Talen Energy Corporation (TLN) Q1 2016 Earnings Report, Transcript and Summary

Welcome to the Talen Energy First Quarter Result Conference Call. All participants will be in listen-only mode. [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 slide to 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 a 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 the most directly comparable GAAP measures in the schedules to our earnings release and the presentation that we 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 has lead 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 a more detailed review of the financial performance and our forecast, and we’ll then take questions. We are about three week shiny anniversary of the spin and the acquisition of the RJS portfolio, and I'm extremely proud of the efforts and the accomplishments of our entire team over the past two years of planning and execution. We’ll touch on 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 asset sales, all of which were executed at great values in competitive processes. Our Brunner Island co-fire project remains on schedule which should permit us to bring gas in Unit 3 by August and the smaller two units by the end of the year. We made significant progress on the Montana project evaluation as well and expect to have a final decision on that in the next two weeks. That project is expected to be executed all differently than Brunner Island and that we are working with the midstream company to finance, construct and operate the lateral pipeline. Since the Brunner Island project has a much smaller 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 heat water heaters and the 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 schedules in the spring of 2018. I want to thank the entire Susquehanna team for staying focused on safe execution of this work, all well keeping Susquehanna Unit 2 running at a capacity factor of 100% for 10 months in County, fantastic work by all. The great operating performance and the 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 yearend 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 plans and our evaluation of a similar investment at modular assets. 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 well for CP and pay for performance capacity constructs in both PJM and New England. We began the 2019, 2020 PJM capacity auction this week with results expected to be announced on May 24t. As usual, we are not providing a forecast to the auction results, but we see better behavior on economically and environmentally challenge assets as a key driver of the outcome. On the safety front, we continue to make meaningful strides to improve our safety track record as evidenced in the chart on the bottom right of the slide, but we remain highly focused 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 graph, we secured key victories at the U.S. Supreme Court in the Maryland and New Jersey litigation on subsidize new gas bills and from FERC in 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 ERCOT, 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 ours that goes in our Texas portfolio become even more valuable for system reliability. Recent forecast 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 tempered weather and low seasonal gas pricing, we’re getting good runtimes in assets. We’ve seen some modest improvement in forward prices over the past two months, and even though the constitution pipeline is 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 this pipeline is fully subscribed, we expect the developers will be pursuing options to move forward with that project. Finally, turning to New England, 2017-2018 power prices are up modestly since our last update with spark spreads slapped down on a recent spike and forward gas in the region. ISO New England will implement rental demand curves for the 2020-2021 forward capacity auctions. We expect this will gradual downward pressure on capacity prices due to the transition that was negotiated by the generators. On Slide 11, we’ll provide updated hedge levels and margin sensitivities. We have increased our 2016 generation hedge levels across the board, which reflects a combination of Q1 delivered results and some modest balance of your hedging. For 2017, we were 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 East nuclear and coal. In the West, we added some hedges for the summer for both 2016 and 2017. I’ll now turn the call over to Jeremy for a more detailed look at financials. Jeremy?

Thanks Paul. On Slide 13, you will see some of the key drivers of our 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. They were not part of last year's first quarter results as well as higher capacity prices. Offsetting these positive margin drivers will lower realized energy prices, timing of the Susquehanna refueling outage in 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 was partially offset by lower corporate costs following the separation from PPL. Let’s turn to Slide 14. As Paul previewed in his remarks, we’re affirming and updating our guidance of same time. We believe our solid operational performance, our hedging program and our continuous efforts to control costs we’ll keep this on track versus our 2016 guidance. If you recall when we initiated our 2016 guidance that we did not include any anticipated contribution from the mitigation assets. Now that the sales are complete, we know a certainty what they contributed towards our 2016 results. The net results as the $20 million increase to our 2016 adjusted EBITDA guidance and a $10 million increased to our 2016 adjusted free cash guidance. We’ve provided these adjustments so that our guidance will more closely aligned with our reported results as we move through the year. Before I turn it back to Paul, let spend just a minute on capital allocation on slide 15. Please note that we have updated the cash from operations in the chart on the bottom of the page reflect first quarter results, including the actual results for the asset sold in 2016 consistent with our guidance update. We continued to stay the course with respect to our capital allocation as discussed in the fourth quarter call. We closed our hydro sale last month which brought in $860 million from 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 Montana station project very soon as Paul indicated and we’ll continue our assessment with respect to the Harquahala station. We remain on discussions with various entities around potential local resource needs and we’re simultaneously refining plans to potentially move all or a portion of the capacity to the Northeast. As we’ve discussed in the past moving summer all of park would required capital investment beyond the current plan. Finally, we continue to review our liability management options, obviously on-prices have improve since our last update which will be factored into our analysis. However, there are other factors such as managing the maturity calendar and reducing interest expense, therefore consider. With that, I’ll hand it back to Paul.

Thanks Jeremy. Our scripted remarks were fairly concise this morning as we gave you a pretty fulsome update in late February on the yearend call on many fronts. We’ve had a very solid financial start to the year, executed fully on the committed asset sales, identify further opportunities to reduce costs and continue to invest projects that we believe will improve the profitability and risk profile of our portfolio. Before we get in 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’re now ready to take those questions.

[Operator Instructions] The first question comes from Ali Ahga of SunTrust. Please go ahead.

Thank you and good morning.

Good morning. Ali.

Good morning. First just 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?

Yeah, 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, the Riverstone has harmed in Texas. From this reading it appears to be a direct competitor of Talen, and I am just wondering as they 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 talent? And just excuse me to reading through that release.

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 then renaming the team, we don’t have a perspective on what their - 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, we had said at when we conceived the spin that this did not represent the spin of PPL portfolio and the merger or acquisition of RJS that did not mark the - that was not a Riverstone exiting the business and that they had the capability to pursue congressional generation assets in the future, which they had planned to do. Now they have market power limitations based upon being an affiliate of Talen, but beyond that they are free to continue to pursue those opportunities, nothing change 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 add of money shall find in Longwood contracts expiring I believe at the end of the year would add about 60 million a year, and then you were still at that something in the Brunner dual-fuel would add about 25 million a year. Are those numbers still valid today?

The first number will still be valid. I have to believe in Joe sitting here that Brunner for '16 especially because we had originally planned to bring all three units on by yearend. We've now with strong execution and construction, we feel confident we can get Brunner 3 the big Unit to 750 megawatts unit on by August. That will provide an uplift, but gas prices have declined since, so the project is going 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 looks better. Okay. Last question, not specifically trying to go after these rumors out there, but just 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 were compelling. I think that scale is important that driving out cost is important. I guess I would say that as I think back on our experience in going after cost here, in the way that we went after a cost as part of an integrated utility holding company it’s much difference. So I would say that from my perspective and looking at operators operating uneconomic plants in Ohio, and looking at some nuclear shutdown that’s going on in the industry, getting after costs is much more, I guess I’ll call it aggressive in an IPP context and inside of the utility holding company with common systems, common business processes, it’s just the different urgency in a different culture. So, I would expect and I would wholeheartedly support the remaining integrated, the disintegrating and becoming carefully, but I am not really sure you have to ask the other CEO is how they think about consolidation in the industry. Everything is 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.

The next question comes from Julian Dumoulin-Smith of UBS. Please go ahead.

Good morning.

Good morning, Julian.

So let me follow-up on the questions there on capital allocation, Jeremy, what’s the timing this year on taking through when you would execute on a growth that stay back or what have you given the cash is now in the door?

Yeah. So I think the two key projects that pace our timing there are the Montana co-fire which just 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 value there is moving summer all of that capacity that - what can represent a really attractive return to shareholders. It will certainly require some substantial capital investment. So I think we just want to have clarity on that before we take this all as capital and do something with it. I know the markets are - the financing markets are getting better than there were, but they are not all better yet. So I think we are very cautious about doing anything in the capital markets to shrink our debt, and then suddenly realize in weeks or months later, oh gosh we need to go on raise a bunch of debt again to fence a hard move. So we are just trying to sort, draw all that now, I think that still a first half of year decision in terms of where we are moving. So I wouldn’t really expect anything splashy on the capital allocation front before the first half of the year.

Got it. And just remind us what the hard CapEx figure you're looking at as you sharpen the pencils?

Yeah. We were originally at around 500 KW and we fine tune that down to $300 to $400 range so on, if all three trains were moved at 1080 megawatts, that’s call it 325 million to 450 million some more in that ZIP code, if all three trains are moved. So, again Julian, it’s free-up another $100 million or $200 million by selling it in-situ or move all three, those are kind of the bookends, but that’s a potential $600 million range there of outcomes. We are continuing the dialogue with load serving and other 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. And just a clarification, I’m just going to stay away from the market rumors, but on the RMT what are the limitations in terms of change in ownership and any implications if any for PPL, if you don’t mind reminding us on where that stands post there?

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

We have a general safe harbor, I mean people have to ticker on tax advice, I mean there is always a tax disclaimer right, we are not your tax lawyers. But there is a general safe harbor that provided any future transaction was not pursuant to preconceived plan at the time of the spin or prior to the time of the spin, then you're generally okay to do whatever. It’s just there is a coincidence in timing, the closer you are to that spin date, the more scrutiny there is and the more sort of inference that there was a preconceived plan. But in general, there was no preconceive plan to a transaction at the time of spin or prior to the spin then you’d have a general safe harbor proceed.

Got it. Can you comment briefly here on the kinds of unit in PJM in the upcoming auction there you’ve seen - I know you mentioned the economics here - like we saw on fuel, but can you elaborate a little bit more regionally or how you see that changing year-over-year obviously power prices down, any elaboration we appreciate?

Well, I mean just look back on the 18-19 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 haven’t born yet substantial cost reduction fruit. Tim is leading one of the initiatives there and there are 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 market worked just fine. There are negative impacts to markets given what the 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 impact. So, they'll 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 were cost cutting where the costs are either already at very low levels and not much more can be done it. 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 gap need to take a hard look in the mirror and make some tough decisions.

Speaking to tough decisions, any update on Montana lastly?

No. We are working constructively with the parties in the state as we speak. We are doing everything we can to try to find the 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 that 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.

The next question is from Abe Azar of Deutsche Bank. Please go ahead.

Good morning. In the 2018-2019 PJM auctions, about 20% of your portfolio went uncleared with lower demand and expect the pricing in its upcoming auction. Should we expect the similar amount of megawatts will remain uncleared or have you revisited your risk assumptions for CP?

Well, I would say, Abe, I’d like to say a couple of things. One, that amount that roughly 2200 to 2500 megawatt so that didn’t clear also included assets that we have now sold as part of the FERC mitigation process, so that will 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 know that we cleared more capacity in those auction. So as we evaluated with the market did by way of bidding, we did modify or bidding behavior somewhat. So I think again, I don't see us changing, think about the risk reward relationship and there are projects that we know and megawatts are cleared that have since been announced to be shuttered. So ultimately, there is 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 am using my [indiscernible] so you can’t see four 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 were affiliate waivers as we have seen the company have not given out. Do you think the current proposed iteration impacts the market the same way, and if so, where and how do you plan to challenge?

Well, maybe a couple of thoughts. I don’t think that even at the state level there is a resolution before the capacity auction, results are in - well, not just the result, you know the bidding activity is done the 17th, and then the results come out May 24, so nothing is going to be finalized in two weeks. So they’ll have to do it accordingly and how they see risk reward there, I don't think by changing the fact that there is 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 in certain if they pursue.

Okay. Thank you.

The next question is from Srinjoy Banerjee of Barclays. Please go ahead.

Hi. Thank you for taking my questions. Paul you could have been asked previously in the call, but just hypothetically and going into the debt language, it doesn’t change your controls, is it just a 25 which have a change of control? And then specifically, are there any callouts depending on you may hope hypothetically acquire the group?

Is that $600 million and about 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 rating downgrade as a result of potential transaction.

That’s the rating of the issue itself not of the company.

Correct. That’s all the….

Right. Oaky. And then there are any callout as specific that you may acquire the group?

Sorry. I missed that last piece.

There was a callout or exceptions to that change you can control being apply specific that you 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 dialogue 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.