第一能源 (FE) 2015 Q4 法說會逐字稿

Greetings and welcome to the FirstEnergy fourth-quarter 2015 earnings conference call.

(Operator Instructions)

As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Meghan Beringer, Director, Investor Relations. Thank you, you may begin.

Thank you, Adam, and good morning. Welcome to the FirstEnergy's fourth-quarter earnings call.

We will make various forward-looking statements today, regarding revenues, earnings, performance, strategies, and prospects. These statements are based on current expectations and are subject to risks and uncertainties. Factors that could cause actual results to differ materially from those indicated by such statements can be found on the investors section of our website under the earnings information link and in our SEC filings.

We will also discuss certain non-GAAP financial measures. Reconciliations between GAAP and non-GAAP financial measures are also available on our website. Please note that on the investor relations page of our website, we have also included a slide presentation that will follow this morning's discussion.

Participating in today's call are Chuck Jones, President and Chief Executive Officer; Jim Pearson, Executive Vice President and Chief Financial Officer; Leila Vespoli, Executive Vice President, Markets and Chief Legal Officer; Donny Schneider, President of FirstEnergy Solutions; John Taylor, Vice President, Controller, and Chief Accounting Officer; Steve Strah, Vice President and Treasurer; and Irene Prezelj, Vice President, Investor Relations.

Now I would like to turn the call over to Chuck Jones.

Thanks, Meghan. Good morning, everyone. I'm glad you were able to join us.

I'm excited to share the results from an important and productive year for FirstEnergy. In 2015, we made tremendous progress on major initiatives across our Company. We put a number of obstacles behind us and completed critical work necessary to implement our regulated growth strategy going forward.

At the same time, we consistently met our financial commitments to you. Last night, we reported operating earnings of $0.58 per share for the fourth quarter and $2.71 per share for the year.

These results, which reflect improved operations at our competitive business, as well as growth in our transmission business, are above our initial guidance range for 2015. And in line with our revised estimates that we provided during our third quarter call, despite the mild weather we experienced in the fourth quarter.

For the first quarter of 2016, we have provided operating earnings guidance of $0.75 to $0.85 per share. As we will discuss later, we intend to provide additional guidance, once we have an outcome in our Ohio electric security plan.

Before we move to Jim's financial review, I will take a few minutes to discuss the key events from 2015. First, we removed regulatory uncertainty and took important steps to position our regulated utilities for growth, with the conclusion of rate cases in West Virginia, New Jersey, and Pennsylvania. Resolving these cases allows us to plan for additional infrastructure and reliability investments at those utilities.

In Pennsylvania, we took that next step by filing long-term infrastructure improvement plans for each of our four operating companies in October. These plans, which were approved by the Pennsylvania Public Utilities Commission last week, outline a projected increase in capital investment of nearly $245 million over five years to help strengthen, upgrade, and modernize our Pennsylvania distribution systems. Yesterday, we filed for approval to implement a distribution system improvement charge at each of the four operating companies, which would allow us to recover quarterly costs associated with the capital projects approved in the LTIPs.

In Ohio, we achieved an important milestone for our latest electric security plan, by reaching a settlement agreement with the staff of the Public Utilities Commission of Ohio and 16 other parties, including EnerNOC, an energy management solutions provider, Ohio Partners For Affordable Energy, a low-income customer advocacy group, and IGS Energy, an independent energy supplier. The agreement outlines ambitious steps to safeguard Ohio customers against retail price increases and volatility in future years, deploy new energy efficiency programs, and provide a clear path to a cleaner energy future by reducing carbon emissions.

Our settlement includes an 8-year retail rate stability rider, associated with the proposed purchase power agreement. This provision will help protect customers against rising retail prices and market volatility, while helping preserve vital base load power plants that serve Ohio customers and provide thousands of jobs in the state. The PPA includes the Sammis plant in Stratton, Ohio, the Davis-Besse nuclear power station in Oak Harbor, Ohio, which recently received approval from the nuclear regulatory commission for a 20-year license extension, and a portion of the output of two OVEC plants.

The procedural schedule for our Ohio case is nearly complete, with hearings concluded, initial briefs filed, and reply briefs due next Friday. A decision from the PUCO is expected in March. Clearly, there is a lot of talk about the PPA, as all interested parties seek to have their voices heard.

We firmly believe that our plan serves the best interest of Ohio customers and Ohio communities, while supporting competitive markets in the state and PJM. This generation will continue to be offered into PJM's energy and capacity markets, and the PPA will have no impact on our standard service offer, or customer's ability to shop for their retail electric supply. In fact, we expect that the output from these plants will be treated no differently than the 20% of regulated generation that currently clears in the PJM markets and that 20% does not include imports into PJM, which from MISO would be primarily regulated generation.

I'm sure you will have a lot of questions about the legal and regulatory process and Leila is standing by to share our perspective during the Q&A. We believe our plan is the right one for Ohio and we remain optimistic in the outcome, both in Ohio and at FERC.

Let's turn to our transmission business. We just passed the halfway point of the first phase of our Energizing the Future transmission investment initiative to meet the reliability needs of our customers and communities. We remain on track to meet our target of $4.2 billion in spending during the 2014 through 2017 timeframe.

Consistent with our plan, we spent $2.4 billion in 2014 and 2015, including $986 million last year, on projects to address service reliability, grid modernization, and growth. We completed major initiatives to address last year's Northeast Ohio plant deactivations, and brought online critical new infrastructure to support midstream gas operations in our region.

Work in 2016 is expected to include $1 billion in investments on projects such as synchronous condensers at our Eastlake plant, new line construction projects in West Virginia and New Jersey, Static VAR Compensator projects in Pennsylvania, New Jersey, and West Virginia, and several new substations, line rebuilds, and re-conductoring projects. While expansion in the shale market has cooled, we expect investments over the next several years of about $150 million for work that is already in the pipeline.

We also addressed several matters in 2015 that support future investment in this important long-term growth platform. During the fourth quarter, FERC approved our settlement for a forward-looking formula rate structure at ATSI subsidiary, which permits more timely recovery of our investments. In addition, in June, we filed to create a new subsidiary named Mid-Atlantic Interstate Transmission or MAIT. This subsidiary would hold the transmission assets of Met-Ed, Penelec, and JCP&L, and facilitate new investments that can improve service reliability for those customers.

Our proposal is on FERC's agenda for tomorrow and we are seeking approval from both the Pennsylvania Public Utilities Commission and the New Jersey Bureau of Public Utilities by the middle of the year. These structural changes are important steps to ensure timely recovery of our investments and set the stage for continued growth through our Energizing the Future transmission initiative.

Turning to our competitive operations, the PJM capacity market reforms approved by FERC have already begun to have a positive impact on the capacity auction process. Although the markets continue to fall well short of being compensatory for long lived capital asset like base load generation units.

Our revised competitive strategy, focusing on stabilizing the business by reducing risk, also produced positive results. In 2015, we sold 75 million megawatt hours, while significantly reducing our exposure to weather sensitive load and executing a rigorous commitment to economically dispatching our units. As result, we mitigated the impact of severe weather in the first quarter of 2015 and achieved adjusted EBITDA of $949 million.

This is in line with the revised guidance that we provided in October and reflects solid operational results, as well as the impact of our cash flow improvement project. We are holding off on providing adjusted EBITDA guidance for 2017 and 2018 until our analyst meeting following the PUCO decision in Ohio.

However, we are reaffirming both our 2016 adjusted EBITDA guidance range for the competitive business of $950 million to $1.05 billion and our expectation that the business will be cash flow positive each year through at least 2018. Before I move from our competitive segment, I will mention that given the significant decline in the global coal market, we impaired our investment in the Signal Peak mine, resulting in a $362 million pretax non-cash charge, which Jim will cover in more detail.

Finally, I will spend a few moments discussing our cash flow improvement plan and other financial matters. We took a very important step to improve our financial metrics and balance sheet in 2015, through the launch of our cash flow improvement project. This initiative began in the spring, with the goal to capture meaningful and sustainable savings opportunities and process improvements across the Company, while continuing to fully meet the needs of our customers, our organization, and our employees.

I'm very pleased with the results of this effort to date. We are on track to capture $155 million in savings this year, and $240 million annually by 2017, up from our initial goal of $200 million over the timeframe. The results from this initiative will allow us to essentially hold our O&M flat through 2017.

We put a lot of risk behind us in 2015, including key initiatives that provide our Company with greater strength and flexibility as we pursue our regulated growth plans. I am also gratified by the response from the rating agencies.

In December, citing our shift in strategy and more credit-friendly business risk profile, Fitch revised its outlook from stable to positive. Days later, Moody's affirmed it's Baa3 rating, with a stable outlook for FirstEnergy corporation, FES, and Allegheny Energy Supply, citing our Ohio ESP settlement.

Over the past year, I have gotten to know many of you and have shared my leadership philosophy, including my commitment to make our company more transparent. I hope you have seen that in action over the past year.

I have told you one of our primary objectives is to improve the quality of our earnings. This year, two significant non-cash adjustments got in the way. The annual mark-to-market for pension and OPEB will remain an annual adjustment, either up or down. And the impairment of the Signal Peak coal mine is required, given the current market for coal and the fact that this is not a core asset for us.

Outside of these two items, earnings quality in 2015 was very solid and supported with operational cash flows that showed an $700 million improvement over 2014. We are making solid progress and once we have an outcome in our Ohio ESP, we should be in a position to provide 2016 full year earnings expectations and shed more light on the next couple of years, including our regulated growth projections, and any future equity needs to support our growth initiatives.

It remains our priority to continue strengthening our balance sheet and further de-risk our competitive business. These steps will help ensure we are well positioned to pursue the next period of regulated growth and success, benefiting our six million customers and the local economies we serve, our investors, and our employees.

Now I will turn the call over to Jim for a brief review of the quarter. As always, we reserve plenty of time for your questions before the end of the hour.

Thanks, Chuck, and good morning, everyone. As always, I will remind you that detailed information about the quarter can be found in the consolidated report that was posted to our website yesterday evening. We also welcome your questions during the Q&A or following the call.

Our fourth quarter operating earnings of $0.58 per share compares to $0.80 per share in the fourth quarter of 2014. On a GAAP basis, we have reported a loss of $0.53 per share for the fourth quarter 2015, compared to a loss of $0.73 per share during the same period last year.

2015 fourth quarter GAAP results include special items totaling $1.11 per share. I will spend a few moments on two of those items before moving to the review of operating results.

The first of these is the impairment charge related to our investment in the Signal Peak mine. As Chuck mentioned earlier on the call, given the weak market for coal globally, in the fourth quarter we wrote off our investment in Global Holding, the parent company of Signal Peak, resulting in a non-cash pretax charge of $362 million, or $0.56 per share, which reduced the value of this investment to zero.

As some of you may remember, back in 2011, FirstEnergy sold a portion of its ownership interest in Signal Peak, receiving $258 million in cash proceeds and recognizing a $370 million after-tax gain, which included a sizable step up in the one-third interest we retain. Presently, the mine remains operational and FirstEnergy continues to provide a full guarantee on Global Holdings $300 million term loan. Since this investment is no longer a strategic fit for FirstEnergy, we have moved the earnings associated with Signal Peak from our competitive segment to corporate other for all periods.

The second special item is the $0.35 per share annual pension and OPEB mark-to-market adjustment, another non-cash item. As discussed in our third quarter call, we anticipated discharge, given the plans investment performance, which was partially offset by a 25 basis point increase in the discount rate. I will note that for 2016, we have $381 million in required minimum pension funding, with $160 million already contributed to the plan last month.

Let's spend some time walking through the fourth-quarter drivers by business units, followed by a brief review of the full year. In our distribution business, total deliveries decreased 6% in the quarter, or 2% on a weather-adjusted basis. Residential sales decreased 10.6% and commercial sales decreased 3.4% compared to the fourth quarter 2014.

Our regions of the mildest fourth-quarter temperatures in at least 35 years, with heating degree days that were nearly 30% below both last year and normal. The decrease in customer use also reflects the adoption of energy-efficient lighting and the impact of other energy efficiency measures. We continue to analyze these efficiency trends, and we plan to discuss the expected impact on our load forecast over the next few years when we hold our analyst meeting.

Sales to industrial customers decreased 3.9% in the quarter as a result of lower usage from our steel, mining, chemical, electrical equipment, and manufacturing customers, partially offset by increase usage of the shale gas and automotive sectors. Distribution results were also impacted by higher operating expenses, which included planned reliability spend in the quarter, primarily at JCP& L.

In our transmission business, fourth quarter operating earnings increased as a result of higher revenue associated with a higher rate base and ATSI's forward-looking rate structure, which became effective in January, 2015, partially offset by lower return on equity at ATSI as part of its comprehensive settlement that was approved by FERC in October.

In our competitive business, we recorded strong fourth quarter operating earnings, as higher commodity margin was offset by higher operating expenses. The impact of lower contract sales was offset by higher capacity revenues, lower purchased power, fuel and transmission expenses, and increased sales to the wholesale market, reflecting our more open position. Operating costs for the competitive business were higher in the fourth quarter 2015, primarily due to expenses related to the nuclear refueling outage at Beaver Valley unit 2.

Finally, at corporate, a higher effective income tax rate and higher interest and operating expenses reduced operating earnings by $0.08, in line with our expectations. Now I will take a couple of minutes to discuss full-year results and review the key earnings drivers for 2015.

Operating earnings were $2.71 per share, compared to $2.56 in 2014. GAAP earnings were $1.37 per share in 2015, compared to $0.71 in the prior year. At our regulated distribution utilities, 2015 operating earnings were in line with our guidance.

The net benefit of resolved rate cases and generally favorable weather was offset primarily by higher operating expenses associated with planned reliability maintenance. Total distribution deliveries decreased about 1% compared to 2014.

In the industrial segment, sales declined primarily due to decreased steel and mining production. Sales to residential and commercial customers were essentially flat compared to the prior year. In the regulated transmission segment, operating earnings increased, primarily as a result of a higher rate base and a forward-looking rate structure at ATSI in the Company's regulated transmission business.

In our competitive business, operating earnings increased significantly, primarily due to improved commodity margin related to higher capacity prices. Adjusted EBITDA was $949 million, in line with our expectations. You will recall that we began the effort to reposition our sales portfolio in the second quarter of 2014.

Our total retail customer count at the end of 2015, was 1.6 million, a decrease of 445,000 from December 31, 2014. We sold about 75 million megawatt hours in 2015, including 68 million megawatt hours of contract sales and an additional 7 million megawatt hours of wholesale.

We currently have about 61 million megawatt hours committed for 2016. And for 2017, about 38 million megawatt hours are committed, or about half of our expected generation resources.

The Ohio PPA would add approximately 23 million megawatt hours on an annual basis, which was essentially close our sales positions through the first half of 2017. In the corporate segment, 2015 operating earnings were consistent with our guidance, reflecting higher interest and operating expenses, as well as a more normal effective income tax rate.

2015 should be recognized as a pivotal year for our country company. We were able to raise the operating guidance that we provided, reduce risk, and build a solid platform for regulated growth. We are confident that our efforts will help us reach our goal of creating long-term value for FirstEnergy shareholders.

Now I would like to open the call up for your questions.

(Operator Instructions).

Stephen Byrd, Morgan Stanley.

I wanted to discuss transmission spending opportunities. In your fact book, I think it is slide 45, you talk about a review of the reliability in your ATSI system and maybe this should be phrased more broadly, but I just wanted to check in terms of as you assess transmission needs, replacement of 69 kv lines, 138 kv lines, what is your sense in terms of the potential for additional spending to enhance reliability, in transmission in particular?

Well, Stephen, we've talked about this a little bit in the past. Our team has identified in excess of $15 billion of projects that we could execute, all on our existing 24,000 miles of transmission lines, and that is our focus. What we do with those projects is prioritize them in the best way to drive benefits for customers. And my view is that the best investments we can make are the ones that customers are willing to pay for and that you all are willing to invest in.

The opportunity is there for us to make these kinds of investments for a long time. The ability to add, on an annual basis, to that is a little bit challenged by the availability of a transmission construction workforce in our country. So I would not expect that you would see a huge increase on an annual basis, but you could extrapolate out quite a bit into the future how long we can continue to execute this program.

That's very helpful. That makes sense. I wanted to shift over to the Ohio PPA discussions. I'm sure there will be many questions on this.

At the FERC level, I guess, comments are due February 23rd or thereabouts. I know this is obviously not your preferred outcome, but if the FERC case were to go in opposition to the PPAs, could you talk a little bit about what the implications might be, understanding again that is not your preferred outcome?

Hi, Stephen. This is Leila. I do not think it is the likely outcome either. Let me spend a couple of seconds, to recount for the group what that would've actually entailed to get to that place.

So right now we have an affiliate waiver, and the basis upon which it was granted, those items have not changed. If you think about it, Ohio still, the customers are not captive. They can shop. There has not been a law change. That means that the Ohio commission is still, in order to approve the PPA, would have to find that the ESP is better than the MRO. They would still be protecting customers.

So if you look at those kinds of things, again I don't think that it is something that the FERC should rescind, if you would, but if they were to do that, what would happen? They would likely apply the Edgar rule. You could look at the different provisions of how they look at that.

There are several ways to comply with the Edgar rule and one of them look set non-price terms and conditions. We would be looking at a hearing dealing with our PPA, on I think there are a lot of things that could be said around the non-term pricing conditions that would allow the pricing to stand as well.

Understood. Thank you very much.

Gregg Orrill, Barclays.

Thank you. Two questions. The first one is regarding the competitive business guidance for 2016. I guess it was the same as it was in the third quarter look, despite the fact that wholesale power prices are down. Could you talk about what the drivers there were?

Sure, Gregg. This is Donny. If you take a look at our slide 104 of the fact book, you can see the EBITDA guidance. As you clearly indicated, the falloff in prices, we reflected that in our open position. We are down about $3 there. But we have also lowered our cost, especially our fossil fuel we went back and took another hard look at some of the things we had done in CFIP and we were able to lower that.

Net of those two things, the lower revenue from the decline in the open position, net of what we have been able to do on the cost side, our commodity margin is only down about $15 million, which is well in the range of our EBITDA.

Okay, thank you. And then regarding the equity needs, can you talk about your thoughts there in light of some of the write-offs and funding needs that you have?

I have said really consistently that we have set a goal of strengthening our balance sheet and getting to where we need to get with the rating agencies, without having to use any equity having to do that. I just do not believe that is the intent of shareholder equity. We worked very hard this past year. I talked about the results of CFIP.

We've also made improvements in other parts of our operation and we've got the entire Ohio ESP to get a resolution on before we are in any position to talk about what future equity needs might be. We talked about $245 million of incremental investment in Pennsylvania distribution. Under the Ohio ESP, there is an extension of the DCR rider, plus potential opportunities to invest in increasing the smart distribution network in Ohio, along with transmission with ATSI, and transmission with MAIT.

What we need to do, and what we plan to do, is to communicate to you what type of regulated growth rate we are going to strive for going forward, once we have these last remaining questions done. And then any equity needs are going to be driven off of that. They're not going to be driven off of a need for equity to deal with any of the financial issues that we have been trying to wrestle to the ground this last year. They will only be used for growth and that is our intent.

Thank you.

Paul Ridzon, from KeyBanc.

What is your current thinking around when the Ohio commission will rule, and what is your outlook for that schedule getting delayed? And if it were delayed beyond the PJM auction, how would it impact your bidding behavior?

As I said in my comments, we are expecting an answer from the Ohio commission in March. And so I do not think it is going to affect our bidding behavior one way or another.

Our competitive generating business bids in our competitive fleet. We have regulated generation in West Virginia already that is bid by a regulated generation group. The two do not talk, as required by FERC standards of conduct. This generation will get bid in by one of those two groups, depending on which side of the fence it is on.

Can you remind us what the original investment in Signal Peak was?

We made an original cash contribution of about $150 million.

And you sold a piece at what, you said $230 million?

Yes. We sold 50% of our interest and we had a cash proceeds of $234 million.

Okay. Thank you very much. I'm good.

Dan Eggers, Credit Suisse.

Couple of cash flow questions for you guys. How should we think about bonus depreciation affecting the cash flows coming back in? And how does that get treated in different utility/transmission assets, as far as adjusting rate base?

Dan, this is Jim. On depreciation, we are already in a large and well position for 2018 and 2019 period. This is just going to extend that beyond 2021. Obviously, these years will change somewhat with the approval of the PPA scenario.

On earnings side, it's really a modest impact from our rate-based reduction. We will see a little bit on the transmission side and certain of our other jurisdictions that have formula like rate recovery such as the DCR in Ohio. I would say the impact to our earnings rate base is going to be minimal.

So should we assume, what kind of cash tax rate are you guys assuming through 2021? Are you an AMT or sub AMT level then?

Hi Dan, this is Jon Taylor. We are at the AMT level.

Okay. Got it. I guess on the pension side, did I read it correctly from the last quarter slides to this quarter's slides that your pension expenses are up about $55 million in 2016 versus 2015 on a pretax basis?

Yes, Dan. Two things that are driving that. First we had a 25 basis point decrease in the Return on Assets. So we took that down from 7.75 to 7.5, and we also saw a 25 basis point increase in the discount rate, which would increase our interest cost. So the two of those were about $50 million.

Okay. Got it. And if we look from the K the 5-year funding plans, your obligations for pension are up about $600 million, to the 5-year running period to last K to this K, do you guys see any funding obligations around that or is this kind of beyond 2016, we'll wait and see what happens in interest rate environment between here and there?

Dan, what we have out there, and you are right, our five-year required contributions are about $500 million higher than what the five-year required contributions were in the 2014 10-K.

Our actuary, Aon, they recalibrated that annually and at this point these are fundings that we would be required to make. As we said, we have a $381 million contribution required in 2016. We have already made $160 million in January.

2017 we have a $439 million pension contribution. That's down somewhat from where we were in the 2014 10-K, where we had $555 million, but again that is associated with our actuary recalibrating when our payments are required and some of those payments were moved out to a future year.

Okay, thank you. And I guess just last thing on the ESP side in Ohio, does it become a friction point where you have to have a decision in order to implement rates before ESP three goes away? How much time or cushion do you guys need between PUCO making a decision and you guys being ready to implement?

Yes. There does become that point, but I think it's going to be a moot question because I fully expect the commission to act in March.

So a decision in March gives you plenty of time?

Correct.

Okay, very good. Thank you.

Julien Dumoulin-Smith, UBS.

Let me just follow up on what Dan was asking there. First on the bonus depreciation point. Can you elaborate a little more on the earnings impact rather than the cash flow, and think about what it does separately to the transmission and the distribution side as you think about perhaps the next round of rate cases or FERC filing?

At this point, Julien, I would say that the impact on each of the segments would just be pennies. It would not be material at all.

Got it. Could you elaborate why that would be, just to be clear? As you think about, is that principally because you have not filed, or you don't necessarily have a meaningful distribution case contemplated?

At this point on the distribution side, it would only impact the utilities that we have formula like rates considering the DCR in Ohio. We have rates that are in effect in all of our other jurisdictions. We will likely be looking to go in for rates in New Jersey and Pennsylvania, that will not be -- we won't see changes of our rates until the 2017 time frame at this point. We will give you more clarification on that when we have our analyst day meeting.

Just to clarify analyst day expectation, if there is indeed an issue at FERC, I suppose, a, you would expect the host journalist they would be in terms of providing guidance, should we continue to expect EBITDA guidance, kind of status quo as you laid out? If the 206 is successful?

Yes, well, I think this is where we are at. We will wait until we get the outcome in Ohio. Once we have that and we will give you a little clearer guidelines on what we are expecting in terms of our analyst meeting. One way or another, we will be giving you guidance for 2016, that includes ESP or does not include ESP, based on where we are at that point in time.

Got it. And then lastly on the Signal Peak asset, what is the situation in terms of the servicing the debt and just the guarantee there? If you could elaborate in terms of the asset itself?

Okay, Julien. This is Jim. From servicing the debt, the mine continues to service that debt. The only time that we would have a change there is if we become more of a full-time owner of the mine. If we would have control over 50% of that, the first step we would have to do is likely consolidate that debt onto our balance sheet. Right now it is not consolidated because we are only a 33% owner.

Then ultimately if there was a capital call that the other owners were not able to fulfill, that would also likely require us to make that capital call. At the end, of that $300 million, $100 million is purely ours because we own a 33% interest in that. Once we understand fully what happens to the mine, if it would happen to shut down, then we would be responsible to fulfill that obligation to the banks.

The balance of the obligation.

That's correct.

Great. Thank you so much.

Paul Patterson, Glenrock Associates.

Just on a quick question here -- in terms of the PPA associate generation, how much of that, if you could remind me, cleared in the 2018, 2019 auction?

This is Donny, Paul. So Sammis and Davis-Besse, it all cleared in the 2018, 2019 auction.

Okay. And then, you guys brought up an interesting issue here in terms of how you're generation in the PPA would be similar to regulated generation, et cetera? And I do not recall when the Harrison plant acquisition by the regulated affiliate in West Virginia was being purchased, this much of an issue in terms of opposition, et cetera, from generators, et cetera. Why do you think, in this case it is being so much more of an issue than it would be in the Harrison case, when it sounds to me, and correct me if I am wrong, the economics would kind of be similar? In terms of the [size of] market. (overlapping speakers)

I am at a complete loss for why it is such a big issue for others, because I do think it is financially the same as what happened with Harrison. These units will no longer supply retail load, they will no longer supply polar load. They're not going to influence the competitive market in any way. So I am at a complete loss for why it has generated such adamant opposition, other than potentially misery loves company.

Okay.

If I could add on just a little bit to that.

So if you think about the parade of horribles that EPSA and others highlighted in their complaints to FERC, they talked about, if you let these generating units look regulated and have in effect, what they call an out of market subsidy, that would crush the marketplace.

If you think about PJM, as Chuck alluded to earlier, 20% of PJM is already regulated and that does not even include the FRR entities. If you think about what they were talking about, the bidding aspect of this, it is public information that prior to capacity performance, three quarters, that is 75% of the megawatt's in the PJM capacity auction bid at zero. They bid at price takers. After CP, it was about roughly half.

If you think about it with the new penalty, what you associated with that penalty should kind of be your new zero, I would suggest the new price takers is actually higher than 50%. What that would suggest is some of the generators who actually filed this and complained so loudly, saying it would crash the market, they themselves actually bid into the capacity market at zero.

Okay. Fair enough.

Paul, just to be clear on the capacity. I said it all cleared, and in actuality when you look at our fact book on slide 119, you can see there were 525 megawatt that ATSI that did not clear.

I'm sorry. Go ahead.

A slice of that maybe at Sammis and Davis Besse. But essentially it all cleared.

Why would a slice of it not have cleared, I guess?

To the degree we bid all of our units on a curve, there could be a slice that did not clear.

That would be Sammis and Davis-Besse?

Generally we bid all of our units on a curve, Paul.

I guess I am wondering, of the PPA affiliated plants, some of it may have cleared and some of it may not have cleared. Is that correct?

It would not look any different than the rest of our unregulated plants, Paul.

Okay. Just to get back to Julien's question, and to make sure I understand on the global holding guarantee, the $300 million, if there was a -- it wasn't clear to me exactly how much on the hook you guys are, if the Signal Peak mine becomes uneconomic or unable, and you don't get the capital calls from third parties, how much would be the total risk that you guys may or may not have? I wasn't clear completely.

The total amount would be $300 million, less any types of proceeds that we could get from the sale of the mine. So if we cannot sell the mine for anything, the maximum would be $300 million. Assuming that there is some value to the mine, we would be able to use those proceeds to reduce that amount of exposure.

Great. Thanks so much.

Anthony Crowdell, Jefferies.

Two quick questions on the PPA. First, do you think FERC rules before the May PJM auction, and second, you mentioned in the waiver earlier that you have a waiver between your utility and the competitive generation. Is a waiver unique to a particular PPA? Or is it, I guess, for any PPA that goes between your utility and competitive businesses?

This is Leila. It covers all of the transactions between the utilities and the affiliates. And again the basis upon which it was granted, the circumstances have not changed. The commission still retains the ability to protect customers. And I'm sorry I forgot your first question.

Do you think FERC rules before the auction and may?

I'm sorry. Yes. Nothing is carved in stone and they do not have to. EPSA asked for expedited treatment, but most people believe that they will act before the auction, and probably act on the filed paper as opposed to holding a hearing. That would be my best guess.

Quickly then, has FERC ever reversed policy and revoked a waiver?

I don't know the entire history, but I can tell you what FERC has done, with regard to captive customers and shopping. FERC, on several occasions, has been asked to look behind the curtain and opine whether a state's particular flavor of retail choice is what they would agree with or not, and FERC has consistently said no. As long as they are not captive customers, and as long as they can shop, then we are not going to try to second-guess what commissions do.

Great. Thanks for taking my questions.

Praful Mehta, Citigroup.

Sorry to go on the PPA question again, but I am just trying to understand the other side, and I know this is clearly not the preferred pot, but if the PPA does get cancelled, or which ever pot or how it gets cancelled, I'm just trying to paint the picture first from an equity needs perspective, and also from strategic fit perspective.

As in, if you do see the PPA getting canceled, is there any view on how the equity need requirement changes, especially to support credit? And, secondly, strategically do you see this business still a fit within FE or do you look to do an exit in some form at some point?

First off, we have not communicated any earnings guidance for full-year 2016. Whether the PPA gets done or not, and I am not going to do that here this morning.

What I have said is, we will deal with that outcome when we have it, and we will communicate at that time what our earnings guidance for 2016 is, what our future growth plans for the utilities are, what our future equities might be, if anything, to support that growth. I think you are just going to have to be patient and wait for the outcome and we will tell you where we are at that point in time.

Beyond that, I have consistently said I think that generation, transmission, and distribution are all critical assets in terms of serving customers. And right now I don't see any strategic change there for us.

Fair enough. And on the second question, if I look at the generation of a competitive business and I look at --

I would remind you in my remarks I told you that this business is generating positive EBITDA, positive cash flow through 2018, without any benefit from the energy security plan.

Got you. That's a great lead in to my second question, which was, as I think about that positive free cash flow, I guess an important part of that is just the different channel that you sell your generation through. And LCI looks like an important piece of that puzzle.

The range that you generally provide for LCI is in the 0 to 20 terawatt hours of sales in the LCI direct. 2017 looks like it is just at five terawatt hours right now and clearly it's early days and you're waiting for the PPA. The reason why I am focused on it is the LCI price versus the smart price is almost 20 megawatt hour difference. I'm just trying to put a lower bound on that LCI sale, at a minimum what do you see achieving at LCI or LCI channel sales in the 2016, 2017 time frame?

This is Donny. I think actually if you look at slide 104 in the fact book, it shows LCI, MCI and mass market, we have 16.4 terawatt hours closed already for 2016 delivery.

I am looking at 2017 and LCI for 2017 is five terawatt hours.

Sure. We have got a ways to go there. LCI customers generally are shorter term contracts compared to, government aggregation, for example. It would not be unusual to be able to close10 terawatt hours or 15 terawatt hours in a year prior to the delivery year.

Thank you. And you expect those prices to be at similar levels to where you currently clear, which is around $54 to $55 per megawatt hour?

That is more difficult to say. What you have to keep in mind embedded in that price is the price of capacity.

So, a customer at ATSI in the 2015, 2016 time frame is going to look different than a RTO customer and that is going to look different than a customer in the 2017, 2018 timeframe. It's hard for us to say what price we would end up locking those in at. What I would tell you is that we would have consistent margins.

Got you. That's very helpful. Thank you.

(Operator Instructions).

Charles Fishman, MorningStar.

In comparing the fact sheets, it looks like the transmission spend you are projecting a little up for 2016 and a little lower for 2017, but nothing has changed with respect to Energizing the Future. The overall project is pretty much on track from the way you set it up a couple years ago, correct?

That's correct.

That was my only question. Thank you.

There are no more questions in the queue. I would like to thank you all for your continued support and I look forward to getting our answer from Ohio here in a few weeks, and then look forward to meeting you all face-to-face at the analyst meeting following that. Thank you.

Thank you. Ladies and gentlemen, this does conclude our teleconference for today. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.