Firstenergy Corp (FE) — Q1 2015 Earnings Call Transcript

Thank you, Kevin. Welcome to our first quarter earnings call. Today, we will make various forward-looking statements 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 or outcomes 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. Participating in today’s call are Chuck Jones, President and Chief Executive Officer, Jim Pearson, Senior Vice President and Chief Financial Officer, Leila Vespoli, Executive Vice President, Markets and Chief Legal Officer; Donny Schneider, President of FirstEnergy Solutions; Jason Petrik, our Corporate Assistant Controller; Steve Staub, Vice President and Treasurer; and Irene Prezelj, Vice President, Investor Relations. Now I will turn the call over to Chuck Jones.

Thanks, Meghan, and good morning, everyone. It’s a pleasure to speak with you today. We had a good quarter, and we are off to a great start for the year. Since our last call in February, we have continued our work to position FirstEnergy for solid, predictable, and customer service-driven regulated growth. This morning we will talk about our progress on those strategies. We will also discuss other key initiatives, including an important effort that is underway to reduce our cost structure and drive improvements to our balance sheet, and of course, we will review our first quarter financial results and operational performance. Similar to our last call, we intend to keep these prepared remarks brief to allow ample time for your questions before the end of the hour. Our first quarter operating earnings of $0.62 per share are slightly above the top end of our guidance range and give us a solid foundation to start the year. We benefited from the growth in our transmission business and solid distribution performance that was assisted by a second year of unusually cold weather. Our year-over-year results also reflect the actions we began taking in the second quarter of 2014 to reposition the retail sales portfolio in our competitive business. For the past year we have talked about the extreme weather events of the first quarter of 2014 and the impact those conditions had on our competitive business and our strategy. The first quarter of 2015 was even colder with heating degree days totaling 21% above normal and 2% higher than 2014. The PJM market also set a new winter peak of 144,000 megawatts, exceeding the previous winter peak, which was set in January of 2014. In our competitive business, however, the difference in our results between this winter and last is striking. This improvement speaks to the benefits of our more conservative strategy, which includes three major components. First, selling no more than we produce in order to maintain an open position of at least 10 million to 20 million megawatt hours annually to protect against extreme weather, unplanned outages or a combination of both. As a result of our actions to strategically reduce load obligations, our 2015 retail and polar obligations are expected to be about 68 million megawatt hours, compared to 99 million megawatt hours in 2014. Second, reducing exposure to weather-sensitive load. From January of 2014 through March of 2015, our overall retail obligations are down nearly 35% on an annualized basis, with much of that coming from serving fewer of the most weather-sensitive residential and small commercial customers. Finally, a more rigorous commitment to economically dispatching our units. This strategy, together with improved plant operations, helped to mitigate the potential downside from this year’s severe first quarter weather and demand conditions, even though our region experienced four more below-zero days this February than last January. As contracts continued to roll off, we expect a further decrease in our annualized retail load obligations through the end of this year, much of that decline will be associated with the most weather-sensitive load. As I’ve mentioned to many of you previously, we recognize that reducing risk in the business also means that we are likely giving up some earnings potential, but as we have said, our objective is to make the competitive business more stable as we focus our efforts on growth in the regulated businesses. In that regard, the last few months have been a busy period for our energizing the future transmission investment program. We are nearing completion of projects that are designed to maintain service reliability in the wake of plant deactivations in Northern Ohio. Those plants ceased operations for good on April 15th. These projects included the Bruce Mansfield-Glenwillow project, a 195,345 kilovolt transmission line extending on 119 miles from Western Pennsylvania to Suburban Cleveland, scheduled to go in service by June 1. In addition, we are preparing to energize a new 345-kilovolt substation and associated transmission upgrades in Wood, Trumbull, and Stark counties, which are designed to maintain service rollout reliability in Northern Ohio after the plants are closed. We also continued our work to strengthen the grid to help protect it from storms and make network and physical security upgrades. Finally, we're on track with our planned investments on projects that will support the midstream gas operations, with about $365 million in the pipeline through 2019. On the regulatory front, our rate cases in New Jersey and Pennsylvania have concluded. In Pennsylvania, we were pleased that the PUC accepted our rate plan settlements for each of our four utilities in the state. The new rates, which will be effective on Sunday, will help our operating companies continue to enhance reliability and service to our Pennsylvania customers. We are looking at further options for customer-focused investments going forward, including the option to possibly request a distribution system improvement charge to recover the cost of those investments. In New Jersey, we received recovery of approximately $580 million in costs incurred by JCP&L for the 2012 storms and we're glad to have a long process and uncertainty behind us. Now we look forward to working with the BPU as we set a course for future infrastructure and reliability investments at JCP&L. We've had a good and productive start to the year, and we are making solid progress toward our long-term goals. Looking forward, there are still three major initiatives underway that will ultimately help shape our company and our strategies going forward. First, in Ohio, the hearing on our electric security plan has been delayed by 60 days and is scheduled to begin on June 15th. As you know, in its recent decision on the AEP and Duke cases, the PUC ruled that stability writers related to purchase power agreements similar to our proposal are legal in Ohio. This was an extremely significant outcome. We believe that our filing includes a robust case for how our proposal benefits utility customers and supports economic development in the state. On May 4th, we expect to file supplemental testimony to further demonstrate how our plan meets the factors outlined in the AEP and Duke cases. While we're comfortable with the new schedule set by the PUCO, this schedule will affect the timing of our analyst meeting, which we had hoped to have this summer. We believe that it makes sense to host this meeting after we receive a decision in Ohio, which pushes us to sometime late this year. The second open matter could have a significant impact on our business is the PJM capacity performance proposal. PJM has addressed FERC’s question regarding the structure of the product. Pending its final decision, FERC granted PJM's requested waiver to delay the May capacity auction to no later than the week of August 10th. We appreciate the care and long-term perspective that FERC is taking in its review of this important mechanism, and expect both PJM and FERC are interested in reaching a resolution as soon as possible. In both of these matters, we look forward to a final outcome that produces better clarity for our company and produces benefits for electric consumers in our region. On a related item, as you know we had delayed our decision to construct a new dewatering facility for our 2400-megawatt Bruce Mansfield plant in Pennsylvania while we evaluated the plant’s future, particularly with respect to the results of the next capacity auction. We will continue to monitor market conditions, but given the current environment, including the auction delay, we think it makes sense to move forward with some early aspects of this project. This work is designed to preserve our ability to continue operations of the plant after December 31, 2016. All costs associated with this project are in our current business plan. We, of course, intend to remain sharply focused on those things we can control, including our own spending on goods and services, operating expenses and other corporate spending, as well as capital expenditures. Last month, we launched a cash flow improvement project intending to capture both immediate and long-term savings opportunities that are meaningful and sustainable. A team led by FES President, Donny Schneider, is working to identify savings and process improvements across the company with a particular emphasis on our generation business. The team is focused on expense reductions, capital expenditures, and inventory. We are also working with an outside consultant to examine the significant savings potential in our supply chain. With more than $2.5 billion in annual spending in the project scope, we believe that significant cost savings opportunities are available while continuing to successfully serve the needs of our organization, customers, and employees. I will note that workforce and benefit reductions are not included in the scope of the project. In all, we are targeting $50 million in savings this year and an additional $150 million in 2016, reaching a run rate of $200 million by 2017. We expect that the savings will be split about evenly between O&M expenses and capital expenditures and help us create sustainable levels for the future. By appropriately addressing our cost structure, we can help direct our future and move FirstEnergy to a point that our fundamental operations make the company stronger while improving the balance sheet over time. We’re off to a solid start in 2015. Our early financial results together with our progress on our strategic initiatives are building a solid foundation for the year and for the future of our company. These results in our outlook for the remainder of the year continue to support 2015 operating guidance in the range of $2.40 to $2.70 per share. Consistent with the leadership philosophy I have shared with many of you, I would like to narrow the gap between our GAAP and non-GAAP results. While some differences are expected, we are diligently focused on earnings quality. Now we will turn the call over to Jim for a brief review of our first quarter financial results, then we’ll open the call to your questions.

Thanks, Chuck, and good morning, everyone. Consistent with our approach in the last call, I will use my time today to speak to the major drivers and events of the first quarter. This information is detailed in our consolidated report, which is posted to our website, and we would be happy to address any specific questions in the Q&A or after the call. As Chuck said, this morning we reported strong 2015 first quarter operating earnings of $0.62 per share, which compares to $0.39 per share in the first quarter of 2014. On a GAAP basis, basic and diluted earnings for the first quarter of 2015 were $0.53 per share, compared to 2014 first quarter basic earnings of $0.50 per share, or $0.49 per share on a diluted basis. We’re off to a good start for the year. First quarter 2015 operating earnings were fairly plain and simple. As expected, we benefited from improvements in our competitive business, as well as increased transmission revenue, which were partially offset by a higher effective income tax rate in our corporate segment. From the standpoint of our first quarter guidance, we came in above the range we provided largely due to the impact on our distribution business of extremely cold weather in late February and March. Compared to the normal weather that we include in our guidance, first quarter wires revenue benefited by $0.06 per share as a result of heating degree days that were 21% above normal during the period. This was offset by about $0.03 per share related to weather impacts at our competitive business. First quarter operating earnings also benefited by a net $0.03 per share, compared to guidance primarily as a result of the New Jersey storm amortization delay and incremental revenue from a TrAIL transmission investment. Overall distribution deliveries increased slightly compared to last year, reflecting weather as well as modest growth in our customer base, offset by the impact of lower average customer use associated with energy efficiency. Residential sales were flat compared to the first quarter of 2014 but down 1.7% on a weather-adjusted basis, while both actual and weather-adjusted commercial sales increased slightly. Industrial sales were also up slightly, marking the seventh consecutive quarter of growth in that sector. While soft natural gas prices are deterring some new entrants into the shale gas fields, our conservative estimates continue to support more than 1000 megawatts of new load for midstream businesses through 2019. The shale slowdown contributed to the softer first quarter demand from the steel sector; however, most of the other key sectors in our region remain solid. In our transmission business, first quarter operating earnings were $0.17 per share, reflecting incremental rate base growth at both ATSI and TrAIL and forward-looking rates at ATSI beginning January 1st this year, partially offset by higher depreciation, taxes, and interest expense. As Chuck described, our competitive business was able to more effectively navigate this year's extreme weather conditions due to the changes we began putting in place during the second quarter of last year. Our 2015 first quarter operating results in this business reflect the benefits of this repositioning and improved plant availability as well as higher capacity revenues. For 2015, our committed sales currently are about 70 million megawatt-hours, essentially having sold everything, we anticipated on a retail and forward wholesale basis, with over 8 million megawatt-hours available for spot wholesale sales over the remainder of the year. For 2015, we are also reducing our generation production estimate from about 79 million megawatt-hours down to about 72 million megawatt-hours due to the economic and market conditions we experienced during the first quarter and the market price outlook for the balance of 2015. If it is more economic for us to purchase power from the market to serve low when needed, we will do so. But we have the benefit of our own generating resources if and when we need to call on them. Ultimately, market conditions will determine how much we generate from the fleet and how much we purchase. Essentially, we will source the power to meet our retail load obligations as economically as possible. For 2016, approximately 70% of our projected sales are committed. Based on our results for the first quarter, we are reaffirming our 2015 adjusted EBITDA range for the competitive business of $875 million to $950 million, as well as our 2016 adjusted EBITDA range of $750 million to $850 million. Consistent with the guidance we provided earlier this year, the corporate consolidated effective tax rate was 38.8% in the first quarter of 2015, compared to 30.3% in the first quarter of 2014. This change drove an $0.08 per share decrease in the corporate segment compared to last year and reflects the elimination of certain future tax liabilities associated with basis differences in the first quarter of 2014. This year is off to a solid start, and we are executing our plans to improve our company's fundamentals and drive long-term shareholder value through customer focus and regulated growth. As Chuck said, we are reaffirming our 2015 guidance range of $2.40 to $2.70 per share and are also providing a second quarter operating earnings range of $0.42 to $0.50 per share. With that, I'd like to open the call for your questions.

Good morning, guys.

Good morning, Dan.

Just following up on the cost-cutting plan, thanks for the additional detail. But could we maybe dig a little bit more into where you are seeing those buckets of savings maybe between regulated, non-regulated and kind of the scaling of those opportunities as you get further into the plan?

Well. Dan, let me say it this way. I think, I said in my remarks that we are going to be focused primarily on the generation business. We are going to look at everything. The reason that the scope is excited about $2.5 billion is because there are certain buckets of expenditures that would be counterproductive to our regulated growth strategy to go and try to address those. For example, our transmission expansion plan. So we're focusing primarily on generation. We are very cognizant of the fact that we don't want to do anything to take the growth strategy in our regulated companies off-track.

If we consider the impact on inflation, what will the underlying O&M inflation be after accounting for these savings? Is that the appropriate approach for thinking about the future?

I'm not sure I understand your question.

So, I guess if you think about, are these savings going to be net reductions in O&M year-by-year or is there a level of inflation that will eat up some of the savings as we think about ‘16, ‘17, ‘18 numbers?

Well, I think that initially, this is going to be a step down in our cost structure. And like any business over time, there are incremental adjustments that are made, as we offer our employee wage increases as there are inflationary things that go on in the economy. But one thing to keep in mind is we have not included staffing in this phase of what we're doing. We will have annually about a thousand employee attritions each year. And going forward, we expect to make adjustments in the structure of our organization such that those attritions should pretty much offset any inflationary pressures that are on where we are at when this project’s done.

Okay. And I guess one other topic. With the Supreme Court hopefully addressing the 745 case on Monday, can you just talk about what the process would be from a legal perspective for you guys if the Supreme Court takes the case or if they choose not to take the case?

Okay. So if they choose to take the case, then I would expect folks to continue to drive capacity performance. They've already rejected its premature PJM’s attempt to modify the DR process. So it would continue as a supply product as it has in the past and wait for some final determination from the Supreme Court, substantive determination with regard to demand response. If they decide to not take the case, I can speak to what in theory should happen. In theory what should happen, demand response should come out of the capacity auction as a supply product. From our standpoint, we believe there is a place for a demand response. We believe that that is on the side of state implementation plans, and we think going forward that would be a useful product and can still be maintained. With regard to how PJM views it, we know they view that as a very valuable product. So I would imagine at a practical level, PJM will be seeking to somehow reinclude demand response within the capacity auction.

Is it going to be practical, if they don’t take the case and they have to go to this removal of DR? A, is a practical that it can be reasonably well addressed for this upcoming auction, and then what is your view on whether retroactively prior auctions need to be adjusted?

We still have our case that challenged the previous base residual auction. The situation has been delayed and remains unaddressed. I expect they will need to take action regarding this issue as well. Consequently, there are uncertainties about that auction, particularly whether we should eliminate demand response and its price suppression effects without rerunning the auction, but by simply removing those effects.

Okay. Thank you.

Hi, good morning.

Hi, Brian.

With the cost cut commentary today, does that preclude now the need to issue equity for the foreseeable future, particularly given some of the FFO to debt metrics that some of the credit rating agencies are looking at?

Here's what I've said on that topic. All along, I believe that it's incumbent on us to find a way to fundamentally operate our company in a way to where we don't have to use equity to strengthen our balance sheet. I think these cost-cutting initiatives will get us to a place where we can be successful in not having to do that. Then going forward, I think where equity should be used is where it’s intended to be used in our business, and that is to generate growth in our business. So we may look at equity down the road to use for growth, either for additional transmission investment or potentially even investment inside the distribution companies. But I believe we can get ourselves to a position where the cost-cutting puts us at the bottom end of the range that we need to be from a credit metrics perspective and then these costs over time, we will continue to improve the balance sheet.

Great. And also of the cost cuts and cash flow improvements, I think you said $100 million of this was expenses, and the remainder is cash flow improvements. Can you talk about on the cash flow side how much of that is just timing related as opposed to permanent reductions or permanent improvements in cash flow?

I don't think we can even talk about that right now. We just kicked this team off a few weeks back. We were in the early stages of it. I think when we get to this point at the end of the second quarter, I think I will be in a good position to tell you more concretely what we've identified and what the ongoing impact on our company is going to be.

Okay. And then last point, then I'll jump back. The cost cuts that you’ve got there embedded in the current EBITDA guidance, I thought I heard you say that, but I just want to confirm.

No, they are not.

They are not.

They are targets at this point. Once we know what they are, then we will embed them in our going forward forecast that we give you.

Very good. Thank you very much.

Hi, good morning.

Good morning.

First the question on, you mentioned the supplemental testimony you’re going to file on Monday I guess. Could you just give us a little sense, more color on what areas you might be focusing on with that?

Hi, Steve. This is Leila. We will be addressing the factors that the Commission laid out in the AEP cases while we think our underlying case actually did cover all of those. Since the Commission gave us an opportunity to supplement our testimony, we are availing ourselves of that. So just if you think about them, they were financials, need, supply diversity, compliance with environmental regulations, jobs, economic development, and then kind of going down the list. So we will be supplementing our testimony in all those regards.

Okay. Thanks. Separate question, just to clarify something on the equity issuance question before. So to the degree that you would look at equity funds for growth investment, would that only be for investment that goes beyond your current capital plan or could it be fund investment that’s already in your current capital plan?

Well, Steve, I think we need to see where we end up with this initiative first and foremost and where that leaves us in terms of free cash flow once that’s done. But I would say my goal is to use equity for new growth on top of the growth that we've already communicated to you.

Okay. Good. For my last question regarding transmission, I recall that you plan to account for some type of ROE adjustment in that area. Can you provide any insights into your assumptions on this following your Q or any additional information?

So here is what I would say on that. We have been approved for a forward-looking formula rate at 12.38%. We are doing what we believe is prudent to go forward, but I think we’re approaching those negotiations in the settlement process from that perspective. And for me to give you anything else, I think we’re negotiating against ourselves at this point, and I'm not prepared to do that. So we'll see where this process unfolds, but I think FERC approved us at 12.38% and we’re going to negotiate from there.

Okay, but you’re reserving something?

No.

Okay. Thank you.

Hi, good morning.

Hi, Neel.

Good morning.

First question on JCP&L, now that you have the rate case resolved, obviously, it was off of a 2011 test year. So you’re not getting up to that authorized ROE, how soon could you refile to try to get the liabilities between authorized and earned?

Hi, Neel. Actually from the rate order, we are required to file the rate case by April 2017, but as we always do we continue to look at that and I might expect to filing even sooner than that timeframe.

But one of the things we want to do here is we haven’t really been able to sit down and talk with the BPU commissioners for almost three years now. And the President and I have talked and we are going to get together and talk about the future of JCP&L together before we get to a point where then we can’t talk again. So that’s the game plan.

Great. And then Jim, I wanted to go back to your comments about possibly reducing the amount of terawatt hours that comes out of the fleet in 2015, and I'm not sure if it was 2016 as well. In 2015, would it be a margin benefit just because you’re purchasing power at cheaper cost and generating, or the actual kilowatt hours coming down for stuff that you haven’t hedged, and does that also affect 2016 as well?

Neel, what we’re looking at is it would be a margin benefit because we would be looking at buying power cheaper than what we would produce it at.

So, would it be for the hedge portion, I guess, in 2015, what about 2016?

Yeah. We have that broken out in the fact book, Neel. I don’t have the exact number right off the top of my head. But, yeah, we would have it out there. But in 2016, we’re going to look at running in and dispatching the plants no differently than we are right now, if it’s cheaper to buy from the market that’s what we will do.

Great. And then, just generally speaking, as far as some investment for the supercritical to be CP compliance. Is there any general color you can give us as to how your fleet is positioned going into the auction in hopefully August?

Well, I think we need to see first where FERC and PJM land in terms of a capacity performance product being in the auction. Then we need to sit down and take a look at how are we going to approach that auction from a bidding strategy. Then we need to see what units clear and at what price they clear and then from there we’ll decide what the appropriate investment in our unit is to make sure that they’re available when they need to be. So there are a lot of unanswered questions and there are a lot of competitive implications around how we’re going to approach that. I prefer not to get into the details. But we understand that there is the potential that we may want to do some additional investment in our fleet, but that all depends on where these rules shake out and where the market ultimately clears that.

Perfect. Thank you very much.

Good morning.

Hey, Julien.

Hey, so just following up with little clarity on New Jersey. Does it necessarily need to be a rate case for say in the medium term? Specifically, what I’m curious about is, is there any potential for like a stimulus-like program like we’ve seen at some of the peers in New Jersey versus or in conjunction with the rate case?

Well, as I said, we haven’t had a chance to really have meaningful dialogue with the BPU for three years. We’re going to go over there and have meaningful dialogue. Once we have that, I’ll be able to answer that question a little better. It's an option that we would obviously be willing to consider if they are willing to consider it.

And then with regard to the disk in Pennsylvania, you’ve been pondering the idea for a while. What do you need to see happen there or what’s the ambiguity in pursuing that structure?

Well, I wouldn’t say we’ve been flirting with it. We had a major hurdle we had to get through, which is the base rate cases for all of those companies, which we are now through. And now what I've done is I've asked our energy delivery team to look at what investments make sense for customers inside those operating companies. And I’ve pretty consistently said, I’m going to go invest money where it makes sense for customers. So until we see exactly company by company what the needs are to drive reliability improvement and improve customer service, I can’t answer that. I think I've said that we could spend up to about $440 million in Pennsylvania and stay under the 5% cap. I don't see us going anywhere near that number in the first disk filing that we would make, if we make one. But we’re putting that business case together right now.

Excellent. And then finally on the GenCo real quickly. In light of the latest trend of cost cuts, are you still generally targeting a cash flow breakeven outlook for that company? Is that kind of the right way to think about it at a high level?

Well, that business is cash flow positive for the next four years without any of these cash flow improvements. So anything that we accomplish is going to make it more cash flow positive and it’s going to improve FirstEnergy's overall cash flow and that’s what we’re trying to accomplish. So we’re already cash flow positive for that business for the next four years.

Great. Excellent. Thank you.

Good morning.

Good morning, Paul.

I was reviewing some of the questions and I was a bit unclear. When I refer to the fact book and Neel's question about generation output, I notice there hasn’t been any significant change since 2015 in your expectations. I want to confirm my understanding: given the changes in power prices and forward groups, do you expect any modification in your output? I just want to clarify this.

Yeah. Paul, this is Donny. Yeah. From 2016 with the forwards that are out there, we’re still projecting no change to what we’ve shown in previous fact books. The fact of the matter is, at today’s forwards, we’re kind of right on the edge. And so almost literally a dollar change in the forwards would move, whether we dispatch a unit or we don’t dispatch a unit. But for now what we’re seeing in ‘16 is that our units will run as we’ve forecasted previously.

Thanks for the clarity. Regarding Dan's question about FERC, Leila, you mentioned that if the Supreme Court decided to take on the case, you wouldn’t seek to rerun the auction but would want to remove the effects. Could you explain that further? Are you considering a reprise of the auction, or what do you mean by that?

No. I don’t think they misunderstood what I said. What FERC has done, PJM came to FERC and asked to consider DR on the demand side of the equation, and FERC told them they were pretty mature in that. So the Supreme Court takes up the case. The chance exists that demand response might still be under FERC jurisdiction. And I think that what FERC was looking at. So right now, the way it would I think play out is demand response would be in the BRA auction when it’s held presumably in the middle of August. And would be a supply-side item as it has been in the past.

Okay. But if the Supreme Court had not removed it, would you want to proceed with the previous auction? I believe you indicated that you would like to…

Boomerang.

What do you mean by not having the auctions rerun but having them the effect taken out, I think it’s the way I understand it to be?

Reflecting on last year when we held the BRA and filed the complaint with FERC, we suggested that if demand response is not within FERC's jurisdiction, the appropriate action would be to remove it from the supply side. This would allow us to evaluate how the auction would have unfolded if demand response had not been included, while still accounting for the participation of other generators. This approach would eliminate the price-suppressing effects without requiring anyone to resubmit their bids for the auction.

Okay. I see. Okay. Thanks so much for that. And then on JCP&L, there is this review that's going on that I think they are trying to do some audit or something which is a little unusual since you just had your proceedings. But they themselves are seeking to review you guys. Could you talk about that and how that relates to the potential for? I mean, could you just address that, I guess, and what you think about that in this whole idea about the lag and everything else that you talked about?

Well, first of all, I would say this, we are not afraid of any audit of JCP&L’s operations. I'm confident that when they do this review, they are going to see a JCP&L that is much different than the JCP&L they saw the last time that they did a review. The reason for it is as a result of the 2011 and 2012 storms. There were reliability issues that kind of crept into the rate case and there was no adequate mechanism within the rate case to deal with the reliability issues. So coming out of the rate case, this is a way that kind of put those reliability issues behind us and position us, as I said, where we can now work with the BPU to move forward together.

Great. Thank you so much.

Good morning. Your had a great quarter with respect to transmission. I just wonder, appreciating that you don't want to negotiate with yourself during the settlement proceedings, but I believe this was the first quarter you got a forward rate-making mechanism at TrAIL, TrAILCo. Can you separate that out the $0.09? I mean how much was due to the forward mechanism and how much was due to the fact that you’ve been very busy with CapEx the past year?

First off, it’s ATSI that we filed further, not TrAIL.

Okay.

And as a result of those filing, what you are essentially seeing is the investments that we made in 2014 were made in a kind of the old formula rate. So for the first quarter of this year, you are seeing kind of a compound impact of everything that we invested in ‘14 because the rate went into effect as well as the first quarter investments that we’ve made. So in those overall results, the difference between a 12.38% return in any other subsequent return that we might end up at is minimal, and that's why we say we reserved a small amount, but we are moving forward with a 12.38% return until somebody tells me that it’s a different return. And I believe there is a very strong case to be made that if there is a different return, it should be different going forward from the point where there’s a settlement, not reverse.

Okay. So the settlement negotiations are really over the ROE not over the forward rate-making mechanism, correct?

This is Leila. We really can’t comment on what’s being discussed in the settlement. But I think, given the position of ROE in the grand scheme of things, you can derive your own conclusions with regard to that.

Okay. Thank you.

First of all, great results and my questions have been answered. Thank you so much.

Hey guys. Congrats on a good quarter. Real quick and this one maybe more for Jim. Just looking at the short-term debt balances, seem that those went up a little bit. What’s your plan in terms of whether you’ll maintain that short-term debt balance outstanding for a good while or whether you have the capability to pay it down or will you think about either terming it out or doing something else with it to reduce long-term interest rate exposure?

We wait to see where we come out on these initiatives, as Chuck talked about, Michael. We have some significant opportunity in the cash flow improvement project that Chuck talked about, and then a couple of the other big items that we are still looking at the capacity performance and the PPA. We don't have any plans right now to term any of that debt out. We will continue to look at it. The first quarter’s a little bit unusual from a cash flow output. We generally prepay our Pennsylvania gross receipts tax. That's about a $177 million. We had a pension contribution that we made in the first quarter. Ohio property taxes are due in the first and third quarter, and generally, our benefit plans have payouts in the first quarter. So it’s a bit of an abnormal. I would expect that over the rest of the year we would not see that balance grow. In fact, we may reduce that somewhat. But we will continue to look at whether it makes sense to term it out. I would prefer as time goes on, to push that further down into the business units, have the debt closer to the asset. But I think we’ve got to wait to see where we come out on some of these initiatives before we make that final decision.

Got it. Thank you, Jim. Much appreciated.

Hi. I wanted to congratulate you and encourage you on your efforts to improve the quality of earnings. I have a question regarding that. One distinct aspect of your operating earnings presentation, as I understand, is that unlike your GAAP earnings, where the difference between expected returns on pension assets and realized returns is recognized annually in the fourth quarter, there is no recognition of that difference in operating earnings. I estimate that over the past five years, this difference has amounted to about $570 million, averaging around $115 million a year or $0.27 per share. My question is, are you considering ways to more accurately reflect the outcomes of your pension investments in operating earnings?

Hugh, we made that decision a number of years ago to record any changes in actuarial assumptions on a mark-to-market basis. In our ongoing operating results, we have all of the service costs in there and then just any changes in the actuarial assumptions. And the biggest piece of that is generally the change in the discount rate, which has fallen over the last few years. So, we have no intention of changing the way we report our pension and our operating earnings going forward. But we fully break that out and much you know what the discount rate and the actual return on the assets.

Got it. Thanks.

Thank you very much. Really two things. One, can you give us any type of update on potential discussion that you are having in Ohio? I think at one point, you had mentioned that some other parties have expressed an interest in talking to you subsequent to the AP decision?

Well, I would say that we’re always in discussions with the parties that are intervening. And we’re not in discussions with the commission because we can't be. And when we have something to tell you, we’ll tell you.

And then I guess the other question is half of the $2.6 billion, I think, represented fuel which I think is more unique to the generation side. But the other half looks like it could be potential savings that when applied to other segments within the company. You sort of ruled out transmission, but any possible application of that saving to the distribution side?

What I ruled out is anything that would negatively affect our regulated growth strategy. We recently had rate cases in several of our operations, and it would be counterproductive to consider additional investments in those utilities. Therefore, I ruled out anything that impacts our regulated growth strategy.

Thank you.

Hi. All my questions have been answered. Thanks.

Good morning.

Hi, Stephen.

Good morning.

In your initial remarks, you mentioned that one of the factors contributing to first-quarter performance was the more rigorous economic dispatch of the generation unit. Could you elaborate on how you approached this year compared to the previous period?

Why don’t I let Donny take it, but as I’ve told you, our goal is to run the competitive business overall a little more conservatively so that we can have predictable results and that’s what we’re trying to achieve. And obviously, what I talked about is effective last year there was a polar vortex, this year in February, there was what they term the Siberian Express, which was actually more severe weather and a higher PJM peak load. And I think that we were able to capitalize on some of that weather improvement that we get on the utility side by doing what I said. And that is our operating our generating business much more conservatively. Part of that is we’re not going to dispatch units into a price that they don't make money, if we can avoid doing that. So Donny, you want to fill in any details or?

Yes. Stephen, I’d just say we’ve had a long history of this kind of thing. If you recall back in 2009 timeframe when the market first collapsed, we took our Lake plants offline, we took that workforce out of the Lake plants, and we moved them into the regulated side of business. Summer of 2012 we took Sammis Plant offline for about three to four months and then ultimately brought it back online. What we have now that's different than what we’ve had in the past is there is a lot more free board. When you have that open position into the spot market, you're able to take advantage of the market much more readily than what we have had in the past, because we have a cushion there from a risk perspective. So when you look back at this previous quarter, we had our Mansfield Plant completely offline for about a straight week when the price was below our marginal cost.

Okay, I understand. That makes sense. Regarding the winter performance, it appears that this year you have achieved significantly better operational results. We have discussed this in the past, but I am interested in hearing about the changes you have made year-over-year, how you managed the fleet to mitigate weather-related risks, and how this positions you for the future.

The main difference between January 14 and this year was the failure of a generator step-up transformer at Beaver Valley 1. This incident was not related to the weather, even though it was extremely cold outside. The temperature inside the transformer was significantly higher, between 75 and 90 degrees Celsius, which means the failure was random and occurred at an inopportune time. This had the most significant impact on 2014. In addition, we made efforts to reinforce some outdoor equipment at our power plants that could be affected by weather, which could disrupt unit performance. However, these improvements did not require major work or spending. I also want to highlight the outstanding teamwork between our Commodity Group and our generation fleet this winter, which contributed to the positive results we achieved.

Thank you very much.

Okay. Well, I think that was the last question. So we want to thank you all for your support. Obviously, I think we had a pretty good quarter, it was influenced by the weather, and I’m not going to take credit for the weather because we've got July and August coming. And if it goes the other way, I’m not going to take blame for the weather either. But it was a good start to the year. If you dig down below that, our operational performance was right on schedule with what we're trying to accomplish. And I know one quarter doesn't make a trend, but you have to start with one before you can get to 10 or 12. So that's our game plan, and we thank you all for your support.