating 2014 free cash flow guidance of $0 to $25 million defined as operating cash flow after capital expenditures and project debt repayment including amortization of the term loan and distributions to non-controlling interests. It is comparable to our previous metric cash available for distribution. Our guidance this year excludes the significant expenses that were or will be incurred associated with the refinancing transaction and any reduction of additional debt. It also includes the upfront debt repayment in conjunction with the term loan conversion at Piedmont.

The Slide provides the bridge from project adjusted EBITDA to cash flows from operating activities. Significant year-over-year changes include reduction in cash flow from assets divested in 2013 and benefits to working capital in 2013 that are not expected to recur in 2014, both of which are captioned in other [route]. Higher cash interest payments are attributable to the expenses I just mentioned. Excluding these expenses interest payments would be modestly lower.

I’d also note that although G&A expense is down approximately $3 million, we expect to achieve the $8 million of savings that we identified last year. The remaining savings are included in the project adjusted EBITDA line. Slide 20 in the appendix provides reconciliation of this. Walking from operating cash flow to free cash flow, the significant drivers of the lower result in 2014 are the amortization of the APLP term loan and higher cap ex this year associated primarily with the Nipigon steam generator upgrade and a couple of other optimization projects. Note that approximately three-quarters of our operating cash flow this year is being applied to repay debt primarily due to the refinancing of our near term maturities with the term loan and its sweep feature.

Now I’d like to turn the call back over to Barry.

Barry E. Welch

That concludes our prepared remarks and we’d now be pleased to answer any questions you may have.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Nelson NG – RBC Capital Markets.

Nelson NG – RBC Capital Markets

Just a quick question on the Ontario facilities, you mentioned that it benefitted from higher waste heat in Q4, for 2014 do you expect the results for the Ontario facilities to be much stronger due to the cold weather experienced to date?

Paul H. Rapisarda

I think in terms of expectations we took an average of the last several years from a budgeting point of view and not anticipating above average or I should say worse winter conditions.

Nelson NG – RBC Capital Markets

Okay, but in general the cold weather has been a net positive, right because of higher gas volumes?

Edward C. Hall, III

We have had some benefits not only in Ontario but our other projects, but unfortunately we’ve had some offsets as well. In Ontario specifically due to the cold we had condensers freeze up at one of our plants and we continue to have some operating challenges because of the extreme cold. So while we’re making more money we’re not as available as we expected to be and as a result it’s offset.

Nelson NG – RBC Capital Markets

Just on Ontario, can you provide any more commentary on the Tunis facility in terms of any expected timing on the recontracting or are you still in pretty early stages of negotiations?

Paul H. Rapisarda

I would still characterize it as fairly early stages. I think all I was trying to suggest in the earlier remarks is it does seem like the OPA is trying to move through the projects a little bit more expeditiously than they have over the last couple of years and so we would expect some resolution prior to the end of this year.

Nelson NG – RBC Capital Markets

Then just moving onto your balance sheet, it looks like you’ll have over $100 million of cash in your balance sheet after earmarking $200 million to debt reduction. What are you going to do with that cash? Are you looking to reinvest or are you kind of keeping a bit of a buffer for other purposes?

Terrence Ronan

Well right now the new credit facility is at the APLP level and we do have flexibility to borrow under the revolver down there. We don’t have the ability to upstream cash from that to the parent. I think in general we’ve talked about feeling comfortable with at least $50 million cash on the balance sheet to run operations. I would say that we’re still that or perhaps a little bit higher. We have some flexibility but nothing specific for that cash beyond using it for company purposes at this time.

Nelson NG – RBC Capital Markets

Then just one more question, in terms of the dividend and determining the right level of the dividend, can you talk a little bit about the process you’ll be taking? Are you effectively carrying out a full strategic review on your assets before determining the right dividend level?

Barry E. Welch

What I described earlier is a process where we’re basically looking at quite a lot of options across a broad spectrum including everything from selected asset sales, joint venture approaches, what we would do with excess cash in terms of options, debt reduction, potential growth opportunities, and including broader options so I would say a wide spectrum of options.

Nelson NG – RBC Capital Markets

Just one last question, what’s your budget for the development cost for 2014? I know that I think on Slide 20 it’s partly included in the $14 million of unallocated corporate costs, I was just wondering what the total development budget was?

Barry E. Welch

There’s a number appearing in a line that I think is eight, it includes some residual payments with respect to the Ridgeline acquisition so I’d say if you look at real – we don’t have it in there but if you look at actual money we’re spending on an ongoing basis for project development it’s more like $3 or $4.

Operator

Your next question comes from Rupert M. Mere – National Bank Financial.

Rupert M. Mere – National Bank Financial

On your strategic review process where are you in the process now? I understand you’ve had some other issues you’ve been taking care of but can you talk a little about how far along you are in the process, how long you think it could last and are you in any active discussions on asset sales or joint ventures right now?

Barry E. Welch

I don’t think we want to characterize where we are in the process, how long it’s going to take. We basically took a fair amount of energy in the organization to move through and close and fund the [CLB] and revolver. As you can imagine, we want to take a good hard look and a comprehensive one at what the options are and I don’t think it would be wise to sort of pin us into a timeframe.

Rupert M. Mere – National Bank Financial

Looking at your project adjusted EBITDA guidance for 2014, what range of outcomes have you assumed for Selkirk after the expiry of the PPA?

Paul H. Rapisarda

We mentioned two things that are happening. Obviously, we’ve been already operating and again, we have a minority interest it’s only about 17%, but the project has been operating already with 80 megawatts of its total output in the merchant market so what’s happening as of August with the other contract dropping off at the end of August so we have both the reduction of those contracted payments in the end of the year and we have a reduction in what we projected for the merchant prices across first the 80 megawatts already in the market and the additional output as well and we’re currently not assuming a new contract. We’re basically, from a planning point of view, just assuming that the projected prices in that zone of near [ISO] are what we would get when all the output is in the market.

Rupert M. Mere – National Bank Financial

Then just finally, it seems you are still carrying relatively material project development costs. Can you give us some color on what the activities are in the project development and do you anticipate a similar level of activity into 2014?

Edward C. Hall, III

Maybe to answer this it’s best to go back briefly to the summer where we announced we were cutting back the early stage development and effectively that created cost savings as part of the $8 million that we announced both in terms of some personnel reductions around development as well as the third-party development expenses. What shows up is basically about $8 million of which we’ve got maybe some amount around $3 million I mentioned sort of residual payments that were related to the Ridgeline transaction.

The remaining $5 we have in there from sort of a budget point of view, I’d say if I were making odds it’s possible that we might shave $2 out of there depending on the outcome, just some of that effort. But effectively the focus of that is at this point late stage development where we hopefully if it’s going to be meaningful given the business model right now for us it would have to be a short period of time before the project is moving into construction.

Operator

Your next question comes from Sean Steuart – TD Newcrest.

Sean Steuart – TD Newcrest

A few questions. I guess first on the basket provision as related to the high yield notes, does it apply to preferred dividends as well and I guess can they be restricted by that provision? Do the $13 million you have in annual pref dividends does that count against the basket that you have with that provision?

Terrence Ronan

No, the preferred dividends aren’t part of the basket. What was the second question again, I’m sorry?

Sean Steuart – TD Newcrest

The $13 million in annual preferred dividends, they wouldn’t count against the $61 million you have?

Terrence Ronan

That’s correct.

Sean Steuart – TD Newcrest

Then I guess based on your comments you’re expecting you’ll be back on side with fixed charge coverage ratio after a year? Maybe I’m missing reading that. Does calling a chunk of the high yield notes as part of your proposed capital allocation strategy, does that affect the compliance or non-compliance with that provision?

Terrence Ronan

There’s a couple of questions there, let me take the first one. I think we’re trying to tell you how the mechanics work and the reasoning behind us tripping the test now as the make whole payments that we had to pay in conjunction with the refinancing. We haven’t given any guidance about whether we’ll be in compliance within four quarters or not at this time. All we’ve said is that the portion that is in this quarter as a result of the make wholes would roll off in four quarters. With respect to any further debt repayments, if there were premiums associated with that or make wholes and it were not in this quarter, that would take an additional period of time to roll off. For example, if it were in the second quarter.

Then finally, I think I said during my part of the presentation that we’re not viewing that test as the driver. It is a factor among many factors, I would say a minor one, with respect to the dividend level going forward and what the outcome of any discussions about options we may have going forward with the board will result in.

Sean Steuart – TD Newcrest

On Piedmont, maybe just a little bit of context on I guess the revision to the long term project distributions you’re expecting out of that asset being reduced between $4 million and $6 million from $6 million to $8 million. What’s the context there of that revision?

Edward C. Hall, III

There are a couple of drivers. In the near term the biggest driver has been our fuel supply. As a result of the delay we had in startup we had started to build a wood supply and a supply chain in the area then we shut off for six months so a lot of people went into a situation where it was difficult and it’s taken us time to get that wood market back. We, as a result of that, paid significantly more for wood in this year and last year as well, then we expected to so we’re continuing to work to improve that and get some suppliers up and running that can lower our costs.

The other factor was the quality of the wood. The moisture content of the wood was higher than we originally expected which impacts our efficiency. So if you factor those two things in, and we don’t get the improvements that we originally thought we could get, that’s why we lowered the guidance. We’ll obviously work to get what we can out of the wood market. Then finally, looking forward in the longer term basis, the original expectations on what we would sell our renewable energy credits for has been reduced as a result of what’s gone on in that market.

Sean Steuart – TD Newcrest

Lastly for me, maybe you can give some context I guess as a means of augmenting your liquidity position, any assets outside the APLP structure that you might be focused on divesting, or at least starting that process towards looking at monetizing some of those assets?

Paul H. Rapisarda

I think if you look at what we’ve done over the last couple of years, we’ve articulated this notion of non-core assets and we certainly still have some assets that would fall into that bucket. Selkirk which we talked about as being one where it’s a minority position non-operated coming off contract. Then I think more broadly as Barry alluded to, as we look at this range of options for the company going we will certainly revisit all of the assets for either outright sales and use the proceeds for one of the options Barry discussed or in the context of potentially a joint venture structure.

Operator

Your next question comes from Matthew Akman – Scotia Capital.

Matthew Akman – Scotia Capital

The revolver at APLP I’m just wondering if there’s any way you could use those monies for any development activities?

Terrence Ronan

I think at the APLP level we would be able to draw on the revolver for general corporate purposes if we were to do development at the APLP level.

Matthew Akman – Scotia Capital

What would be the definition of that? Would that have to be a redevelopment, or repowering, or expansion of an existing asset within that or could that be a new asset somehow?

Terrence Ronan

I think it could be a new asset as well as it was within the APLP umbrella and we provided security to the new lenders on that new asset.

Matthew Akman – Scotia Capital

Moving to Piedmont can you just reconcile the projected increase or guidance increase of $10 million for 2014 in project adjusted EBITDA versus the $4 million to $6 million of contribution after 2014? Are those numbers equivalent or is there a wedge between the $10 million and $4 million to $6 million in terms of capital or something like that?

Terrence Ronan

Yes, I mean we feel confident that the plant will be running more as it will be on a go forward basis. We’ll have a full year of operations this year. We won’t have any distributions this year because of reasons we’ve previously gone through regarding reserves but there is debt amortization going forward. We’re working on the fuel expenses.

Edward C. Hall, III

Probably the biggest impact is the full year of operation and a higher availability. We’ve assumed the unit is capable at running at higher availabilities and we won’t have the startup expenses we’ve had in 2013 repeating in this year.

Matthew Akman – Scotia Capital

Maybe I’ll just ask my question in a more simple way, I guess if the $4 to $6 comes true after 2014 would that imply $10 million or higher than $10 million in increase in projected adjusted EBITDA or lower?

Edward C. Hall, III

The project adjusted EBITDA will be in that $10 million range going forward and that is down from original expectations as a result of the factors I mentioned in the previous question. The $13 to $14 is driven by the factors we talked about and the $10 I think is a good number going forward.

Matthew Akman – Scotia Capital

My last question is, and I don’t know if this is fair ball or anything, but I know you guys have the debt to EBITDA covenants in APLP. I’m just wondering at the overall entity if you’ve given any thought to targets there? Your 2014 guidance suggests kind of seven to eight times debt to EBITDA I think. Is there a target there?

Terrence Ronan

Well we haven’t established a specific target Matthew. I think what we’ve talked about is that one of our priorities is debt reduction over time. We think that the new credit facility helps us do that, gave us a runway until 2017 without any maturities but we don’t have a target at the top of the house other than reducing leverage or debt overtime.

Barry E. Welch

Certainly in the slides you’ll see that on the term loan side we’re looking at three-quarters of that getting amortized over until its maturity so I’d say 450 there. In the back of the slides we’ve also issued [skips in audio] in the overall complex.

Operator

Your next question comes from Ben Pham – BMO Capital Markets.

Ben Pham – BMO Capital Markets

Most of my questions have been hit, just a follow up on the Piedmont. Obviously, you’ve been quite transparent on the cash flow movement there overtime but I was just curious what would you do differently from this development standpoint or even operationally with an acquisition just really stress testing your assumptions going into it? Just really what is the lesson on approach you would take going forward?

Barry E. Welch

First of all, at this point from a business model point of view, the length of construction period for a solid fuel project being two years or sometimes in this case two years plus, is no longer appropriate. It’s a long construction period for us in terms of getting to cash flow. Specifically, in this case I think that we have learned some things about how to do engineering and design work up front with respect to the [inaudible] procurement and construction contract and how to tie that together better that we would certainly do differently on a go forward basis. As Ned mentioned, simply the fact that we interrupted the fuel supply which is a critical dynamic for these kinds of solid fuel projects for a six month period and had to reset it, that by itself is something that you certainly wouldn’t repeat if you had a smoother startup. I don’t know if anybody else has any other thoughts?

Paul H. Rapisarda

I think the only thing I would add to that is as you know it’s one of four biomass plants we have in the portfolio. The three up and operating were seasoned plants, have performed extremely well and so we’re very comfortable with the space. I think as Barry said, the lessons learned that really apply to the development and construction side and I think we have a better team going forward if we chose to look at another development opportunity.

Ben Pham – BMO Capital Markets

Lastly, just on Orlando the benefit in ’14 can you clarify have you guys exactly locked in that benefit for this year and how does that look in ’15 in terms of the hedges there?

Edward C. Hall, III

As part of this refinancing we did have to unwind some hedges with banks that were not going to be participating in the new transaction. But it is our intent to look at those, putting new hedges on and doing so relatively soon so we can probably update you on that down the road. But it is our intent to lock in some of those prices at Orlando to take advantage of what we see as good prices.

Terrence Ronan

The other comment I’d make on the market is while the weather has clearly bumped up the front end of the curve for gas, if you look at the back years two and three out, as you hoped there hasn’t been much of an impact upwards based on the weather blip on the front.

Edward C. Hall, III

The last thing in terms of locking in, remember a good portion of this is we had a contract with [Redicreek] that expired at the end of the year and it’s moving over to Progress Energy so that portion is absolutely locked in.

Operator

Your next question comes from Jeremy Rosenfield – Desjardins Securities.

Jeremy Rosenfield – Desjardins Securities

Just on the [drift], can you just remind us where the participation rate is at the moment?

Terrence Ronan

It’s about 5%.

Jeremy Rosenfield – Desjardins Securities

In terms of cash flow hedges for foreign exchange on the dividend payments and on convertible debt instrument payments, can you remind us where the current level is?

Terrence Ronan

As I discussed on the last question we did have some banks that did not participate in the new facility that resulted in the unwind of some natural gas hedges and the same is true on the interest rate and the foreign exchange side. On the foreign exchange side we don’t have anything hedged right now but we are certainly looking at that and it is something that we will put in place relatively soon. On the interest rate side, currently the $600 term loan is unhedged. It does have a LIBOR floor of 1%. We do have a requirement to hedge a portion of that, a minimum of $200 million within 90 days. It is certainly our intent to do that and likely more than that so I think that we’ll be at a comfortable position that we can tell you about not too far down the road.

Barry E. Welch

One other comment on fx, what we’re seeing in the forward market is not very dissimilar to the average hedge price that we had that was unwound and on the interest rate side with respect to the term loan facility there’s a LIBOR floor in there of 1% and so LIBOR itself is of course significantly under that and even if we didn’t execute hedges there’s significant headroom before we hit the floor and would see any impact.

Jeremy Rosenfield – Desjardins Securities

Does the revolving portion of the new facility have a feature where you can term out some of that for a longer period of time?

Barry E. Welch

It does not.

Jeremy Rosenfield – Desjardins Securities

The only other question I had is if you’ve had any conversations with rating agencies as to their views of the cash flow profile and what it would take to have improvements in the ratings?

Barry E. Welch

Well we’ve met with both the rating agencies in conjunction with the transaction we just completed and got rated. Nothing specific beyond what we talk about on these calls which is the status of recontracting and what that means for cash flow going forward so we’ll continue to update the agencies as we move along just as we do you.

Operator

This concludes our question and answer session. I would like to turn the conference back over to Barry Welch for any closing remarks.

Barry E. Welch

Thanks very much everyone for your time and attention on the call this morning.

Operator

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

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