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Atlantic Power Corporation (NYSE:AT)

Q2 2014 Earnings Conference Call

August 8, 2014 8:30 AM ET

Executives

Amanda Wagemaker – IR

Barry Welch – President and CEO

Ned Hall – EVP and COO

Paul Rapisarda – EVP, Commercial Development

Terrence Ronan – EVP and CFO

Analysts

Nelson Ng – RBC Capital Markets

Matthew Farwell – Imperial Capital

Sean Steuart – TD Newcrest

Operator

Good morning and welcome to the Atlantic Power Corporation Second Quarter 2014 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’d now like to turn the conference over to Amanda Wagemaker, Investor Relations Associate at Atlantic Power Corporation. 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 three months.

Our results for the three and six months ended June 30, 2014 were issued by press release yesterday afternoon and are available on our website and on EDGAR and SEDAR. Financial figures that we’ll be presenting are stated in U.S. dollars unless otherwise noted. All amounts or percentages unless otherwise noted are approximate.

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 the press release and quarterly report on Form 10-Q, 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 relevant 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 Welch

Good morning. I’d like to extend my thanks as well to all of you for joining us today. I’ll briefly review our financial results for the quarter and year-to-date and then turn things over to Ned to discuss our operational performance and to provide an update on our asset optimization initiatives. Paul will then provide an update on a few of our projects followed by Terry who will review our results in more detail and provide an update on other financial matters.

Turning to a review of our Q2 results on slide four, project adjusted EBITDA increased $19 million or 34% to $75 million. There are a number of positive factors this quarter which drove the increase. The first of these was that we had fewer maintenance outages than in the second quarter of last year which benefited output as well as reduced our maintenance expense.

Second as Ned will discuss in greater detail wind, water and waste heat were above expectations this quarter which benefited our Idaho wind projects, Curtis Palmer and our Ontario projects. Third, we had a full quarter of Piedmont operation this year versus a partial quarter the previous year. Fourth, our Orlando project benefited from lower gas cost after unwinding above market hedges which Terry will discuss further and also from higher capacity revenues under new PPA.

Through the first-half of this year we have earned a $150 million of project adjusted EBITDA and our expectations for the second-half put us on track to achieve our guidance of $280 million to $305 million. Free cash flow reported for the second quarter was negative $15 million although cash flow from operating activity has increased $27 million this was more than offset by our first repayment of APLP Term Loan Debt totaling $37.5 million, which had a significant but anticipated impact on free cash flow. This debt repayment puts us on track to reduce total project and corporate debt this year by approximately $80 million on net basis.

Year-to-date free cash flow as reported was a negative $61 million which includes the term loan repayment as well as approximately $57.5 million of cost incurred in the first quarter associated with our refinancing transactions. We expect the free cash flow generation will be positive in the second-half of this year and Terry will discuss the drivers of that. Our free cash flow guidance for the year of zero to $25 million excluded the refinancing transaction cost and we still expect to be in that range.

Lastly, as we announced earlier this year together with our board we are continuing to evaluate our broad range of potential options to best position the company to maximize value for shareholders, including a possible sale or merger of the company. As previously announce we do not intend to comment further on this evaluation of potential options until we determine if further disclosure is appropriate or required.

Now I’ll turn it over to Ned.

Ned Hall

Thank you, Barry, and good morning. Turning to slide five. I am pleased to report that we had strong operations results during the second quarter and we achieved these results while sustaining our commitment to an environmentally responsible and injury free workplace. We benefited from better than expected waste heat, wind and water volumes, which increased contributions by our Ontario projects, all of our wind businesses and Curtis Palmer.

As background in Ontario all of our projects are situated along the TransCanada Pipeline. We capture the waste heat from the pipeline compressors and use that instead of Natural Gas or wood to generate steam to run our steam turbine generators. This is a cost savings for us that increases our operating margin. In the second quarter the amount of waste heat generated was above expectations, largely because of the cold winter and the refilling of gas storage. Our Idaho wind project had a 10% increase in output this quarter compared to last year continuing the strong first quarter performance. Although wind conditions in Idaho were below average in 2013 they have been above average so far in 2014. Canadian Hills at a 4% increase in generation in the quarter where we had most of the shortfall that it experienced due to its January outage. Curtis Palmer benefited this quarter from a delayed snow melt and above average rainfall resulting in generation volume increase of 24% from the year ago period.

Generation across our portfolio increased 0.7% for the quarter driven by Curtis Palmer of fourth quarter of Piedmont fewer force outage hours at Williams Lake and strong wind conditions at Meadow Creek and Rockland which were partially offset by reduce dispatch at Manchief and Selkirk and schedule maintenance outage in Cadillac, Orlando and Naval Station.

Our availability factor was 91% this quarter compared to 93% a year ago mostly because of the extended scheduled maintenance outages in Cadillac, Orlando and Naval Station which were partially offset by improved availability at Mamquam, Moresby Lake, and Williams Lake. In addition we had fewer major gas project outages this quarter than a year ago.

Turning to slide six, for the first six months of this year our availability factor was 92% versus 94% in the same period last year. Because of the lower availability we did not receive 4.7 million of capacity payments at our Ontario projects, Piedmont and Cadillac that we would have expected to earn had these projects operated at their budgeted availability levels. The majority of this relates to our Ontario projects with the remainder attributable to Piedmont and Cadillac.

From an overall standpoint, we were able to offset this short fall with the additional revenues from waste heat, wind and water during the second quarter as well as improved availability from Piedmont which allow the project to earn 100% of its capacity revenues for the quarter. However, in July we experienced a failure of Piedmont and the connection between the generator and the transformer due to improper installation. This resulted in a 12 day forced outage. The repairs are complete the unit is back in service and a warranty claim has been filed but we do not expect Piedmont to earn all of its capacity revenues this quarter.

With regard to the dispute with Zachry, the EPC contractor for Piedmont. The despite resolution part of the arbitration process which includes that discovery in depositions is continuing. Depositions are almost completed and following that we would expect each side to review the situation. Mediation is scheduled for the last week in August. If no settlement is reached at that time formal arbitration hearings will begin in October.

Turning to slide seven, next I’d like to provide an update on our major maintenance budget as well as our optimization initiatives. Last quarter, we indicated that we expected major maintenance expenditures to total approximately $38 to $43 million this year but we now expect to be slightly lower in the range of $35 million to $40 million. The reduction is mostly attributable to two items; an insurance recovery at Piedmont which we have netted against expenditures made earlier at the project and deferrals of some planned 2014 expenditures into 2015 at another project.

Our capital expenditures this year are more heavily weighted towards the second-half primarily because of the Nipigon steam generator replacement and upgrade which is our largest CapEx project this year with an estimated total cost of approximately $11 million.

We expect to begin the outage later this month and complete it this fall before the winter peak season. When completed the new steam generator will give us the ability to generate additionally energy from the project. Our PPA at Nipigon runs through 2022.

Turning to slide eight, the Nipigon project is one of several optimization initiatives that we have underway this year. These are investments we have identified that will increase the cash flows and enhance the value of our existing projects. We are on track to invest approximately $17 million this year for a two year total of approximately $27 million and we expect incremental cash flow from these investments of at least $8 million annually on our run rate basis beginning in 2015 half of which we expect to realize this year.

Another project currently underway is the $2 million investment to boost generation at our Morris project during periods of high temperature. The equipment has been installed and performance testing is currently underway. In July we executed and inter-connection agreement with PJM at our Kenilworth project in New Jersey. This allows us to sell up to 9.9 megawatts of capacity, energy and ancillary services into the PJM market. Our first priority is to meet the steam requirements and electric energy demands of our customer, Merck which is in the process of expanding its facilities. So the amount of energy available to sell in the PJM will vary with Merck’s demand. Although it’s not possible at this time to quantify the potential benefit to us we view this as another good example of extracting value from our existing assets by executing a low cost option with a goal of increasing our revenues.

Now I’ll turn the call over to Paul.

Paul Rapisarda

Thank you Ned and good morning, everyone. First, I’d like to mention that we did close the sale of Delta-Person to public service in New Mexico in July and have received $7.2 million in proceeds for our 40% interest. We expect to receive another $1.4 million currently held in escrow 12 months post-closing. As we have discussed on recently quarterly calls we have two projects for which the PPAs will be expiring this year, Selkirk in New York in which we have an 18% ownership interest and our Tunis project in Ontario.

The Selkirk PPA and steam contracts will be expiring at the end of this month. The project has recently reached a preliminary agreement on a 20 year extension of the steam and site lease agreements with our current steam house, SABIC. We expect that the agreement will be finalized by year end. This agreement is intended give us the flexibility to operate the plant in response to market conditions by better aligning our requirements to provide steam to SABIC with our ability to capture positive margin in the electricity market.

Together with our partners we continue to explore all feasible options for the sale of the power. Although we have received indications from a number of counter parties regarding tolling agreements, capacity hedges and other forward sales these were not at a level at which the partners believe that would make sense to contract at this time. The plan for the near-term at least is to operate the project on a fully merchant basis. As you know 80 megawatts or about one quarter of the project’s capacity has been operating on a merchant basis for some time. So this is not new to us or our partners.

Also as we previously indicated we expect significantly lower project adjusted EBITDA and cash flow from Selkirk following the expiration of the PPA. Last year’s project adjusted EBITDA contribution of approximately $21 million was at the high end of what the project has achieved so the decline that we expect this year of approximately $9 million does not only relate to the four month impact from the expiration of PPA but also reflects lower realized prices for the capacity that is already merchant as well as the comparison against a very strong 2013.

Turning briefly to our Tunis project, it has a PPA that expires at the end of this year. Discussions with the Ontario power authority are continuing. Although the outcome of the recent provincial election is not expected to result in any change in energy policy in the province the merger of the OPA and the independent electricity system operator called for in the recently passed budget could further slow re-contracting negotiations. Once again we expect that a new contract if one were to be obtained would be on less favorable terms an result in significantly lower project adjusted EBITDA and cash flow from Tunis once the existing PPA expires.

Now I’d like to turn the call over to Terry.

Terrence Ronan

Thank you, Paul and good morning. First, I’ll review our financial results for the second quarter and year-to-date and then provide an update on our 2014 guidance. I’ll review also changes to our debt liquidity positions during the quarter and then close by addressing a few discussed in our 10-Q.

For the quarter our project adjusted EBITDA increased $19 million or 34%. Slide 11 provides a bridge from the second quarter 2013 level of $56 million to the second quarter 2014 results of $75 million. As Barry and Ned have already discussed fewer major outages, higher waste heat in Ontario, strong winds at our Idaho projects and a full quarter of Piedmont operation were the primary drivers of the increase in project-adjusted EBITDA for the quarter.

Slide 12 provides a bridge from year-to-date June 2013, to year-to-date June 2014. Year-to-date project adjusted EBITDA increased $13.5 million to $149.6 million with the second quarter increase of $19 million more than offsetting decline in the first quarter. The increase was driven primarily by the factors that I previously discussed affecting the second quarter which were partially offset by the unusual number of forced outages in the first quarter some of which were caused by extreme weather. Lower G&A and development expenses were also positive factor in the six month comparisons.

Turning to slide 13, I’ll discuss free cash flow results for the second quarter. As a reminder free cash flow is after project debt repayment, a cash flow sweep under the APLP term loan capital expenditures distributions to non-controlling interests such as the tax equity investors at Canadian Hills and preferred dividends.

It is also after the significant transaction related cost that we incurred in the first quarter related to our refinancing and debt repurchase transactions totaling $49 million as well as an $8 million pay down of Piedmont debt that we made to facilitate term conversion in February. Together these transaction costs totaled $57.5 million.

Reported free cash flow results for the second quarter were negative $15 million which was a decline of approximately $8 million from the year ago period. Although cash flows from operating activities increased $27 million this increase was more than offset by the initial repayment on the term loan totaling $37.5 million. I’ll discuss the term loan amortization a bit more when I review our guidance for the year.

Turning to slide 14, reported free cash flow for the year to-date decreased by a $136 million to negative $61 million. The reduction was driven by a decrease in operating cash flow which we have detailed on the slide under the term loan repayment of the second quarter.

Reported free cash flow result of negative $61 million includes the approximate $57.5 million of first quarter transaction cost that I mentioned earlier. Adjusting the numbers to exclude these costs, consistent with how we have presented our guidance for full year we’ll put the results at negative $3.5 million for year-to-date.

Turning to our 2014 guidance we are reaffirming both our project-adjusted EBITDA and free cash flow guidance. Slide 15 provides a bridge of our 2013 project adjusted EBITDA of $269 million to our 2014 guidance of $280 million to $305 million. As we have discussed our second quarter results including the benefit of stronger wind, greater water volumes and higher waste heat have largely offset the impact of the unplanned outages and other factors that affected our first quarter results.

Relative to how we presented this bridge in our first quarter call we now expect Piedmont to make a more modest contribution to project-adjusted EBITDA primarily due to the outages that the project experienced in the first quarter and July of this year and the impact that has had on the capacity payment that the project has received.

This negative impact has been offset by stronger results from our wind projects as well as a reduction in development and G&A expenses relative to our previous expectation. These cost savings have been mostly in the area of development and staffing cost. I would emphasize however, that we are no assuming a continuation of the above trend results from wind, water or waste heat for the balance of the year.

Slide 16 provides a bridge from our project adjusted EBITDA guidance to our free cash flow guidance. Expected cash interest payment of $165 million to $170 million include the $49 million of refinancing transaction cost previously discussed. Excluding these cost cash interest payment should be modestly lower than last year and we expect to see a reduction in the cash interest expenses quarter-over-quarter beginning in the second-half of this year.

We expect cash savings for the refinancing and repurchase transactions of approximately $7 million in 2015 and that should grow over time as the term loan is amortized. The expected repayment of the convertibles at their maturity in October this year with cash is expected to result in another approximate $2.7 million of savings in 2015.

Walking from operating cash flow to free cash flow the most significant deductions are maintenance and optimization CapEx of $16 million, which is higher in past years due mostly to the Nipigon steam generator replacement and upgrade. Project debt repayment of $26 million, which includes the $8 million of principal repayment at Piedmont in the first quarter and repayment of the APLP term loan, which we expect will be in the range of $52 million to $55 million for the year requiring an additional $15 million to $17 million to be repaid in the second half.

The term loan repayment in the first half of $37.5 million was 70% of the expected full year amount for few reasons. First, timing of APLP cash flows, which are typically stronger in the winter and spring months at the Ontario project in Curtis Palmer although some of this will be collected in the early part of the second-half. Second, timing of APLP capital expenditures, the majority of which are expected to be incurred in the second-half of the year due to the timing of the Nipigon project.

As a reminder the calculation of cash flow for the sweep is after CapEx requirement at APLP including Nipigon. So this would be expected to reduce cash flow and therefore the amount available for the sweep. The third, 37.5 margins included cash build-up during a four months stop period from transaction closing on February 26, rather than a more typical three months cash flow. Putting all these factors our reported free cash flow is expected to be negative this year. However, our guidance has always excluded the $57.5 million of transaction cost and on that basis we still expect 2014 free cash flow in the range of zero to $25 million. Considering that we are at negative $3.5 million for the first six months this guidance implies an expectation of positive free cash flow generation in the second half of the year.

The drivers of the expected improvement are timing and project distributions from our minority owned projects, not at APLP which we expect will be higher in the second half of the year due to timing of deferrals at a couple of projects, lower cash interest payment at the parent and working capital changes due to seasonality and timing of revenue collection. In addition, free cash flow should benefit from lower term loan repayment in the second-half.

Slide 17, summarizes the changes to our outstanding debt from year-end 2013 through June 30 2014 and projected changes that the company expects to occur in the second-half of 2014. Debt repayments in the second quarter totaled $42 million, primarily $34.5 million on the APLP term loan. The year-end projected debt balance incorporates the expected payment with cash of $41 million of convertible debentures that mature in October, reduction in the project level debt of $17 million including the project debt at Delta-Person which was sold in July and the amortization of the term loan. The net result would be an approximate $80 million net reduction in total debt by year-end 2014 versus year-end 2013.

Slide 18 provides an update on our liquidity which increased by approximately $15 million to $261 million as of June 30, 2014 from $246 million at March 31, 2014. The primary reason for the increase was a $37 million reduction in letters of credit outstanding, offset by a $22 million reduction in unrestricted cash which was attributable to debt repayment and other issues, other uses of cash during the quarter. We have detailed the components of the LC reduction on slide 18.

On slide 19, there are few developments discussed in our second quarter 10-Q that I’d like to note. First, we had a $14.8 million non-cash impairment charge at our Tunis project that was triggered by its upcoming PPA expiration at the end of the year. Our accounting policy is to preview our projects with potential impairments six months prior to expiration of the PPA. This impairment was based on a probability weighted range of possible outcomes following expiration of the PPA.

Second, during our third quarter we also plan to conduct an impairment analysis of our goodwill which was $291 million as of June 30. This impairment analysis was trigged by the continued deposit of our market cap relative to book value of our equity. Third, as I have mentioned previously the company is not in compliance with the fixed charge coverage ratio test, included in the restricted payment covenant of the 9% senior unsecured notes. As long as we are not in compliance with this test the restricted payment covenant limits our 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 June 30.

We have declared seven monthly dividends in January through July totaling approximately $25.6 million that are subject to this basket provision. Although the basket is certainly a constraint it is not the driving factor with respect to any decision on the dividend level. Dividends declared and paid at discretion of our Board of Directors. Separately I would note that we expect to remain in compliance with financial maintenance covenants governing our senior notes, the APLP credit facilities, including the term loan and the APLP medium term notes for at least the next 12 months.

Fourth, Piedmont is not compliance with its debt service coverage ratio, which went into effect after term conversion in February due to outages experienced in the earlier part of this year that reduced expected capacity payments. We do not expect the project to pass that service coverage ratio test for at least the next 12 months and thus we do not expect the project will make any distributions for at least 12 months. This is a change from our previous expectation that there would no distributions through 2014.

Finally, as disclosed in our 10-Q we put several new gas hedges in place at Orlando as well as our Ontario projects. As you may remember at the time we executed our new senior credit facilities in February we were required to terminate the existing gas hedges for 2014 through 2017 at Orlando project. These were above market hedges and we incur a $4 million cost to terminate them which was recorded in the first quarter. We are now a 100% hedged on peak through 2016 versus approximately 28% hedged at the time of our first quarter call at prices lower then under the previous hedges. Although we project that we will not offset the termination cost in 2014 we expect to recover a portion of the cost in the 2014 through 2016 time period.

In Ontario we signed additional gas purchase agreements for North Bay, Kapuskasing and Nipigon. Our un-contracted forecasted fuel requirements are approximately 98% covered through 2015. Our PPAs for these projects are based on a fixed energy price and so we wanted to remove uncertainty and reduce volatility around the cost of gas for the un-contracted portion of our gas needs.

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

Barry Welch

Thanks, Terry. That concludes our prepared remarks and we are now pleased to answer any questions you may have.

Question-and-Answer Session

Operator

We will now begin the question-and-answer session (Operator Instructions). The first question comes from Nelson Ng with RBC Capital Markets. Please go ahead

Nelson Ng – RBC Capital Markets

Great, thanks. Good morning, everyone.

Barry Welch

Good morning, Nelson.

Nelson Ng – RBC Capital Markets

Just a quick on Piedmont. So after experiencing a few outages this year is that your view now that the facility is finally operating smoothly or do you expect any do you expect any potential hick-ups over the next six months?

Ned Hall

Hi, Nelson it’s Ned. I wish I had a very firm answer to that but at this point given the failure we had in July which was very unexpected and due to installation quality I am uncomfortable saying I am a 100% confident. I would also point out thought as a solid fuel plant it’s 15 months into operation. It’s not unusual to have a shake-out period over a year or so. So I think and there is nothing that I see that won’t allow us to get the equipment ultimately to a point where we will be able to meet its commitments in the PPA but the July outage was not expected.

Nelson Ng – RBC Capital Markets

Okay, got it and then just on – just following on Piedmont so, given that the cash is effectively locked-up in the project for at least the next 12 months. Do you plan to use that cash to accelerate the debt repayment or will you just wait and receive lump sum distribution sometime next year?

Ned Hall

Well Nelson there is a couple of things in play that we have a requirement for a couple of reserves, one related to some litigation that we have disclosed previously with Zachry regarding the construction of project. So that cash would remain in there, in a reserve account until such time as we pass the test.

Nelson Ng – RBC Capital Markets

Okay, that makes sense. And then just moving on to G&A cost, the run rate for the first-half of the year is a little higher than your forecast for the entire year. Are the costs in second-half expected to be a bit lower than the first-half or is it just the strategic review that’s keeping the cost a little higher than normal?

Terrence Ronan

Well I am not sure where you are coming up with our cost being higher than expected I think we had talked about a $8 million year-over-year reduction.

Nelson Ng – RBC Capital Markets

So year-to-date was about $18 million and I think the guidance for the year was $33 million. So, if you simply just double the $18 million you get about $36 million. So I was just wondering whether the run rate for the first-half is a little higher due to any – whether it’s the refinancing or the strategic review?

Terrence Ronan

Yeah, I think if you look at 17.5 and you simply doubled it, it’s not really much difference from the $33 million we said we are going to have right now. I’d say on a year-over-year basis you’ve definitely, I am going to say more than the $8 million that we disclosed to you as a savings target last year. We are ahead of that by several million dollars. So yeah so, I think…

Nelson Ng – RBC Capital Markets

Okay. That’s fine. And then just have one last question. In the 10-Q I had mention the U.S. shareholder class action lawsuit, you mentioned that you filed a motion to dismiss the action just a few days ago. I was just wondering whether there is scheduled date where the motion will be reviewed and a decision made in terms of the action and I presume is sometime in the fourth quarter a fair estimate or not?

Barry Welch

Hi, Nelson it’s Barry. We had – there is schedule which sometimes can change and whatever we put into the Q is all that we can say at this point on that.

Nelson Ng – RBC Capital Markets

Okay, all right. Thanks, those are all my questions.

Ned Hall

Thanks.

Barry Welch

Thank you.

Operator

The next question comes from Matt Farwell of Imperial. Please go ahead.

Matthew Farwell – Imperial Capital

Hey, good morning.

Barry Welch

Good morning Matt.

Matthew Farwell – Imperial Capital

A question on the capital structure the 2019 notes there is some commentary about the restrictive covenants, obviously it’s a high coupon. Do you have a feel for what your cost of capital is at the HoldCo on a guaranteed basis and whether in that note could be reasonably financed when it becomes callable. This – in the fourth quarter, seems like there is a couple of million dollars of potential interest savings there can offset some of the other declining cash flows there at some of the projects.

Terrence Ronan

So, Matt I think you are talking about the 2018 high yield notes.

Matthew Farwell – Imperial Capital

Sorry about 2018, 9% notes, sorry about that.

Terrence Ronan

Yes okay. As we have talked about in the past debt reduction is a high priority for us and we have done some of that this year already at that high yield note. It is a high priority and we are going continue to reduce debt through the covert pay back in October and the sweep. The high yield is obviously our high, is coupon debt and we are well aware that the first call in November. But as you know we are looking at a broad array of options to try and increase shareholder value including the possibility of debt reduction but no decision has been made on that at this time.

Matthew Farwell – Imperial Capital

Okay and you mentioned that free cash flow is going is going to improve in the second half. I am a little confused because are you saying that a part of that will happen through reduced amortization at APLP. Is that, are you implying that weighing of EBITDA will be more heavily towards the projects that are outside of APLP is that how is, that the mechanism there?

Terrence Ronan

Well I think the main driver for the second-half is the timing differences that I talked about earlier on the call related to or equity project distributions which are outside of APLP specifically Chambers due to the refinancing we did there and the timing of distributions we will get and then also Selkirk had a delay in distribution there that we will receive in the second-half. That’s the primary driver of the increase. Secondly, I mentioned the lower interest expenses at the parent level which is also not part of the sweep. And then I think thirdly, we talked about some working capital changes and with respect to the sweep it’s really formulaic in that if we have a greater CapEx spend in the second-half of the year that reduces cash available for the sweep, 50% goes to the sweep, 50% goes to us. So we are picking up you know $0.50 on every dollar basically there but I would emphasize the main driver is the timing differences on the equity project distributions.

Matthew Farwell – Imperial Capital

Okay. On the SG&A topic what’s that to be taken this year or what’s estimate you continue to take to lower the administrative expenses?

Terrence Ronan

Matt the original program we laid out, I guess we last summer talk about $8 million on a run rate and that’s what we referenced earlier. And we have been able to look at that and we think we will be at a better run rate than that by a couple of million dollars and we are continuing to look. We will be at about $12 million run rate versus the $8 that we originally had looked for and we are continuing to look at other things that we could do to continue to chip away. Slide 28 by the way gives you some detail on that.

Matthew Farwell – Imperial Capital

Some more detail on that, okay. And on the Piedmont discussion what is – how should we be thinking about pro forma EBITDA once that project begins to generate cash flows?

Terrence Ronan

Well on a steady basis, at least from a cash distribution basis we have talked about $4 million to $6 million for cash distributions, $12 million to $16 million for project adjusted EBITDA from the project. As I said we don’t expect to make any distributions for at least 12 months but on a long run normalized basis I think those look like the numbers and that group is working hard to keep this running more consistently with a goal towards earnings a 100% of our capacity payments but those are the numbers.

Barry Welch

And the other I would say is just qualitatively it’s taking longer than we would have expected to get those kind of run rate number. So those aren’t numbers that we are expecting in ‘14 or ‘15.

Matthew Farwell – Imperial Capital

Got it. So if we were to take a step back and look at ‘15 versus ‘14 obviously Tunis and Selkirk will be a change I guess Piedmont is sort of non-existent in ‘14 so, not much change there. Are there obviously you are talking about the wind and the gas flows and hydro, any other changes that we should be thinking about from ‘14 to ‘15, just based on what you know about the projects?

Terrence Ronan

Sure. I think in general our CapEx this year because of the Nipigon spend is going to be higher than it generally is. So we would anticipate that CapEx should be lower next year and then also some of the lower interest expenses that I talked about earlier in the call would be kicking in and also I think we are estimating $9.5 million to $10 million next year in lower interest expense.

Matthew Farwell – Imperial Capital

Okay. So nothing else on any of the individual projects that you can pick-up?

Barry Welch

We haven’t provided any disclosure yet for 2015 Matt.

Matthew Farwell – Imperial Capital

Okay.

Barry Welch

You probably do know we do not have any PPAs that expire next year.

Matthew Farwell – Imperial Capital

Got it. Great, well that’s all for me. Thanks a lot.

Barry Welch

Thank you Matt.

Terrence Ronan

Thanks Matt.

Operator

(Operator Instructions). The next question comes from Sean Steuart of TD Securities. Please go ahead.

Sean Steuart – TD Newcrest

Thanks good morning everyone. Just one question with respect to the tax equity structure at Canadian Hills, can you remind us how we should think about the cash reversion phase timing and I guess I am just wondering when for an interim the cash flows will start to revert to your tax equity partner.

Terrence Ronan

Yes, we haven’t guided the flip but it’s pretty far out so there is nothing in the near term for five year at least that you should be looking. It’s out past that.

Sean Steuart – TD Newcrest

Is there is revision phase before the flip date though or no?

Terrence Ronan

No, there is really just from cash point of view there is a flip in that partnership structure and there is nothing else prior to the flip.

Sean Steuart – TD Newcrest

Okay, that’s all I have. The rest of my questions have been answered, thanks guys.

Barry Welch

Thanks Sean.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to Barry Welch, President and Chief Executive Officer for any closing remarks.

Barry Welch

Thanks you once again for your time and attention today and your continued interest in Atlantic Power.

Operator

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

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Source: Atlantic Power's (AT) CEO Barry Welch on Q2 2014 Results - Earnings Call Transcript
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