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Atlantic Power Corp (AT)
Q3Â 2019 Earnings Call
Nov 1, 2019, 8:30 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good day, and welcome to the Atlantic Power Corporation Third Quarter 2019 Results Conference Call. [Operator Instructions] Please note this event is being recorded.
I would now like to turn the conference over to Ron Bialobrzeski, Director of Finance. Please go ahead.
Ron Bialobrzeski -- Director of Finance
Welcome, and thank you for joining us this morning. Our results for the three and nine months ended September 30th, 2019 were issued by press release yesterday afternoon and are available on our website www.atlanticpower.com and on EDGAR and SEDAR.
Management's prepared remarks and the accompanying presentation for today's call and webcast can be found in the conference call section of our website. A replay of today's webcast will be available on our website for a period of one year. Financial figures that we will be presenting are stated in US dollars and are approximate unless otherwise noted.
Please be advised that this conference call and presentation will contain forward-looking statements. As discussed in the company's Safe Harbor statement on page two of today's presentation. 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.
In addition, the financial results in the press release and the presentation include both GAAP and non-GAAP measures, including project adjusted EBITDA. For reconciliations of this measure to the most directly comparable GAAP financial measure to the extent that they are available without unreasonable effort. Please refer to the press release, the appendix of today's presentation or our quarterly report on Form 10-Q. All of which are available on our website.
Now I'll turn the call over to Jim Moore, President and CEO of Atlantic Power.
James J. Moore, Jr. -- President and Chief Executive Officer
Thank you, Ron. Welcome everyone, and good morning. Thank you for joining us today. With me this morning are Terry Ronan, our CFO; Dan Rorabaugh, our SVP Operations; Joe Cofelice, our EVP, Commercial Development and several other members of the Atlantic Power management team.
The results for the third quarter are provided in the press release, the presentation and the prepared remarks, which were posted to our website last evening. Please review those materials. I will cover the highlights. Following my remarks, we will take your questions.
We had a productive third quarter in many areas. We have a culture of bad news in nanoseconds, a term we borrowed from the man in Omaha. So, before I review the positive news of the quarter, I'll lead off with the one negative development and that was the fire at our Cadillac biomass plant on September the 22nd.
Fortunately, no one was hurt. Our assessment of the damage and our investigation of the cause are still under way. At this time, we believe the fire probably resulted from a malfunction in the steam turbine, which was badly damaged as a result and will need to be replaced along with the generator.
The fire did not involve the fuel areas of the plant and was not related to anything specific to biomass plants. We're working hard to bring the plant back online. Our current estimate which is subject to change is that this will probably take at least another nine months.
We have insurance coverage for our plants, which we believe is adequate to cover the cost of necessary repairs and replacement of equipment. Our business interruption insurance also should essentially replace the loss EBITDA during the outage. We believe that our financial exposure to this event is limited to our insurance deductibles. We estimate the impact at approximately $2.5 million to $3 million.
Turning to the positive developments of the quarter. First, financial results exceeded our expectations. This was a continuation of our strong performance in the first half. As a result, we've increased our guidance for 2019 project adjusted EBITDA to a range of $185 million to $195 million.
We've also increased our estimate of 2019 operating cash flow to a range of $115 to $125 million. Second, we continue to meet our deleveraging objectives. We pay $18 million of debt during the quarter, which keeps us on track to repay total of $87 million this year.
Our leverage ratio has improved to 3.7 times and we expect it to finish the year at approximately that level. We see further improvement in the ratio in 2020 and beyond as we continue to repay significant amount of debt. Third, we successfully recontracted Williams Lake for 10 years.
This was a good outcome in a difficult market and it is significantly accretive to our previous estimates of intrinsic value per share. Kudos for our commercial team. The contract structure makes EBITDA and cash flow estimates more volatile than for our other biomass plants, but once we've gotten further down the path in our fuel procurement strategy, we will provide guidance on longer-term expectations most likely at some point next year.
Four, this quarter marked a return to growth for us. We closed on the acquisition of four contracted biomass plants for a total of $31 million. We've increased and extended our expected PPA generated revenues and cash flow as a result of these acquisitions.
On a combined basis, we expect them to generate project adjusted EBITDA of approximately $7 million to $9 million annually on average through 2027 and then about $3 million annually through 2043. The expected investment returns are attractive and the acquisitions are accretive to intrinsic value per share. We are evaluating some potential optimization investments for the South Carolina plants that we expect with further improved returns.
So, going forward, we have now successfully paid down nearly $1.1 billion of debt since 2014 and we are on a pace to cut the current level and half from here. We reduced our corporate overheads by around 60%. The combination of the two is contributing to strong cash flows available for capital allocation. We have significant free cash flow after debt repayment to look forward to over the next five years. We also have liquidity of $181 million as compared to an equity market capitalization of just $257 million based on recent share prices.
The best use of capital would be acquisitions such as the $45 million we did over the past year. We are disciplined now and we're willing to turn this ample cash flow toward more aggressive share buybacks, if the external markets are not giving us any fat pitches. Since December of 2015, we bought back $56 million of common and preferred shares with $37 million of that in common at an average price of $2.27.
We plan using the ongoing cash flows and developed to do the most good for our intrinsic value per share, whether it's doing another $45 million of investment another $56 million in return of capital or both. We have no set allocations we'll stay focused on price to value and intrinsic value per share.
We'll now take your questions.
Questions and Answers:
Operator
Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from Nelson Ng of RBC Capital Markets. Please go ahead.
Nelson Ng -- RBC Capital Markets -- Analyst
Great. Thanks. Good morning, everyone.
Terrence Ronan -- Executive Vice President and Chief Financial Officer
Good morning, Nelson.
Nelson Ng -- RBC Capital Markets -- Analyst
My first question relates to Cadillac. I think in the prepared comments the $24 million of insurance receivables is just for the repairs, right? It's not for the business interruption part?
Terrence Ronan -- Executive Vice President and Chief Financial Officer
Yes, that's correct, Nelson. It's just net of the $1 million deductible versus $25.2 million writedown.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay. So, if the outage is about nine months and I think Cadillac was earning about $8 million or so of EBITDA annually and you might expect another like rough using very rough numbers like $6 million of receivables from business interruption subject to deductibles. Does that feel right?
Terrence Ronan -- Executive Vice President and Chief Financial Officer
We've got 45-day deductible on the business interruption insurance, I would say, that you should look at it as approximately $1 million a month.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay. Got it. And then in terms of the insurance receivables like what is the risk of, I guess, not receiving what you expect or not fully recovering your costs and your loss margins like what are some of the factors there?
Terrence Ronan -- Executive Vice President and Chief Financial Officer
We don't see a scenario where that would be reduced. We're pretty confident that we'll receive everything that we need beyond the deductibles.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay. Got it. And then just moving on to Williams Lake. I believe that it's -- there's a fixed price that you're getting for the power produced. But there's no pass-through for any changes in fuel costs. Could you just give a rough number in terms of what you expect the plant utilization to be on a longer-term basis? I know there's a maximum capacity factor of 67%, but like what's your -- what's in your business plan in terms of your utilization?
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Yeah, good morning. This is Joe. We'd expect over the longer term, over the term of the PPA to run at approximately 67% capacity factor, which is the maximum allowed under the PPA for 2020. As we said in our prepared remarks, we're building up our inventory. So we may run less than 2020. Hopefully we'll run more in 2021 and then we hopefully the maximum output that we can -- that we're allowing under the PPA after that.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay. So, I guess, using that assumption where you're kind of running as much as you can, you're pretty confident that the power price you're getting, obviously, more than covers your cost of fuel longer term and you don't really see a risk in terms of the cost kind of outpacing the contracted revenue side? Is that what you're saying?
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Yeah, I mean, there's certainly a risk and that's why we negotiated provisions in the PPA that provide us with ability to get out of the contract and essentially cap our losses, if the fuel market were to go totally sideways on it. Having said that, we have updated our fuel supply studies. We think we have conservative estimates in there for the cost of fuel from the mills. If you do have conservative estimates in there or the cost of fuel that we'll get the road side residual, I can't say that, and the forest residual. And based on that we think the economics of the project is strong and as Jim noted, our base case exceeds our -- the projections that we're carrying internally prior to entering into the contract.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay. And then another question on Williams Lake. Can you just comment about, I guess, magnitude of the maintenance you need to do from now through 2021? And roughly if you choose to do it, what is the rough cost of the fuel shutter for rail ties?
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Yeah, well, I mean taking the last part of that question first. We haven't disclosed the capital cost for the fuel shutter and we're not in a position to do that and also had to estimates to provide on that. As far as the maintenance goes we -- the two major items that we're focusing on our rebuilding of a cooling tower and a rewind to the generator. We'll have more to say on those costs in the fourth quarter.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay, thanks. I'll get back in the queue. Thank you.
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Thank you.
Operator
Our next question comes from Rupert Merer of National Bank. Please go ahead.
Rupert Merer -- National Bank -- Analyst
Good morning, everyone. Maybe I'll continue with Williams Lake. So, you understand it can be a competitive market for purchase of mill residuals and harvest residuals today with curtailment of some of the lumber mills, but also demand from some of the pellet mills. Just wondering how you see your competitive position versus the pellet makers. Is your power price high enough that you think you'll be able to compete with them on the cost of fiber?
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Yeah, I mean, on the latter point. Our power price is sufficient to allow us to completely believe that. Having said that, we are making conservative assumptions as the amount of actual fuel that we'll receive from the mills. And that quantity is significantly lower than what we will receive to get the long-term contract that we have in place before.
And one of the thing as it relates to the pellet plant is, it's important to note that their spec is higher than our spec. And so while they do compete with us for fuel and they do -- and that does impact us. They do leave pellets on the side of the road that we can take advantage of them. We're currently using that.
So we think we're providing conservative estimates in our economics to reflect that, but we fully understand the state of the market there. We fully understand that we're competing against, I think, two pulp mills, a board plant and a pellet plant and we've updated our fuel supply studies to take that into account and to take into account the fact that three mills are closed and others are curtailed.
And based on all of that, we think we'll be OK, but obviously if something would happen and the whole industry went sideways and all the mills closed down and then wouldn't have surprised the mills. We wouldn't have the brick and the woods and that's why we negotiated the provisions, we negotiated the PPA that allow us to cap that risk.
Rupert Merer -- National Bank -- Analyst
And your fiber supply studies. What's the furthest you believe you can drive the material before the price is not competitive.
Joseph E. Cofelice -- Executive Vice President, Commercial Development
You know, we'll have more to say on that later. We're actually out in the woods now and we're actually securing supplies and based on the actual results of that we'll have more to say there.
Rupert Merer -- National Bank -- Analyst
Okay, great. And moving to Oxnard, so you have some comments in prepared remarks about Oxnard and your ability to get another contract. It looks like contracts in California could be shorter three to five years. It seems consistent with some of the other awards we've seen recently, but you mentioned Southern California Edison is looking for 1.7 gigawatts, but the probability for recontracting at Oxnard still low in Atlantic's opinion. Why do you think the opportunity is low for public plant?
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Well, I mean, whenever there's a solicitation for 1700 megawatts you generally see bids in aggregate that will be multiples of that. That's historically what we've seen and our hit rate bidding against people who have much lower cost of capital as historically has been that bad. It's difficult.
Having said that, in this case, we are in an area that we believe is constrained, and we believe they need power there. I think the question will be in their analysis, how much do they need, and how competitive are we to -- in response to it. So, I mean, it's less than 50%. I'd say it's low probability, that's low probability for me. It's not as low as it was a year ago. That's a good news, but we're not at the point where we are confident enough to say, it's a higher probability than that right now.
Rupert Merer -- National Bank -- Analyst
And the scenarios you're looking at for recontracting. Is your industrial customers still supportive of the economics of that plant?
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Well, we're considering all options. I believe the answer to that question is yes. But one of the option for us would be to proceed with the plant in its current configuration, another option would be to convert the plant to a peaker. There are advantages and disadvantages to both. And we're evaluating all of that. So, we think he would be supportive. Certainly there's economic interest to be supportive, but do we require him to be there? No.
Rupert Merer -- National Bank -- Analyst
Okay, very good. Thank you. I leave it there.
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Thanks, Rupert.
Operator
Our next question comes from John Mould of TD Securities. Please go ahead.
John Mould -- TD Securities -- Analyst
Good morning. Maybe just to go back to Williams Lake for a second and a little more detail on the decision points on the shredder. How are you thinking about that capital outlay versus taking up to 35% of your fuel supply risk off the table through burning rail ties? And from a timing perspective, beyond finalizing the capital cost, is it also just a question of testing the market for longer-term fuel supply for a few quarters to inform that shredder investment decision?
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Yeah, you nailed it on that last point, if you think about it. There were two pieces missing from our analysis. One, was the terms and conditions of the PPA and how it applies to burning rail ties. We have that now. We signed that contract on October 1st. Now we're contracting with the timber mills to the extent that we can and then we're also out securing the roadside residue and forest residue and we have a better handle on those economics will be able to complete the analysis, but you're spot on there.
John Mould -- TD Securities -- Analyst
Okay. And then you had some comments in your prepared remarks on Calstock. There's no current process for biomass recontracting. Ontario as you said, is your sense that there's an openness to considering the non-electricity benefits or is that just at this point overshadowed by the near-term electricity oversupply situation and maybe the fact that the ISO has been advancing a competitive capacity procurement process? What are your thoughts there?
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Six months ago, seven months ago, I would have said that, you're right. All of that is overwhelming the process for us. I think recently we have been able to gauge with all the relevant ministries and they understand the issue and they understand the importance of biomass plants for the timber industry and for the local communities. These plants have a significant economic impact in the area. And so there is a recognition of it.
I think the problem is how can they do it particularly in an environment where the government ran on a platform that we're not entering into contracts and above-market cost, right. So, you have to deal with that, and we try to point to is what happened in British Columbia, where you had a steaming report come out from the government on BC Hydro's procurement practices from IPPs, but then in the same document says. However biomass plants provide of these other benefits. We have to take them into account and they ordered the utility to enter into negotiations with us.
So, that's what we're trying to do. We're also making the argument that the ISO is proceeding toward this incremental capacity auction. They put the brakes on that in July. So there's even more uncertainty of how the markets will evolve, and we tried to point out to them that our PPA is expiring. And if you let us go, you'll lose the opportunity to recontract us in the future. Therefore something to keep us going while you flip this out. So we tried to make all the arguments we can make whether it will work at the end of the day, who knows, but we'll give it in a full-court press.
John Mould -- TD Securities -- Analyst
Okay. Thanks for that detail. And then maybe just one last question on the -- just broader M&A outlook. How is the biomass -- I don't want to focus on biomass overly, but it's been where you've had success for the last year. How is that opportunity set evolved since you announced the South Carolina acquisitions a year ago? And any takeaways from the integration of those two assets into your fleet thus far for future biomass transactions you might make?
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Sure. On the first part of the question, I think, it's interesting if you look back over the last few years here at Atlantic Power. Our big external successes on the growth side has been biomass plants. And those acquisitions came about as a result of proactive engagement on our part and not responding to a bank process. And so there are a number of biomass plants in North America. Some of them have significant PPA cover on them. And really from time to time companies decide they need to monetize assets and raise capital.
And really what we need to do is be the first people in the door approaching them when that happens and that was the case with AltaGas. That was the case with EDF. So, when you look at the inventory of them, there's a reasonable number of them. But we could visit someone and they can say we have no interest in selling. We can show up six months later and be in a negotiation. So, it's a constant follow-up and pushing as hard as we can.
And then on the integration side, I think, the integration of both plants. I'll answer it if Dan wants to add to this, he can. The integration is going well at both -- at all four plants. Just to remind that we operate two of them. CMS operates the other ones and CMS is an excellent operator. So, there's not a lot, but we have to do there as far as integration of the operations. But the two EDF plants is flowing extremely well. And we have six biomass plants now that we operate. So, we give a strong reservoir of knowledge and expertise to draw on. So, we think we're well placed to take on additional assets.
John Mould -- TD Securities -- Analyst
Okay, thanks for the detail. I'll leave it there.
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Thanks.
Operator
Our next question is a follow-up from Nelson Ng of RBC Capital Markets. Please go ahead.
Nelson Ng -- RBC Capital Markets -- Analyst
Great. Thanks. Just a few more questions on the biomass facilities. In terms of the four acquired biomass facilities I think based on your post-2027 EBITDA guidance, are you essentially assuming that there's no EBITDA contribution from the two facilities acquired from AltaGas after 2027?
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Yes, that's correct. But that doesn't mean that we're not going to do our best and believe that there's some opportunity so we can track it.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay. So there's essentially like a PPA recontracting risk and in the meantime you're just assuming zero contribution until you lock something in?
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Yes. What I would say on that is the -- what we found in many of these situations with our other biomass plants is if we get closer to the PPA date. And there's a recognition of the benefits that the biomass plants provide -- the probability of engaging with utility and our recontracting goes up.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay.
James J. Moore, Jr. -- President and Chief Executive Officer
We're recontracting for our investment thesis.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay.
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Yeah, to Jim's point.
Nelson Ng -- RBC Capital Markets -- Analyst
And then the other kind of related question is in terms of biomass acquisition multiples. Not sure whether it's just a coincidence, but I think the last two transactions were done at like roughly four times EBITDA even though the remaining PPA terms were quite different. So,I'm just wondering whether that's your kind of rule of thumb in terms of trying to acquire things at four times or like I'm sure there's like a lot of other factors you look at. But could you just comment on that?
James J. Moore, Jr. -- President and Chief Executive Officer
Yeah. So we think multiples are meaningless. People use them in the industry for shorthand, but really it's -- you have different contract prices and contract terms. And so really you need to do discounted cash flow analysis to come up with true value. So, we kind of like everybody else we'll throw out a multiple just because that's the convention, but that's not at all what we focus on in terms of our investment decisions.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay. So, just to clarify. So, for the two different biomass investments that closed this year like they were at similar multiples. But are you saying that the returns are similar as well despite the difference in PPA term?
James J. Moore, Jr. -- President and Chief Executive Officer
No. We negotiate separate deals. So, we didn't have a set discount rate we're using on biomass. We're going to get the best deal we can get. And in both case, we thought we had really attractive returns. They're different returns. And really that's how we do our investment. We do it on NPV. We don't do it on a multiple.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay. Great. Thanks for that. I'll leave it there.
James J. Moore, Jr. -- President and Chief Executive Officer
The whole industry you think about it there's people do these multiples and there's one contract is five years and one is 10 years, it doesn't, it's just apples and oranges. So, it's really got to be a DCF analysis.
Operator
This concludes our question-and-answer session. I would like to turn the conference back over to Jim Moore for any closing remarks.
James J. Moore, Jr. -- President and Chief Executive Officer
All right. We thank everybody for joining. And it was really strong quarter and not too often when we announce a 10-year, two-day extension and closed four projects and raise guidance, but we were able to do that this quarter and we'll talk to you next quarter. Thanks for joining.
Operator
[Operator Closing Remarks]
Duration: 30 minutes
Call participants:
Ron Bialobrzeski -- Director of Finance
James J. Moore, Jr. -- President and Chief Executive Officer
Terrence Ronan -- Executive Vice President and Chief Financial Officer
Joseph E. Cofelice -- Executive Vice President, Commercial Development
Nelson Ng -- RBC Capital Markets -- Analyst
Rupert Merer -- National Bank -- Analyst
John Mould -- TD Securities -- Analyst
