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Atlantic Power Corporation (NYSE:AT)

Q1 2014 Results Earnings Conference Call

May 13, 2014 8:30 AM ET

Executives

Amanda Wagemaker - Investor Relations

Barry Welch - President and CEO

Ned Hall - Executive Vice President and COO

Paul Rapisarda - Executive Vice President, Commercial Development

Terry Ronan - Executive Vice President and CFO

Analysts

Nelson Ng - RBC Capital Markets

Operator

Good day. And welcome to Atlantic Power Corporation First Quarter 2013 (sic) [2014] Earnings Conference Call and Webcast. All participants will be in listen-only mode. (Operator Instructions) After today’s presentation there will be an opportunity to ask questions. (Operator Instructions)

Please note this event is being recorded. I’d now like to turn the conference over to Amanda Wagemaker, Investor Relations. Ms. Wagemaker, 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 months ended March 31, 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 and 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.

Non-GAAP to 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 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 Welch

Good morning. I’d like to extend my thanks as well to all of you for joining us today. I’ll briefly highlight recent developments and review our financial results for the quarter 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 a commercial update on a few of our projects and markets. Terry will review our first quarter results in more detail and provide an update on other financial matters.

Certainly, the highlight of this quarter was a significant progress we’ve made in achieving our most important financial priorities, which include addressing our debt maturities, improving our financial flexibility and reducing our interest expense and debt levels overtime.

By undertaking a $600 million term loan financing that we did in February, we were able to take advantage of very attractive bank lending markets in order to address $450 million of our near-term debt maturities, as well as put us in place with the new $210 million revolver that provide us with additional borrowing capacity and much greater financial flexibility.

In taking this comprehensive approach to dealing with our maturities at this time, we believe the risk of uncertain market conditions over the next few years, when this debt would have matured.

In March, we use the net proceeds from the financing together with some of our cash to repurchase $140 million or 30% of our outstanding senior unsecured notes. At a 9% coupon, this is our most expensive debt and the interest cost savings on this piece of the refinancing alone is approximately $5 million annually.

We expect to see reduction in interest expense beginning in the second half of this year and continuing through the maturity of the term loan as the debt is amortized. We expect our debt levels to decline during that period as a result of the term loan, mandatory amortization and 50% cash sweep. For example, we estimate that the $600 million principal could be reduced to approximately $140 million by maturity.

In addition these transactions have extended the maturity profile of our debt, as we redeemed or repurchase debt that would have matured in 2014, ‘15, ‘17 and ’18, and with proceeds from the term loan, which matures in 2021.

We have only one maturity remaining before March of 2017 and we plan to repay that convertible as maturity this October using cash. Although, there were significant costs associated with this transaction that we recorded in the first quarter, some of these would have been incurred overtime and we’ve not taken this comprehensive approach, and we believe the actions put us in a much stronger position as we consider our next steps.

Turning to a review of the quarter on slide five, project adjusted EBITDA was down $6.1 million or 8% versus first quarter of last year. There were number of factors that affect these results.

First, we had several outages, some of them caused by extreme weather, some continuing issues at Piedmont, as well as weather-related fuel sourcing challenges at our biomass projects more generally and low water flows at Curtis Palmer and Mamquam. Ned will provide some color on these.

On the positive side, we had some partial offset from higher power prices in PJM at two of our projects and gas resale opportunities at some of our Ontario projects. We also recorded a $4 million expense to terminate and above market gas swaps at our Orlando project required due to the move to our new revolving credit facility at APLP.

Lastly, the translation impact of the weaker Canadian dollar was slightly negative from an EBITDA perspective. Although, we believe that on total company basis, we actually are net beneficiaries as we have significant interest payments and dividends that are paid in Canadian dollars.

With regard to the cost associated with our recent refinancing and debt repurchase transactions. Terry will walk through these with you in a bit more detail, because a significant amount of these costs were recorded in interest expense, they reduced our operating cash flow and our free cash flow, but did not affect project adjusted EBITDA.

Free cash flow declined in a quarter to negative $46 million. However, excluding these transaction costs and the $8 million debt pay down at Piedmont when we converted to a term loan in February, which is the basis on which we provided guidance, our free cash flow for the quarter would be approximately $11 million. Notwithstanding, the puts and takes this quarter, we are reaffirming our 2014 guidance for both project adjusted EBITDA and free cash flow.

Lastly, we issued a news release last week about our engagement of advisors to assist management and the Board in our valuation of a broad range of potential options for the company including a potential sale or merger.

As we said, on our February call, we continue to focus our efforts on how to best position the company to maximize value for our shareholders and are evaluating a broad range of options. We do not intent to comment any further on the ongoing evaluation of potential options, including on these earnings call until further disclosure is appropriate or required.

Now, I'll turn it over to Ned.

Ned Hall

Thank you, Barry, and good morning. During the first quarter several planned outages, fuel sourcing issues at our biomass projects and continued challenges at Piedmont are resulted in a net negative for our operational results versus last year, as well as relative to our expectations. Reduced waste heat at Ontario projects was also negative versus last year. However, we were above our expectations for the quarter.

As you can see from slide six, our availability was 93%, compared to 96% a year ago, still a good result, but below last year and below our expectations. Forced outages at Kapuskasing, Tunis, Piedmont, Williams Lake and Canadian Hills and extended scheduled outages at North Island and Mamquam were the drivers of the lower availability. Two of the forced outages were weather-related. The weather also affected our ability to source fuel at our biomass businesses, resulting in our cost being above expectations.

During the first quarter, our Piedmont business did underperformed. We experienced forced outages for boiler problem, for which warranty claim has been filed and during the scheduled outage we initiated to repair strategy.

Extreme weather also increased the cost of fuel. We have now assumed direct responsibility for plant operations at Piedmont, which we expect it should have positive impact on the operating results.

In addition, while financial results for Curtis Palmer were in line with last year, generation was below our expectations due to the delayed melt and when the melt did occur the extreme high volumes clogged our intake screens and we had water over the dam.

We did have some partial offsets in the quarter, however. Power prices in PJM benefited results at Morris and Chambers. In Ontario, we opportunistically resold our gas positions in improved margins. In Idaho wind volumes were up strongly which benefited our four operating wind businesses there. Finally, the results of our investments to date in optimization initiatives are exceeding expectations.

Most of our businesses did meet the requirements under their PPAs to earn their expected capacity payments in the first quarter. And we achieved these results while sustaining our commitment to an environmentally responsible and injury free workplace.

Generation volume increased 11% compared to last year. The addition of Piedmont in April 2013, increased dispatch at Chambers, Manchief and Frederickson as well as the increased output from Idaho wind businesses more than offset the impact of outages in the decline of Curtis Palmer.

For the quarter, the operating performance of our wind businesses was neutral to budget primarily due to increase in output from our Idaho businesses being offset by the forced outage at Canadian Hills. In April, wind generation was up 10% versus expectations and May continues to be strong.

As a result of the lower output from Curtis Palmer, our Hydro businesses were overall below budget in the first quarter. However, optimization initiatives implemented at Mamquam increased our output capacity by 4 megawatts. Also during April, Curtis Palmer water volumes were up 7% versus expectations and volumes have been strong in May as well.

The outages at our thermal businesses resulted in quarterly performance below expectations. While waste heat was lower than last year, it was above expectations for the first quarter. During April and continuing into May, waste heat levels were higher than expected. In addition, Manchief and Frederickson continue to operate at higher capacity factors than expected.

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 fourth quarter conference call, I indicated that we plan to invest approximately $27 million during 2013 and 2014 that would result in an incremental cash flow in 2015 of at least $8 million. And we remain on track to achieve at least half this amount in 2014.

The most significant of these investments is Nipigon steam generator upgrade, which has the total cost of approximately $11 million, of which about $7 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 before the winter peak season.

Last year, we completed repowering of Curtis Palmer Unit 4. And we've now completed Unit 5, six weeks ahead of schedule which will allow us to capture additional margin from the higher water volumes we have experienced in April and May and help to offset the weaker result of the first quarter.

At our North Island business in California, we accelerated major outage into 2014 to increase the output of the plant. In order to take advantage of an increased to the interconnection capacity we secured from the California ISO. The project was completed in March and the additional 2.5 megawatts is being sold into the short run of what it cost market.

We also were successful in our efforts to re-rate the Calstock boiler, increasing the capacity of the project by about 2 megawatts which is now improving our margins from this business. We're also on track to complete the $2 million investment to boost generation at our Morris project this summer.

As a result of some repair work necessitated by the outages during the first quarter, we expect total major maintenance and capital expenditures for the full year to be in the order of $40 million. This is about $2 million higher than originally planned. It also includes about $18 million of optimization related spending.

Now let me turn it over to Paul.

Paul Rapisarda

Thanks Ned and good morning, everyone. First, I’ll provide a brief update on Delta-Person in New Mexico project in which we have 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 continue to experience some delays but we are working with PNM and regulators to resolve the remaining open issues and still expect to close the transaction as soon as practical, later this year. Sale proceeds to Atlantic are still expected to be approximately $9 million.

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. Both markets are challenging in the near term. We expect both projects to contribute significantly lower project adjusted EBITDA and cash flow after their current contracts expire.

The Selkirk PPA and steam contracts will be expiring at the end of August. The partners are still in discussions with our steam host regarding an extension of the existing agreement and although no agreement has been reached yet. The prospects of reaching a deal prior to the expiration of the existing steam contract appear good.

Approximately 23% of the capacity from Selkirk is not contracted currently and has been sold at market prices or not sold at all if market prices don't support profitable operation. The project is located in Zone F where high realized prices in the first quarter of this year enabled the merchant portion of the plant to achieve the 66% capacity factor.

More generally, we are exploring all feasible options regarding the sale of power from the project, including selling into the day head market or preferably entering into a longer-term hedge or tolling agreement. But again expect post-PPA economics to be significantly less favorable.

Subsequent to our required notice [Technical Difficulty] approach by New York regulators about the role that Selkirk plays in grid reliability and capacity support in Zone F. We have not had any discussions yet on a possible reliability must run agreement, but would certainly consider pursuing that if that were a viable alternative.

Our Tunis project in Ontario has a PPA which expires at the end of this year. There's been no change in the status of our recontracting negotiations with the Ontario Power Authority or OPA, with discussions between the two parties continuing. However, the recent dissolution of the Ontario legislature and pending elections on June 12 are likely to put any negotiations on hold at least in the short term that the outcome of the election could have an impact on energy policy, as well as key staff in the province.

Suffice it to say that considerable near-term uncertainty is likely to affect our efforts to negotiate a new contract for Tunis. It is important to note, however, that two of the other NUG contract holders did successfully negotiate new 20-year contracts as indicated by their public disclosure, thereby providing an indication of the OPA’s willingness to adhere to the requirements of the 2010 ministerial directive.

Lastly, I’d like to briefly touch on some recent developments that could affect our businesses going forward, as well as any potential project acquisition opportunities. Even adjusting for the winter weather, load growth averaged 1.2% across the U.S. in the first quarter and should further support better capacity prices in many markets.

The EPA's Cross-State Air Pollution Rules were recently upheld by the U.S. Supreme Court. Although it is largely reflected in our current outlook, we expect it to have a further positive impact along with implementation affecting regulations around mercury and other air toxins, by bringing about additional coal plant retirements and therefore tighter power markets, which we expect will be a positive for plans such as Morris and Kenilworth.

Finally, according to the American Wind Energy Association, there were a record of approximately 12,000 megawatts of wind projects under construction at the end of 2013. Unfortunately, recent uncertainties around the IRS's interpretation of construction start definition for purposes of determining whether a project qualifies for the wind production tax credit is not surprisingly, creating some complications in our discussions with developers who have potentially attractive late stage development investment opportunities, but do require further clarity around their eligibility or PTCs.

Now let me turn it over to Terry. Thank you, Paul and good morning. First, I'll review our financial results for the first quarter 2014, as compared to the prior year and walk you through the impact of the refinancing and debt repurchase transaction related costs in our results. I’ll then provide an update on our guidance. Finally, I'll comment on changes to our debt liquidity positions as a result of the actions that we took during the quarter.

Slide 10 provides an overview of our financial results for the first quarter 2014. Project adjusted EBITDA decreased by $6.1 million to $74.2 million for the first quarter 2014, compared to $80.3 million for the same period last year. As Barry and Ned have already discussed, we had some outages in some of our projects this quarter that affected results.

In addition, we incurred cost of $4 million to terminate a gas swap at our Orlando project. We also had an approximate $2 million reduction in EBITDA due to currency translation impacts from a weaker Canadian dollar. The exchange rate this quarter was approximately $110 million versus $102 million a year ago.

However, we believe that this currency impact is more than offset by the benefit realized in our Canadian dollar-denominated interest expense and dividends. Positive factors affecting our EBITDA performance this quarter included strong wind generation at Meadow Creek and the other Idaho wind projects and the steps we took last summer to reduce corporate development expense.

Slide 11 provides a bridge of our project adjusted EBITDA from Q1 2013 to Q1 2014, highlighting the key changes by project. As I mentioned, the declines were driven primarily by outages in the fuel swap termination at Orlando. The gas swap was about market and cover purchases through 2017, and we are currently exploring options to hedge volumes of natural gas prices lower than those of the on loan hedges, which should allow us to recoup some of the costs of the fuel swap termination overtime.

As Barry mentioned during the quarter, we incurred significant expenses related to the refinancing and debt repurchase transactions. These totaled approximately $100 million and are shown on Slide 12. Last quarter, we had estimated the cost would be about $80 million. But this estimate excluded costs associated with the potential repurchase of our 9% senior unsecured notes, $140 million of which we repurchased in privately negotiated transactions subsequent to the call -- February call.

The related costs were approximately $16 million. Approximately half of the $100 million of total cost or $49 million were for premium payments and accrued interest associated with the debt that we redeemed or repurchased. These were included in interest expense in the first quarter of 2014, and thus did not affect project adjusted EBITDA.

The $4 million swap termination at Orlando was recorded in fuel expense. The total of these items is $54 million and is included in operating cash flow. Most of the remaining expenses were approximately $41 million were refinanced for financing advisory, legal consulting and rating agency fees directly related to the transactions, which we capitalized as deferred financing costs and will amortize over the life of the financing. These expenses, although were use of our cash are reflected in financing cash flows and did not affect our cash flow from operating activities or our free cash flow.

Turning to Slide 13, I'll cover our cash flow results for the quarter. Operating cash flow declined $118 million to negative $29 million primarily to the three factors. The transaction costs, I just described which reduced operating cash flow by $54 million, the absence of $28 million of cash flows from businesses that we divested last April and the year-over-year change in working capital of $36 million, most of which is attributable to the return of construction related reserves and other factors last year that were non-recurring in nature.

Had we not incurred the financing and debt purchase transaction costs, operating cash flow would have been a positive number for the quarter, approximately $25 million. Free cash flow which is after project debt repayment, including the cash flow sweep under the APLP term loan, capital expenditures and distributions to non-controlling interests decreased by $128 million to negative $46 million, for the first quarter compared to positive $82 million for the same prior year period.

Our free cash flow results are down year-over-year because of the same $118 million of decreases in our operating cash flow that I just described, plus the $8 million of Piedmont construction debt that we paid down in February to facilitate term loan conversion. Excluding the refinancing and debt repurchase transaction costs and the Piedmont debt repayment, our free cash flow for the quarter would have been approximately $11 million.

Turning to our 2014 guidance, which we are reaffirming for both Project Adjusted EBITDA and free cash flow. Slide 14 provides a bridge of our 2013 Project Adjusted EBITDA of $269 million to our 2014 guidance of $280 million to $305 million. There have been a few changes since our last call, but on balance, we still expect to be in this range. Most significant of this is the $4 million of fuel swap termination, Orlando that was not in our original guidance. We still expect increased EBITDA from Orlando as a result of a more favorable PPA and lower gas costs.

We have lowered our expectations for Piedmont to reflect first quarter results that we still expect an increase for the rest of the year. We have also incorporated the impact of the unplanned outages and low water levels at Curtis Palmer relative to our expectations. These factors are partly mitigated by increased generation of the Idaho wind projects driven by strong winds and reduced corporate expenses.

Slide 15 provides a bridge from our Projected Adjusted EBITDA guidance to our free cash flow guidance. Expected interest expense of $165 million to $170 million includes approximately $49 million of costs associated with the refinancing and debt repurchase transactions previously discussed. Excluding these costs, interest expense should be modestly lower than last year and we expect to see reduction in interest expense quarter-over-quarter beginning in the second half of this year.

On an annualized basis, we expect savings from the financing and repurchase transactions of approximately $7 million and that should grow over time as the term loan is amortized. The expected repayment of the convertibles at their maturity in October with cash is expected to result in another approximate $2.7 million in savings in 2015.

Walking from operating cash flow to free cash flow, the most significant deductions are the amortization of the APLP term loan, project CapEx of $20 million which is higher than in past years due to Nipigon’s steam generator upgrade which we have discussed on past calls, and other optimization projects, and project debt repayment of $26 million which includes the $8 million principal repayment in Piedmont that I mentioned earlier. Including all of these factors, our reported free cash flow is expected to be negative this year.

However, our guidance excludes the $49 million of additional interest expense in the Piedmont debt repayment, and on that basis, we still expect 2014 free cash flow in the range of 0 to $25 million.

Slide 16 summarizes year end 2013 debt and then walks through the changes that occurred in the first quarter of 2014, reflecting the new $600 million term loan, the redemption of $415 million of our Curtis Palmer and US GP notes, repayment of Piedmont project debt and the repurchase of $140 million outstanding of our 9% senior unsecured notes.

The year end projected debt balance incorporates the expected repayment with cash, a $41 million of convertible debentures at maturity in October, project level debt amortization of $19 million, and amortization of the term loan, expected to be approximately $52 million on a partial year basis. The net result would be an approximate $86 million reduction in total debt by year end 2014 versus year end 2013, excluding any foreign currency impacts on our Canadian dollar denominated debt and no debt full of maturities until the first quarter of 2017.

Slide 17 provides an update on our liquidity, which increased to approximately $246 million as of March 31, 2014, from $184 million at December 31, 2013. Primary reason for the increase was the new revolving credit facility at the APLP that we put in place in February, which has a capacity of $210 million versus $150 million under the prior credit facility. Prior facility also directed us to hold the cash reserve of $75 million, which is no longer required.

Unrestricted cash increased by $21 million from year end to $180 million. As I have noted, we plan to use $41 million of this cash to repay the convertible debentures at maturity in October and have already hedged our Canadian dollar exposure 110.5 with respect to this maturity.

Letters of credit outstanding at March 31 totaled $144 million, but as of May 9, this had been reduced to $131 million, as a result of $10 million reduction in letters of credit posted with the counterparty at one project, as well as $3 million in connection with the transition from the prior credit facility to the current one. We expect the further $3 million transition-related reduction in letters of credit in the near term and are actively pursuing reductions in other projects.

Lastly, I will provide an update on our covenants. We expect to meet all the financial maintenance covenants in the agreements governing our debt for at least the next 12 months. However, I would note that as a result of the expenses associated with the refinancing and debt repurchases that we recorded in the first quarter, we no longer meet the fixed charge coverage ratio test under the restricted payments covenant in our high yield debenture. This ratio is calculated on the rolling four quarter basis, so these charges would drop out of the calculation at fresh reporting quarter of 2015.

Also, the interest expense savings from the $140 million purchase of our senior notes in March are rolled into the test in the first quarter of 2014. As long as we are not in compliance with this test however, the restricted payments 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 $63 million as of March31.

The dividend that we paid in February, March, and April totaling $11 million are counted against the basket and the dividend declared in April to be paid at the end of May will be the fourth monthly dividend payment count against the basket. Although this is intended to give you an explanation of the mechanics of the basket where it presently stands, the basket is not the driving factor with respect to any decisions on the dividend level. Dividends are declared and paid at discretion of our Board of Directors.

Now, I would like to turn the call back to Barry?

Barry Welch

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

Question-and-Answer Session

Operator

(Operator Instructions) And the first question comes from Nelson Ng with RBC Capital Markets.

Nelson Ng - RBC Capital Markets

Great, thanks. Good morning, everyone.

Ned Hall

Good morning, Nelson.

Nelson Ng - RBC Capital Markets

Just a quick question on Tunis. So in the event that you guys don’t get a new contract from the OPA, doesn’t make sense to operate the facility as a peak or on a seasonal basis, like during the winter?

Terry Ronan

Yeah, I mean, Nelson, it’s a good question. I think, as you know, the Ontario market is not well-designed currently for that kind of an operation. We certainly are exploring both the technical requirements as well as the economics of operating it on something other than its current base load regime. But I think, we’d just be speculating at this point to say more than that.

Nelson Ng - RBC Capital Markets

Okay. That’s fair. And then just quickly on the debt refinancing. I wanted to just better understand the flexibility of the term loan B in terms of -- regarding your kind of in light of the strategic review. So I think you previously mentioned that, I guess you sell any assets at APLP, it would be okay as long as the proceeds are applied towards the debt. I just want to ask whether if you were too kind of partially sell or do a joint venture or partnership in one of those assets, what the potential buyer or partner also be able to kind of take its portion of cash flows from those asset, if they were in APLP?

Terry Ronan

Yes, Nelson, that’s correct. As long as when we do the transaction, we’re in compliance with our covenants. We are permitted to do a transaction of that nature.

Barry Welch

Yeah. Nelson, it’s Barry. The renewals, some of longer-term contracts are on the other side of this structure and that might be the place where you could be imagine, it’d be a littler easier to look at joint venture possibilities without having to ask the questions about the APLP term loan.

Nelson Ng - RBC Capital Markets

Okay. That’s great. And then, I guess, one kind of detailed question on in terms of your kind of longer-term $25 million major maintenance and CapEx expectation, like roughly what’s the split between what’s expense versus capitalized?

Barry Welch

This year it’s a little higher, Nelson, in terms of some of the chunkier pieces of optimization projects that certainly that has been historically, Terry?

Terry Ronan

Yeah. Generally, Nelson, I think, we’ve talked in the past that that’s been around $5 million a year. But this year, it's about 50-50, mostly driven by the Nipigon project, the total is about $11 million.

Nelson Ng - RBC Capital Markets

I see. So, $5 million would be capitalized and the rest would just be expense to major maintenance longer-term.

Barry Welch

There will be a sort of a more typical one. But I think what Terry’s indicating is that for this year because of those larger capitalized projects including Tunis -- sorry Nipigon being the biggest. We’d be more like 50-50 in terms of the amount that gets capitalize, so about $20 million of the $40 million roughly would be capitalized this year.

Nelson Ng - RBC Capital Markets

Okay. Got it. And then just kind of one last question, I was hoping you can give more color on the Greeley facility. So I think, you mentioned in the 10-Q that the facility was sold for $1 million. Was that facility already mothballed and it seems like a pretty low amount, but could you just give some color in terms of that facility? I know it wasn’t very profitable to begin with, and I guess like $1 million and how that transaction came about?

Terry Ronan

Yeah. I think, Nelson, it is Terry. We had talked pretty extensively about the PPA expiring there and we went through some negotiations to try and find more alternatives and did not, so PPA expired at the end of August last year. And the idea was that we were going to shut it down completely, not mothball it. And then we did find a buyer during the course of the fall, so the $1 billion might seem low, it exceeded our expectations by $1 million.

Ned Hall

Yeah. Let me add to that. It’s Ned, Nelson. The equipment is vintage at this point and since we knew the PPA was ending, we timed it fairly well to not have the type of capital you could invest to the equipment up to full spec, if you will. So, I think, we thought the $1 million was actually better than budget, better than we expected together. And the buyers of the equipment are not going to be able to find a place to use in the U.S. or Canada, which obviously are the markets we focused on. They’re taking it outside the U.S. to try and put it to work in a market that has short power and has expensive power prices. So it’s not very efficient equipment. We had run it into the ground, if you will, towards the end of the PPA and we felt pretty good about the price.

Nelson Ng - RBC Capital Markets

I see. So they weren't buying it to somehow try to operate it, they just went and bought the equipment and they’re shipping it somewhere else to use.

Barry Welch

On my understanding, what they plan to do, I don’t know what they’ve actually done. But I’m fairly confident that they are not going to find a way to run it anywhere in the U.S. and Canada.

Nelson Ng - RBC Capital Markets

Okay. All right. Thanks for that.

Barry Welch

Thanks, Nelson.

Operator

Thank you. (Operator Instructions) All right. As there is nothing else at the present time, I would like to turn the conference back over to Mr. Welch for any closing comments.

Barry Welch

Thanks very much everyone again for your time and attention and your continued interest in Atlantic Power. Thank you. You can close the call.

Operator

Thank you. Yes. The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect. Have a nice day.

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