Talen Energy Corp (TLN) 2016 Q1 法說會逐字稿

Welcome to the Talen Energy first-quarter results conference call.

(Operator Instructions)

Please note this event is being recorded. I would now like to turn the conference over to Andrew Ludwig. Mr. Ludwig, please go ahead

Thanks Kate, and good morning everyone. Thank you for joining the Talen Energy Corporation conference call to discuss first-quarter 2016 results. Today's presentation is being webcast. And we are providing slides of the presentation on our website at talenenergy.com. This presentation may contain forward-looking statements. And we encourage you to review our filings with the SEC to learn more about certain risk factors that could cause actual results to differ from these forward-looking statements. This presentation also will contain references to non-GAAP financial information that we use to measure our business. You can find the reconciliation between the non-GAAP financial measures we use, and most directly comparable GAAP measures in the schedules to our earnings release and the presentation that we have posted on our website. With that, I'll now turn the call over to Paul Farr, Talen Energy President and CEO

Thanks Andy. And thank you all for joining us on our first-quarter earnings call. Joining me on the call today are Jeremy McGuire, our CFO. Joe Hopf, who leads our commercial team and our non-nuclear generation. As well as Tim Rausch, our Chief Nuclear Officer. After my prepared remarks, Jeremy will take you through more detailed review of the financial performance in our forecast. And we'll then take questions.

We're about three weeks shy of the anniversary of the spin and the acquisition of the RJS portfolio. And I'm extremely proud of the efforts and accomplishments of our entire team over the past two years of planning and execution. We'll touch a number of initiatives that we have on our way to grow value for stockholders in our prepared remarks. So I'll move right into slide 4.

The April 1 sale of the Eastern Hydro assets for $860 million marked the end of the FERC mitigation assets sales. All of which are executed at great values and competitive processes. Our Brunner Island coal-fired project remains on schedule, which should permit us to burn gas in Unit 3 by August, and the smaller two units by the end of the year.

We've made significant progress on the Montour Project Evaluation as well, and expect to have final decision on that in the next few weeks. That project is expected be executed a little differently than Brunner Island, in that we are working with a midstream company to finance, construct, and operate the lateral pipeline.

Since the Brunner Island Project as a much stronger lateral, we are initially financing and constructing the gas line ourselves. Once the Brunner Project is completed we plan to assess the value of selling the line to a midstream company to free up the capital we invested in that portion of the project.

At Susquehanna, we safely and successfully completed our Unit 1 refueling outage, which included normal refueling and maintenance activities, as well as major work to replace the original feed water heaters, and installation of shortened blades on the second Unit 1 LP turbine. That leaves the third and final LP turbine blade replacement on Unit 1 for the outage scheduled in the spring of 2018.

I want to thank the entire Susquehanna team for staying focused on safe execution of this work. All while keeping Susquehanna Units 2 running at capacity factor of 100% for 10 months and counting. Fantastic work by all.

The great operating performance, and addition of assets to the portfolio over the past year allowed us to achieve comparable adjusted EBITDA performance for the quarter versus Q1 2015, despite significant declines in energy prices. As we noted when we provided you 2016 adjusted EBITDA and adjusted free cash flow guidance on our year-end call in late February, we excluded from that guidance the financial contribution of the assets being sold to meet the FERC mitigation requirements. Our revised guidance ranges have been updated to reflect the actual financial contribution of those assets, which were sold. And Jeremy will comment more on that in his remarks.

On slide 6, we begin the commercial and operational review. Given our fuel diverse portfolio you can clearly see the impact low natural gas prices are having on generation assets in the region. Gas continues to gain additional runtime at the expense of coal. A major driver of our decision to invest in gasification of the Brunner Island Plant and our evaluation of a similar investment at the Montour asset.

Susquehanna generation was lower year on year, primarily due to a difference in the timing of the 2015 and 2016 refueling outages. Our forced outage performance continues to be extremely strong, setting us up well for CP. And pay for performance capacity constructs in both PJM and New England. We begin the 2019, 2020 PJM capacity auction this week, with results expected to be announced on May 24.

As usual, we're not providing a forecast of the auction results. But we see better behavior around economically and environmentally challenged assets as the key driver of the outcome.

On the safety front, we continue to make meaningful strides to improve our safety track record as evidence in the chart on the bottom right of the slide. But we remain highly focus on achieving even better levels of safety performance.

Turning now to market updates beginning with PJM on slide 7. I would broadly highlight that we've seen an improvement in forward gas and power pricing in all markets since the end of February.

Outside of just the pricing improvement in PJM that you can see in the graphs, we secured key victories at the Supreme Court, US Supreme Court, and the Maryland and New Jersey litigation on subsidized new gas builds. And from FERC, and the Ohio attempt to subsidize existing merchant generation. Maintaining a level playing field among competitors is an essential element to having well-structured transparent and functioning markets that encourage sensible investments in existing and new generation resources.

Now moving to the ERCOT market on slide 8. Pricing has improved from very low levels in late February, but continues to present challenges for coal and nuclear generators in that market. With wind penetration reaching almost 50%, quick-start gas assets like those in our Texas portfolio become even more valuable for system reliability. Recent forecasts of potential shortness in the market for the next few summers bodes well if we get any type of help from the weather. We saw that with just two weeks of heat last summer.

In the New York ISO, with the temperate weather and low seasonal gas pricing, we are getting good run times at Athens. We've seen some modest improvement in [forward] prices over the past two months. And even though the Constitution pipeline has been delayed, both spark spreads and energy prices have improved in the short-term. Based on the public comments from the developers of the pipeline, and the fact that the pipeline is fully subscribed, we expect the developers will be pursuing options to move forward with that project.

Finally, turning to a New England 2017, 2018 power prices are up modestly since our last update, with spark spreads flat to down on a recent spike in forward gas in the region. ISO New England will implement zonal demand curves for the 2020, 2021 forward capacity auction. We expect this to put gradual downward pressure on capacity prices, due to the transition that was negotiated by the generators.

On slide 11, we provide updated hedge levels and margin sensitivities. We've increased our 2016 generation hedge levels across the board, which reflects a combination of Q1 delivered results, and some modest balance of year hedging.

For 2017, we layered on some additional hedges for the East Nuclear and Coal assets prior to the end of the quarter. And we're about a third hedge based on our projected output at March 31. Since that time, we have seen some additional improvement in pricing. And have added additional hedges that take the hedge level to over 60% for Easter Nuclear and Coal. In the West we added some hedges for the summer for ERCOT for both 2016 and 2017.

I will now turn the call over to Jeremy for a more detailed look at the financials. Jeremy?

Thanks Paul. On slide 13, you will see some of the key drivers over first-quarter adjusted EBITDA, as compared to the same quarter last year. Overall margins were higher, due principally to the addition of RJS and MACH Gen margins that were not part of last year's first quarter results as well as higher capacity prices. Offsetting these positive margin drivers were lower realized energy prices, timing of the Susquehanna refueling outage, and the early February sale of the Ironwood facility.

The increase in O&M reflects the addition of RJS and MACH Gen Operations as well as the Susquehanna refueling outage timing. The increase in cost is partially offset by lower corporate cost following the separation from PPL.

Let's turn to slide 14. As Paul previewed in his remarks, we are affirming and updating our guidance at the same time. We believe our solid operational performance, our hedging program, and our continuous efforts to control costs will keep us on track versus our 2016 guidance.

You will recall we initiated our 2016 guidance, that we do not include any anticipated contributions from the mitigation assets. Now that those sales are complete, we know with certainly what they contributed towards the 2016 results. The net result is a $20 million increase to our 2016 adjusted EBITDA guidance and a $10 million increase to our 2016 adjusted free cash flow guidance. We have provide these adjustments so that our guidance will more closely align with our reported results, as we move through the year.

Before I turn it back to Paul, let's spend just a minute on capital allocation on slide 15. Please note that the we've updated the cash from operation in the chart on the bottom of the page to reflect first-quarter results, including the actual results from the assets sold in 2016, consistent with our guidance update.

We continue to stay the course with respect to our capital allocation that's discussed on the fourth-quarter call. We close the Hydro sale last month, which brought in $860 million of gross proceeds, completing the FERC mitigation requirement.

We are making good progress on the major potential projects that will influence our capital allocation decisions. We expect to have a decision on the Montour Station Project very soon as Paul indicated, and we continue our assessment with respect to the Harquahala Station.

We remain in discussions with various entities around potential local resource needs. And are simultaneously refining plans to potentially move all or a portion of the capacity to Northeast. As we have discussed in the past, moving some or all of our Harq would require capital investment beyond the current plan.

Finally, we continue to review our liability management options. Obviously bond prices have improved since our last update, which would be factored into our analysis. However, there other factors, such as managing the maturity calendar and reducing interest expense that are important to consider. With that, I'll had it back to Paul.

Thanks Jeremy. Our scripted remarks were fairly concise this morning as we gave you a pretty full sum update in late February on the year-end call on many fronts. We have had a very solid financial start to the year. Executed fully on the committed asset sales, identified further opportunity to reduce costs, and continued to advance projects that we believe will improve the profitability and risk profile of our portfolio.

Before we get into the Q&A session, given recent market rumors involving the Company, I want to take the opportunity to remind you that we do not comment or speculate on market rumors. We never have and we never will. Please keep this in mind as you craft your questions for us this morning. Operator, we are ready to take those questions.

(Operator Instructions)

Ali Agha, SunTrust.

Thank you, good morning.

Good morning, Ali.

First, a logistic question. So, to be clear, under your old way of reporting and showing us guidance, first-quarter results would have excluded the $20 million that is associated with assets that were eventually sold. Is that the way to think about it, apples to apples?

Yes, that's correct, Ali.

Okay. Then second, Paul, I wanted to get your perspective on this new joint venture that -- or venture, whatever you call it -- that Riverstone has formed in Texas. From just reading it, it appears to be a direct competitor of Talen. And I'm just wondering, they're being your largest shareholder, was there any discussion with you guys? I want to just get your perspective on how to look at that venture versus Talen. And it just confused me, reading through that release.

Yes, Ali, I don't think we have any comments on what Riverstone is doing. Basically that's just the Topaz team that was managing the RJS portfolio before we bought it, is our understanding. So, beyond that, and them renaming the team, we don't have a perspective on what they're -- I don't know what assets -- I don't think they have assets. But I'm not sure what to read into that actually.

Okay. But am I right in thinking that they will be going after fossil fuel projects just like you guys in your regular course of business? Maybe looking for fossil fuel assets as well?

Well -- and we had said when we conceived the spin that this did not represent the spin of the PPL portfolio, and the merger or acquisition of RJS, that, that did not mark the end -- that was not Riverstone exiting the business. And that they had the capability to pursue conventional generation assets in the future, which they had planned to do. Now, they market power limitations, based upon being an affiliate of Talen. But beyond that, they are free to continue to pursue those opportunities.

Okay.

Nothing's changed there.

I see. Separately, in the past, in one of your presentations, when you had talked about what could be uplifts to your EBITDA profile, you had mentioned that the [auto monies], Sapphire, and Longwood contracts, expiring I believe by the end of the year, would add about $60 million a year. And then you'll still have [that time thinking] the Brunner duel fuel would add about $25 million a year. Are those numbers still valid today?

The first number would still be valid. I have to believe -- and Joe's sitting here -- that Brunner, for 2016 especially -- because we had originally planned to bring all three units on by year end, we've now, with strong execution and construction, feel confident that we can get Brunner 3 -- the big unit, the 750-megawatt unit -- on by August. That will provide an uplift. But gas prices have declined since. So, the project is going to add more gross margin and look more attractive. There will be an offsetting impact on the other solid fuel assets in the portfolio, but that project will look better.

It will look better. Okay. Last question, not specifically trying to go off of these rumors out there. But, conceptually, your views on consolidation in the industry today, versus where they were three to six months ago

I don't think that I or we have necessarily a changed opinion. I think, even with some improvement in the multiples of our three peers -- this whole industry of four -- that the cash flows look compelling. I think that scale is important, that driving out cost is important. I would say that, as I think back on our experience in going after cost here, in the way that we went after cost as part of an integrated utility holding company, it's much different.

So I would say that, from my perspective, in looking at operators operating uneconomic plants in Ohio, and looking at some nuclear shutdown that's going on in the industry, getting after cost is much more, I'll call it, aggressive in an IPP context than inside of the utility holding company with common systems, common business processes. It is just a different urgency and a different culture.

So, I would expect that I would wholeheartedly support the remaining integrated -- the disintegrating in becoming peer plays, but I'm not really sure. You'd have to ask the other CEOs how they think about consolidation in the industry. Everything's obviously gets limited by, ultimately, market power. We're going to grind to that at some point, with only four companies in the key markets where there are market power concentrations.

Thank you.

Sure.

Julien Dumoulin-Smith, UBS.

Hey, good morning.

Good morning, Julien.

Let me follow up on those questions there on capital allocation. What's the timing this year on thinking through when you would execute on a (inaudible) debt payback or what have you, given the cash is now in the door?

The two key projects that pace our timing there are the Montour coal fire which, as Paul said, we expect in the coming weeks to have a final view on moving forward or not. And then the other is Harquahala. If part of the path to value there is moving some or all of that capacity, that what I could represent a really attractive return to shareholders will certainly require some substantial capital investment. So I think we just want to have clarity on that before we take all this capital and do something with it.

I know that the financing markets are getting better than they were, but they are not all better. Yet. So I think we're very cautious about doing anything in the capital markets to shrink our debt. And then suddenly realize, weeks or months later, oh gosh, we need to go out and raise a bunch of debt again to finance a Harq move. So we're trying to sort through all now. I think that still a first-half-of-year decision in terms of where we're moving. So I wouldn't really expect anything splashy on the capital allocation front before the end of the first half of the year.

Got it. And remind us, what's the Harq CapEx you figure you're looking at -- or, at least as you sharpen your pencils?

So that was -- we were originally at around [$500/kW] and we fined tuned that down to the $300 to $400 range. So on -- if all three trains were moved at 1,080 megawatts that's, call it, $325 million to $450 million, somewhere in that ZIP Code. If all three trains were moved. So, again, Julien, free up another $100 million or $200 million by selling in situ or move all three. Those are the book ends of -- but that's a potential $600 million range there of outcomes. And we are continuing to dialogue with load serving another entities in that market on the potential for sale. So, we're simultaneously evaluating both sale and relocation to markets in the mid-Atlantic and Northeast.

Got it. A clarification, trying to stay from the market rumors. But on the RMT, what are the limitations in terms of change in ownership? And the implications, if any, for PPL, if you don't mind reminding us on where that stands?

At this stage, there is not, practically, any limiting factors there.

You have a general safe harbor -- people have to seek their own tax advice, that's always the tax disclaimer, right? We're not your tax lawyers. But there's a general safe harbor that, provided any future transaction was not pursuant to a preconceived plan at the time of the spin, or prior to the time of the spin, then you are generally okay to do whatever. There is a coincidence in timing. The closer you are to that spin date, the more scrutiny there is. And the more inference that there was a preconceived plan. So, in general, if there was no preconceived plan to a transaction at the time of spin or prior to the spin, then you have a general safe harbor to proceed.

Got it. Can you comment briefly here on the kinds of units in PJM and the upcoming auction that you would see? I'm not clear -- I know you mentioned the economics here on the likely solid fuel. But can you elaborate a little bit more, regionally, or how you see that change year over year? Obviously, power prices are down. Any elaboration would be appreciated.

Look back on the 2018-2019 auction. There was a major unit in our neighborhood that, that owner said did not clear the auction. The nuclear promise activities are underway, but those have not borne, yet, substantial cost-reduction fruit. Tim is leading one of the initiatives there. And there are a number clearly underway, but that's going to take some time to get to. So, higher cost units in what remains a persistently low gas price market are going to be under pressure. The owners of the assets, I believe in all the testimonies that I've seen in Ohio, were all, quote, uneconomic generation, in the absence of getting subsidies. Well, then, those units should shut.

The markets work just fine. There are negative impacts to markets, given what actions EPA has taken and the impact of this cheap gas that exists and persists in the region. That's not a problem of poorly functioning markets. That has impacts. And so, there will be assets like Brunner and Montour that can be gasified. There will be nuclear plants that have margin to be able to cut costs. And then there will be solid fuel plants that are not in good locations, and where cost-cutting -- where the costs are either already at very low levels and not much more can be done. I don't fault people for trying to do certain things. But, at the end of the day, that is creating a -- that subsidization activity across all these markets is preserving uneconomic generation, which is having a downward pressure on both capacity and energy. So, those owners and other owners that are facing the impact of Marcellus, and now Utica, gas need to take a hard look in the mirror and make some tough decisions.

Speaking of tough decisions, any update on Montana, lastly?

No, we are working constructively with the parties in the state as we speak. We're doing everything we can to try to find a path to a new owner of those assets, which will result, at the end of the day, in some form or fashion of our exit from the market. So we're working diligently to try to execute that in the best way possible for all the stakeholders -- for employees, for the state, industrial load -- for all involved there to try to find the best solution that we can.

Great, thank you.

Sure.

Abe Azar, Deutsche Bank.

Good morning. In the 2018-2019 PJM auction, about 20% of your portfolio went uncleared. With lower demand than expected pricing in this upcoming auction, should we expect a similar amount of megawatts will remain uncleared? Or have you revisited your risk assumptions for [CP]?

Abe, I would say a couple of things. One, that amount, that roughly 2,200 to 2,500 megawatts [show] that did not clear, also included assets that we have now sold as part of the FERC mitigation process. So that would be one point. The second point I would say is, that auction obviously concluded before the transitional auctions for the prior years. And you'll note that we cleared more capacity in those auctions. So, as we evaluated what the market did, by way of bidding, we did modify our bidding behavior somewhat.

So I think, again, we'll -- I don't see us changing the way that we think about the risk/reward relationship. And there are projects that we know, and megawatts that cleared, that have since been announced to be shuttered. So, ultimately, there's going to be demand in subsequent auctions for the modest amount of capacity net of FERC mitigation sales that we've got. And the amount that we want to reserve for our own insurance -- I'm using my air quotes that you can't see -- for asset performance in the future. Even though we've got assets that have a really good track record of reliability.

Great. And shifting gears a bit. You mentioned that FERC revoked affiliate waivers. As we have seen, companies have not given up. Do you think the current proposed iteration impacts the market the same way? And, if so, where and how do you plan to challenge it?

Well, maybe a couple of thoughts. I don't think that, even at the state level, there's a resolution before the capacity auction results are in -- not just the results, the bidding activity is done the 17th, and then the results come out May 24. So, nothing's going to be finalized in two weeks. So, they will have to bid accordingly. And how they see risk reward there.

I don't think by changing the fact that there's no affiliate contract -- the substance, at the end of the day, and the result is the same. Uneconomic generation is subsidized, and it has an impact on wholesale pricing in the market. And that's a FERC jurisdictional issue. We will -- to the extent that these things are filed, we will likely have to, with our peers, engage. Peers that are viewing subsidies as unwarranted and impermissible will bring another challenge back at the state and federal level again, I'm certain, if they pursue that.

Okay, thank you.

Sure.

Srinjoy Banerjee, Barclays.

Thank you for taking my questions. Apology if it has asked previously in the call, but, just hypothetically, and going into the debt language, in terms of change of controls, is it just the [25s] which have a change of control? And then, specific to that, are there any carve-outs, depending on who may hypothetically acquire the group?

There's -- it's that $600 million and a little north of $200 million of IRB, industrial revenue bonds, that are outstanding that would have a potential change of control acceleration -- if there were to be a ratings downgrade, as a result of a potential transaction.

That's a rating of the issue itself, not of the Company.

Correct.

Right.

But that's all that there is.

Okay. And [there are no] carve-outs seen as specific to who may acquire the group?

Sorry? I missed that last piece.

There aren't any carve-outs or exceptions to that change of control being applied specific to who may acquire the group?

No.

No.

Okay, thank you.

Sure.

There are no additional questions at this time. This concludes our question-and-answer session.

Okay. Thanks, Kate. And thank you all for joining us on the call today. We look forward to further dialogues, as we get into potentially some road shows, and then, later in the year, as we get to the normal conference schedule. Thanks all and have a good day.

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