FirstEnergy Corp. (FE) Q1 2014 Earnings Report, Transcript and Summary

Greetings, and welcome to the FirstEnergy Corp. First Quarter 2014 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, for FirstEnergy. Ms. Beringer, you may begin.

Thank you, Brenda, and good afternoon. Welcome to FirstEnergy's First Quarter Earnings Call. First, please be reminded that during this conference call, we will make various forward-looking statements within the meaning of the Safe Harbor provision of the United States Private Securities Litigation Reform Act of 1995. Investors are cautioned that such forward-looking statements with respect to revenues, earnings, performance, strategies, prospects and other aspects of the business of FirstEnergy Corp. are based on current expectations and are subject to risks and uncertainties. A number of factors could cause actual results or outcomes to differ materially from those indicated by such forward-looking statements. Please read the Safe Harbor statement contained in the consolidated report to the financial community, which was released earlier today and is also available on our website under the Earnings Information link. Today, we will be referring to operating earnings, both on a consolidated and segment basis, which are non-GAAP financial measures. Reconciliations to GAAP earnings from operating earnings are contained in the consolidated report, as well as on the investor information section on our website at www.firstenergycorp.com/ir. Participating in today's call are Tony Alexander, President and Chief Executive Officer; Leila Vespoli, Executive Vice President, Markets and Chief Legal Officer; Jim Pearson, Senior Vice President and Chief Financial Officer; Donny Schneider, President of FirstEnergy Solutions; Jon Taylor, Vice President, Controller and Chief Accounting Officer; Steve Staub, Vice President and Treasurer; and Irene Prezelj, Vice President, Investor Relations. Now I will turn the call over to Tony Alexander.

Thank you, Meghan, and good afternoon, everyone. I'll start today's call with a look at our first quarter results, then I will discuss some of the recent developments in each of our businesses, and I'll finish with an update on our full year outlook. Leila will provide a more in-depth review of our competitive business, as well as an update on regulatory activity. And Jim will present more details on our first quarter financial results. Okay, let's get started. This morning, we announced first quarter 2014 operating earnings of $0.39 per share, in line with the range we provided on our year-end call in February. Even though the extremely challenging weather continued throughout the quarter for our competitive business, we had good results overall in both our distribution and transmission businesses. In fact, our distribution business not only delivered strong performance during the quarter, but even more important, we continued to see positive trends in both residential and commercial sales, as well as growth in the industrial sector. Adjusting for the impact of weather, total distribution sales increased 2% compared to the first quarter of 2013. This includes an increase of nearly 3% on a weather-adjusted basis in the commercial sector. We are obviously pleased to see consecutive quarters of sales growth in the commercial sector. Weather-adjusted residential deliveries increased more than 2% compared to the first quarter of 2013, and we saw modest growth in our customer count, continuing the positive trend we noted during the fourth quarter. Sales to industrial customers increased about 1% compared to the first quarter of 2013, driven by manufacturing segments related to shale gas in our region, as well as continued steady growth from the automotive sector. We also welcomed the announcement in March of a planned ethanol cracker plant in our Mon Power service territory. While this project is still in its early stages, the land has been purchased, and we remain optimistic that our region is prime for a cracker plant. This development would be a tremendous boost to not only the shale gas industry in our region, but related manufacturing sectors across our service areas. Our first quarter distribution results, together with the growing momentum in the shale gas industry, sustained our cautious optimism that a more substantial recovery is on the horizon for both the commercial and industrial sectors. We are on track to meet or exceed our growth forecast for all 3 sectors this year. On the regulatory front, we filed our rate case in West Virginia last week, and we expect to file an ESP in Ohio and rate cases in Pennsylvania -- in our Pennsylvania service areas later this year. We are also looking forward to resolution of our New Jersey storm recovery and base rate cases. Leila will provide more details on each of these cases later today. Finally, in our transmission business, we are moving forward with our planned investments to support continued service, system reliability and enhance service to our customers. Projects underway include construction of our 100-mile transmission line from our Bruce Mansfield Plant to a new substation in the Cleveland area. This project is being constructed primarily to support the generation deactivations in the ATSI footprint. In addition, we are well underway on many of the smaller projects that are part of our transmission improvement program. While we did lose some physical construction time this winter due to the weather, we still expect to meet our targets for the year. Now turning to our competitive operations. While Leila and Jim will provide more detail about the specific impact the extreme winter weather and, more importantly, market conditions had on our competitive business, I'll take a moment to discuss what this winter's instability says about the state of our region's electric infrastructure. As you know, the regional grid was under severe stress during the polar vortex in early January and other frigid weather events in the remainder of the quarter. The combination of several factors, including high customer demand, forced outages and plant unavailability, in particular those driven by gas shortages, illuminated the fact that current energy priorities are putting the reliability of our electric system in jeopardy and creating a far more volatile energy price and service environment for customers. This is of particular importance in competitive states, where customer service and pricing are very much dependent, if not solely dependent, on stable and predictable wholesale markets. As you may know, we've shared this view in our testimony at FERC, in comments to business leaders and legislators and in media, and we will continue to advocate for regulatory changes that can ensure generating resources are valued at a level that reflects their contribution to grid reliability. While some modest reforms dealing with overreliance on imports and demand response have been approved by the FERC for the upcoming PJM capacity auction in May, we believe momentum is growing for changes that can truly help maintain the reliability, service quality and price stability that have long been enjoyed from our electric system. Even so, we are evaluating our target level of retail sales, including the markets and channels in which we concentrate our efforts and our hedge position, given the significant volatility now within the wholesale energy markets, the ever-changing market rules and, as we approach mid-2015 and beyond, the anticipated shutdowns of generation within the market. It has always been a part of our overall strategy to maximize the performance of our competitive business. As we evaluate and refine our targets in light of current market conditions, we are in a good position, since we only have about 55% of our generation committed for the 2015, 2016 PJM planning year and about 33% committed for the 2016, 2017 planning year. This gives us substantial flexibility as we consider how best to position our competitive business going forward. With respect to our plant performance during the quarter, even though our overall fleet performed better than expected -- in fact, we delivered more capacity to PJM than our units were committed to deliver or were being paid for -- we had several nuclear and fossil outages and derates that occurred during the most volatile pricing periods. And as Leila will explain, these outages, given the high prices for energy during those periods, had a significant impact on our results. During the quarter, we also successfully replaced the Unit 1 main transformer during the forced outage at Beaver Valley plant in January and commenced the Davis-Besse steam generator replacement project during a planned refueling outage. Davis-Besse is now in the startup process, but the outage took 15-or-so days longer than expected, which we estimate will result in about a $0.02 impact for the second quarter. In April, we also began the scheduled refueling outage at Beaver Valley Unit 2. The outage is on track, and we expect that unit back online during May. We have no other refueling outages scheduled this year. This morning, we revised our 2014 operating earnings guidance to $2.40 to $2.60 per share. It was a tough quarter for our competitive operations, given the market dynamics in PJM, and we have adjusted the earnings range at that segment to reflect the quarter's results and expectations for the remainder of the year. Our corporate segment and regulated utilities are expected to come in better than our original estimates, and our transmission segment is roughly in line with original expectations. While this is a very difficult quarter, we continue to believe that our distribution, transmission and competitive businesses provide a solid platform to deliver value to our investors, and we appreciate your support. Now I'll turn this over to Leila for a regulatory and power markets update.

Thanks, Tony. Given the significance of the extreme weather and market conditions on our competitive business, I will begin with a discussion of the first quarter impact and then move to a regulatory update. First, extreme weather conditions resulted in customer usage that was about 6% higher than normal during the first quarter. We typically hedge for normal weather, leaving open a small portion of our expected customer load as we enter each month. Increased sales are covered through market purchases, from our peaking generation or a combination of both. This quarter, higher market purchases, reflecting weather and, to a lesser extent, our small open position of less than 3%, decreased earnings by $0.10 per share net of increased sales revenues. Higher prices exasperated the earnings impact of our power purchases. Average prices during the first quarter 2014 were nearly $68 per megawatt-hour or double the 3-year average of about $34 per megawatt-hour. More importantly, however, prices during the most volatile days, the 10 highest-priced days during the quarter, where the average around-the-clock day-ahead price at 80 Hub was between $150 and $500 per megawatt-hour, were what really impacted the quarter's results at our competitive segment. All 10 of these volatile days coincided with untimely outages at some of our units, including Beaver Valley and Mansfield. And we couldn't procure natural gas for our West Lorain peaking plant, which would have helped offset some of that impact. The combination of these events, net of fuel costs and better-than-expected generation at other units, resulted in increased power purchase expense of $0.23 per share. The impact of the 10 days was $0.13 of the $0.23. Ancillary expenses from PJM were also up significantly as a result of January charges that were about 10x higher than normal and that exceeded the charges for the entire calendar year 2013. While we anticipated significant ancillary charges when we spoke to you in February, PJM added a March true-up bill of roughly $0.02 per share, reflecting their decision to socialize these costs across the entire region. Our total share of these expenses amounted to $0.10 per share, while the net effect on earnings was $0.05 per share, reflecting a passthrough of some of these costs to industrial and commercial customers, as well as our decision not to seek reimbursement for about $0.02 in expenses from residential customers. Looking at other drivers. Higher capacity prices drove a $0.07 per share increase in capacity expense. And finally, the deactivation of Hatfield and Mitchell, along with the transfer of Harrison and the hydro unit, improved earnings $0.04 per share, taking into consideration lower fuel, operation, depreciation and interest expense and increased purchase power to replace that generation. As Tony said, we continue our work to encourage consistent and reasonable market rules that help rather than hinder competitive markets, and we are committed to advocating for change in rules, policies and practices that better support reliability and overall market development. At the same time we are working for change, we are also taking several steps to refine our internal practices to adapt to the evolving market dynamics. First, we are taking a far more conservative approach in competitive markets, in light of our current condition. We have increased the risk premium that is built into our retail sales price, which should naturally adjust our glide path strategy to produce a slightly more open position. We currently have 56 million megawatt-hours of committed sales in 2015 and 32 million megawatt-hours committed in 2016. Next, we have taken deliberate action to essentially close the small, unhedged portion that we typically leave open going into each month, and that is in place for the remainder of the year. As we move into the summer months, we have taken additional actions to layer in further hedges that supplement our position for retail load. Our peaking units are also available for additional support in the event of an extremely hot summer and more volatile prices. Finally, we have purchased additional outage insurance, something that we haven't felt necessary for about 15 years, to mitigate the impact of volatile prices during the summer. Our results this quarter were affected by a mix of untimely outages and extreme market conditions. We believe that the actions we have already implemented, as well as other conservative measures for the longer term, will help to mitigate the impact of similar market condition should they occur in the future. Moving now to a review of state regulatory matters. In New Jersey, following the BPU's approval of storm cost stipulation and the return of the 2011 storm costs to the base rate case, the parties were directed to advise ALJ whether additional information is needed before the record is closed. We anticipate a decision in the rate case proceeding later this year. Also in New Jersey, the manner of recovery of the 2012 storm cost remains pending before the BPU. Turning to West Virginia. Before I talk about our recently filed rate case, I want to briefly mention that on April 23, the Supreme Court of Appeals of West Virginia entered an opinion affirming the West Virginia Public Service Commission's order from last October approving the generation asset transfer dealing with the Harrison and Pleasants generating station. As you may recall, we closed this transaction in October after receiving approval from the West Virginia PSC. Now respecting the West Virginia rate case, last week, our Mon Power and Potomac Edison subsidiaries jointly submitted a request to the Public Service Commission of West Virginia for a base rate increase of approximately $96 million or 9.3% and an allowed ROE of 11%. In addition, the plan includes the request to recover the cost of a new right-of-way vegetation maintenance program through a surcharge. Recently, the West Virginia PSC approved the company's vegetation management plan filed last year but postponed consideration of the method of cost recovery to the rate case. In the meantime, as authorized by the PSC, the companies are implementing the plan and deferring the cost with a 4% annual carry charge. If the requested surcharge is not approved in the rate case, these costs would be incorporated into the company's base rate request. The requested rates are subject to review and approval by the PSC. We expect the case to conclude by the end of February 2015 With respect to our plans to file base rate cases in Pennsylvania, we are concluding our analysis and expect to file later this year. And finally, in Pennsylvania, on March 6, the PUC issued an order approving our original smart meter deployment plan. On March 19, the company has filed an updated plan, consistent with that order, that would allow for the entire Penn Power smart meter system, 170,000 meters, to be built by the end of 2015 instead of the originally proposed installation of 60,000 meters by the end of 2016. A procedural schedule, including a hearing tomorrow, has been established to allow the Pennsylvania PUC to consider the plan by early June. We expect installation to begin this summer. In Ohio, the PUCO completed its retail market investigation on March 26 by issuing an order that addresses issues ranging from maintaining SSO service in its current form to requiring corporate separation audits of all electric distribution utilities. Also in Ohio, we expect to file an electric security plan, or ESP, before year end. As you know, the current ESP runs through May of 2016, but we need to get started on the process in order to meet the time required to effectively implement a new plant. We expect that most of the main aspects of the filing will be similar, including the continuation of periodic auctions to procure generation for non-shopping customers, as well as the delivery capital recovery rider, which has served us well in terms of providing a mechanism to recover our ongoing investments in reliability at our Ohio utilities. We are also considering, given the substantial changes in market conditions, whether we should propose an option designed to provide our Ohio customers with more generation price stability and reduced exposure to market volatility. We're still in the early stages of this, and a lot -- and obviously, a lot of thought and discussion with our Ohio colleagues is still to come. It may prove, however, to be an effective way, and perhaps the only way, for Ohio regulators to address the volatility in the market and assure stable prices and adequate supplies for Ohio customers. With that, I'll hand it off to Jim.

Thanks, Leila. As I discuss our financial results, you may want to refer to the consolidated report, which was issued this morning and is available on our website. You'll notice that we have redesigned the consolidated report to provide even greater transparency into the performance of our 3 business units: regulated distribution, regulated transmission and competitive energy services. As Tony mentioned earlier, our first quarter operating earnings of $0.39 per share were within our expectations. These results compare to first quarter 2013 operating earnings of $0.76 per share. On a GAAP basis, first quarter earnings were $0.50 per share this year compared to $0.47 per share in the first quarter of 2013. A list of special items that make up the difference between GAAP and operating earnings can be found on Page 2 of the consolidated report. The largest of the special items in the first quarter was an $0.18 per share gain primarily related to the sale of our hydro units. We also recorded a gain of $0.03 per share related to mark-to-market adjustments. These gains were partially offset by plant deactivation costs of $0.05 per share associated with the closure of our fossil units, a decrease of $0.02 per share related to merger accounting for commodity contracts, regulatory charges of $0.02 per share and a loss on debt redemptions of $0.01 per share. Now let's turn to a review of the key drivers in each of our business segments. I'll begin with our distribution business, with operating earnings of $0.53 per share or an increase of $0.01 per share compared to the first quarter of 2013. Distribution deliveries added $0.09 per share compared to the first quarter of 2013. Heating degree-days were about 17% higher than 2013 and 19% above normal, driving a 6% or 2.3 million megawatt-hour increase in deliveries compared to the first quarter of 2013. Looking at the mix of sales, deliveries to residential customers were up 11%, while commercial sales increased 6%. And as Tony mentioned earlier, when we adjust for the impact of weather, commercial deliveries were up nearly 3%, while residential sales increased about 2%. Deliveries to industrial customers were 1% higher than the first quarter of 2013. Looking back at the past 12 months. On a weather-adjusted basis, we are seeing about a 1% growth in both the residential and commercial sectors and a 2% increase in industrial deliveries. The growth appears to be somewhat steady. And to reiterate Tony's point, we are in pace to achieve the expected load growth across all 3 sectors of our customer segments this year. With respect to other drivers in our distribution business, the impact of the West Virginia asset transfer, primarily reflecting the return on the Harrison Plant, increased earnings by $0.01 per share in the first quarter. The weather contributed to higher operating expenses of $0.06 per share during the quarter. This primarily reflects less capital work completed as a result of the extreme weather conditions and storm-related restoration costs, net of deferrals during the quarter. Finally, distribution earnings decreased by $0.03 per share as a result of higher depreciation and interest expense. Moving to our transmission business. Operating earnings were $0.12 per share or flat compared to the first quarter of 2013 as higher transmission revenues were offset by operating expense and taxes, with most of the higher operating expense due to a greater focus on maintenance activities this quarter. In our competitive business, operating earnings were $0.40 per share below first quarter 2013 results. This was driven by the decrease in commodity margin that resulted from the extreme weather, market conditions and outages that we experienced during the quarter, as Leila described. Total generating output decreased 4.9 million megawatt-hours, primarily reflecting our 2013 plant deactivations, the Harrison and Pleasants asset transfer and planned and unplanned outages. Total contract sales increased 1.3 million megawatt-hours compared to the first quarter of 2013. The total number of retail customers remained flat at 2.7 million, but the channel mix is shifting, consistent with our strategy to target higher-margin sales opportunities. Specifically, direct sales to the large and medium-sized commercial and industrial customers decreased 6% as a result of our strategy to be more selective in light of current market conditions. This decrease was offset in the first quarter by sales in other channels. Structured sales increased 42% compared to the first quarter of 2013 as a result of more municipal, cooperative and bilateral sales, partially offset by lower unit prices due to extreme weather and market conditions that reduced the gains on various structured financial sales. Governmental aggregation sales increased 7%, and POLR sales increased 8%, both reflecting higher weather-related usage. And mass market sales were 19% higher, reflecting the acquisition of new customers, primarily in Pennsylvania and Ohio, as well as weather-related usage. The impact of the extreme weather and market events on commodity margin was offset somewhat by lower operating expenses, primarily related to the plant deactivations and the asset transfer, and lower interest expense due to long-term debt repurchases. Finally, I'll take a moment to review financing options that we have completed so far this year. We extended our 3 existing multiyear revolving credit facilities until March of 2019. As part of this transaction, we increased the FirstEnergy and utility facility by $1 billion, we decreased the FES and Allegheny supply facility by $1 billion and amended the transmission facility to allow greater borrowing at our ATSI and TrAIL subsidiaries. We executed and fully utilized a new $1 billion variable-rate term loan credit agreement with a maturity date of March 2019. Borrowings under this term loan improved our liquidity, as we used proceeds to refinance a like amount of borrowings under FE Corp.'s revolving credit facility. We completed the remarketing of 3 tax-exempt issues totaling $417 million in March at an average coupon of 3.86%, and we received FERC authorization to issue up to $850 million in long-term debt for TrAIL. While the first quarter presented some unusual challenges with regard to the extreme weather and market conditions, we were pleased overall with the strength of our businesses and our regulated strategy, and we'll continue to focus on our core businesses with a commitment to operational excellence, financial discipline and predictable and sustainable growth opportunities. Now I'll open the call up to your questions.

[Operator Instructions] And our first question comes from the line of Dan Eggers with Crédit Suisse. Daniel L. Eggers - Crédit Suisse AG, Research Division: Can we just talk a little bit about kind of retail thought process? I mean, it seems like there's a little bit of a reevaluation of kind of sizing and strategy there. Given the first quarter results, what's going to cause you guys maybe to reconsider how much of a short position you create in the retail business? And based on your contractual commitments, where would you look to maybe reduce your exposure if you're going to maybe more balance that business?

Dan, let me start with kind of a broad-based overview. When you think about our retail strategy, we've always indicated that it is primarily an asset-backed strategy. And we have used -- and we've increased sales, to a certain extent, probably in the 20% to 25% range, based on sourcing from the overall market. We've been comfortable in that range for a number of years now because the markets have been fairly stable. What we're seeing today, however, and what we experienced this winter, perhaps, is a precursor of what we might be looking at down the road as additional generation is taken offline as a result of environmental requirements, increasing forced outage rates as a result of -- essentially, as a result of depressed overall capacity markets. And quite frankly, as we rely more on natural gas to fill the capacity void, the increased volatility that creates inside the energy markets, electric energy markets because of the volatility associated with natural gas. And I think all of those are looking -- all of those are leading us to refine our strategy, to see exactly where these targets ought to be, given what we're seeing now as perhaps something that is going to be more of a long-term event in the energy markets, in particular. So not unlike where we started the process, what level of retail sales are -- can be supported by our generation, what is the appropriate level of retail sales to source in the market, if any, and where that mix is will depend much on what happens in retail markets to reflect the risk premiums that will need to be reflected as wholesale markets have far more volatile energy prices in them. And we're going to take that all into consideration. Right now, I feel pretty good about where we're at because the positions we have going forward, quite frankly, where we're at right now, we're more than 100% hedged with our own generation. So it becomes a function of what markets will provide the best opportunities for the competitive business going forward. Daniel L. Eggers - Crédit Suisse AG, Research Division: Okay. And I guess, if you look at guidance for this year, the update to the CES contribution came down quite a bit, even though you guys hit the midpoint of the range for the first quarter in aggregate. What's bringing down the next 3 quarters of CES, probably, relative to plan? And then what is the cost or the ongoing cost of, maybe, the new hedging or insurance strategies you're using this year to help protect yourselves?

Dan, this is Jim. I'll take a shot at that, and then if Leila and Donny want to add any more cover, I'll hand -- color, I'll hand that off to them. Yes, we hit the midrange of our guidance for this quarter, but several things happened since we gave that guidance, Dan. First off, during the quarter, we did experience better results in our regulated distribution business than what we had expected. We knew that we were going to have higher expenses in the first quarter associated with maintenance expenses, but our revenues were somewhat better than what we expected. And then on the corporate side, we also experienced some benefits against some taxes to a couple of cents. What happened since the call, on the competitive side, we decided that we were not going to bill several cents of the ancillary services. In addition, PJM reallocated some of their expenses from January, and that impacted us by about $0.02. And then March was rather challenging, as we experienced some fairly cold weather and some extreme wholesale market prices on that side of the house. So with that, we had a decrease somewhat in the competitive side. It was offset, though, by the corporate and the regulated distribution side. Looking past the first quarter, Dan, we had some additional expenditures that impacted us. First, the Davis-Besse outage that Tony talked about earlier, it impacted us by a couple of cents. And then we also went out and we bought some additional outage insurance, and we closed all of the remaining positions that were opened for the remainder of the year. So when you take all of that together, that is what drove the midpoint of the competitive energy services from $0.42 to $0.17. Daniel L. Eggers - Crédit Suisse AG, Research Division: And so Jim, when you guys look at next year and beyond, should we assume that this higher level of cost for insurance or locking-in-positions is going to be there? Or is that part of the review of where the retail scaling should be?

I would say that, that will be part of what the retail review and scaling will be. But at this point, I'm not really expecting that we will go out and purchase that outage insurance on an annual basis.

And our next question comes from the line of Julien Dumoulin-Smith with UBS.

So quick first question here. As you think about the impact of polar vortex, et cetera, in the state of Ohio, how are you seeing their willingness to, perhaps, engage in a more longer-term, PPA-like manner with you all and perhaps how that meshes with your upcoming ESP?

Julien, this is Leila. I think they are very focused on that. I think Ohio is not alone in their concern at looking at the polar vortex and the market rules and what they mean in term -- potentially mean in terms of reliability going forward. And I think you're right here in the sense that they dovetail into what might folks want to see within the context of an ESP going forward. So those are the kinds of things that we are looking at now and talking with folks in Ohio about to see what it is that we might do in Ohio that's provided for under Ohio law that might mitigate some of the reliability issues with respect to that and to ensure that they have stable pricing in Ohio.

Could you perhaps just elaborate? How big or substantial are we talking about? What's the ambition here, just to get a better sense?

Julien, I -- that is something that's actively being considered. I mean, that's something that we wouldn't decide solely at our end. We would want to be talking with folks and discuss what is the appetite for this kind of things. So that's the thing that's under discussion right now.

Excellent. And then on the capacity piece, I'd be curious; obviously, you have a capacity auction coming up. What's your latest thoughts on ATSI are and, ultimately, how that dovetails with, I suppose, your April proposal to shift some of the offered cap [ph] rule.

Okay. I'll talk about it generally then turn it over to Donny to maybe give you some more specifics. I think with regard to what FERC has already approved, I think it will have the potential to move the auction a little bit. But I don't think any of the rules currently approved are going to move the auction substantially. I don't think that's consistent with what I'm reading out there. I think longer term, Julien, and what some folks in the industry are talking about among themselves and now with some regulators from a federal level perspective, in order to fix the uneconomic generation issue that folks are talking about, that the Market Monitor talked about in his report, you're going to need more than what PJM has proposed to FERC right now. You're going to need additional changes, both in terms of base residual auction changes that, obviously, wouldn't take place until 3 years out, so I'll call that a longer-term fix. But you have some companies, Exelon notably one of them, that says they're looking to make decisions in the shorter term. And folks are going to have to concentrate and look at, "Okay, what might be a shorter-term fix that will take us to a place where you then have fixed the base residual auction 3 years out?" One of the things that folks are talking about is on-site fuel and looking to give units with on-site fuel some kind of premium in a market that they certainly don't get now, tying into the concept of fuel diversity. So those are some of the kind of things that I would like to see happen. But certainly, not something that we're going to see in an upcoming auction. But with that, I'll turn it over to Donny and his thoughts on the upcoming auction.

She said it pretty well, Julien. I don't have a lot to add. I mean, you kind of think of the plus and minus, if you will. On the plus side, if you're a generator, you've got the retirements that are out there. You've got the import limits. You've got the change that they made to DR. You at least have some suggestion about the arbitrage issues. Whether that gets done before the auction or not, who knows? But on the minus side of the ledger, you've got load forecast is down. You've got a lot of new generation in the queue. We'll have to see what happens there with that new generation. I think that's kind of the wildcard for the upcoming auction, if you will. And generally, I'd agree with Leila. It's possible to see this needle move a little bit in a favorable direction, but not nearly enough to sustain what the PJM needs from a reliability perspective going forward.

Excellent. And just a clarification on Dan's last question there, if you don't mind. If you complete your review, could this drive a higher level of maintenance CapEx going forward? Does that change at all?

I don't see when anything that's happened, Julien, this is Jim, that would drive any additional maintenance CapEx.

And our next question comes from the line of Paul Patterson with Glenrock Associates.

Just looking at the fact book that you guys put out and Slide 151, I guess, the issue of free cash flow. It looks like it's substantially down. Now part of because of the lower income in the guidance. But there's also what appears to be a considerable higher level of collateral, I guess, that you guys expected. And this other item, other seems to have swung kind of negative. And I was just wondering if this is -- how much of this might be sort of an ongoing free cash flow situation that we should think about in 2015 and beyond versus sort of a polar vortex issue now?

Paul, this is Jim. I would say you hit it right. A big driver of that is the earnings that are down. So I would say that's probably associated with at least...

It looks like $100 million. The rest of it -- almost $400 million, it looks like, could be...

I would say there's about $350 million there. We had -- in the first quarter, our collateral, it was up $419 million over the first quarter of last year. We did get some of that collateral returned to us when PJM reset their collateral requirements. We did get about $275 million back. So my expectation is collateral may be somewhat higher for a period of time, but not to the extent we have it right now.

Okay. And that other item that looked like it was almost $250 million swing almost, what is that? And does that continue?

What's the other item you're looking at?

Well, just when we look at cash before other items, you've got high drags on sales, collateral, then other. And other seems like it's $194 million negative now, whereas last year -- I mean, excuse me, last numbers you guys gave was a positive $50 million. So I'm just wondering what's that, and does it continue? I mean, how do we think about 2015, I guess, and going forward in terms of what...

I wouldn't -- that's a working capital item, Paul, so I would not expect that to continue like that.

Can you tell us what it was? Or I can follow up offline.

You can follow up offline.

Paul, will you give me a call after the conference call, and we'll run that to ground for you?

Okay. Okay, fine. And then just in terms of SB 310, there have been some news reports about some changes and amendments to it, perhaps. And I'm just wondering what you guys think about those potential amendments and what you think the outlook for getting this thing done is, and if you could just address that a little bit.

Paul, this is Leila. That is something that changes almost hourly. I do think they are posed to do something. I do think you're right in the sense that the different parties are looking at that and putting forward different compromise proposals as we go along. I can't say that I have a perfect crystal ball as to what's going to come out the other end. But I think, directionally, they are probably going to put forward something that is very positive. I don't think it will look like exactly what has been originally contained in the legislation. But I think from a perspective of saving customers' money in terms of energy efficiency requirements, I think it will come out positive. And I think, hopefully, they're slated to do something, yes, this week in the Senate.

And our next question comes from the line of Stephen Byrd with Morgan Stanley.

I just wanted to talk about 2015 EBITDA for the competitive operations. And we've obviously seen a fairly large runup in power prices. To what extent does that factor in? I honestly would have thought perhaps EBITDA would be a bit higher, given the runup. Can you maybe talk through how the change in commodity prices impacts that 2015 EBITDA?

At this point, Stephen, we have not updated our 2015 EBITDA for the open positions we have right now. So if those open positions are filled at a higher energy price, as we're seeing, then you could see that being driven up. But I'll leave Leila to give you some more color on that.

Actually, Stephen, I think, right now, with respect to our current sales levels in 2015, roughly sold the 56 million. If you were to not sell anything further going into it, just sell it at the current forward market prices, I think we would be within that range of EBITDA. So I think, right now, although we -- obviously, that's something we're going to continue to examine as we go forward, I think we are comfortably within the range and are -- as I said, continue to look at it as we go forward.

Okay. But -- not to press on this too much, but since the last update, I mean, we've seen a very large move in commodity prices. I guess I would have expected that, given that you do have a fair amount of open position there, that the EBITDA would be higher. Are there other offsets or other things we should be thinking about?

I think one of the things you need to think about is the sustainability of the pricing going forward. That's something that we continue to look at. And as Tony mentioned, as we go forward, we're going to be looking at a different mixture of things, potentially. So again, that's something that we will continue to evaluate as we go forward. But right now, we feel comfortable kind of within that range as currently shown.

Yes. I think, Stephen, just to add to that. This is Donny. If you think about where we're at today, Leila mentioned, for 2015, we've sold about 56 terawatt-hours. If you use -- we've given you a range on generation, but -- 75 to 80. If you just pick 76 as our generation, that would say that against our generation, we're about 20 terawatt-hours open. The market's moved kind of roughly about $6 for cal year '15, so you're at about $120 million, and I think our range was right at about $100 million. So what we're saying is things are looking better, obviously, from a wholesale perspective. We've got a nice open position. We haven't quite figured out where we're going with retail sales, so to speak. So just a lot of things in flux there that kind of boil down, and we'll probably be updating that later this year.

Okay. I see. So there has been -- the move upward, that does help you achieve that and helps you feel better about where you might be in that range, it sounds like.

Yes. No question, the upward movement in the market is always desirable.

And our next question comes from the line of Greg Gordon with ISI Group.

My -- not to beat a dead horse, but just to follow up with -- along the lines of the last question. Leila, I just want to make sure I heard correctly, you said that you've sold 56 terawatt hours -- or committed to sell 56 in '15 and committed to sell 32 in '16?

Correct.

And one would presume, given that power prices are up, that your plants would dispatch more. So you've given a range of generation output of 75 to 80 in both those years. Shouldn't I presume that you'd be closer to 80, as with prices up and volatility up, you'd probably run more? Because if I do -- if I run the deltas on power prices from the end of the year, I actually come up with more like a little over $200 million in incremental EBITDA in '15 on 24 terawatt-hour delta. So in order for that -- in order for you to not be above the last range, something would have had to have changed on the negative side in your P&L.

Greg, I think your first comment was fair, but I'm going to turn it over to Donny to address the latter piece.

Yes. No, Greg, I think you're directionally correct. There's nothing that's changed in the P&L that would create downward pressure for '15. We are still evaluating where we want to be with retail sales, how we might want to play the wholesale market, for example. So that's really what's driving the fact that we haven't updated that range.

Okay. And then all things equal in '16, you are long a little less than 50 terawatt-hours today, correct?

Yes. With the 32 that's under contract, and you can plan on us generating somewhere, again, in the 75 to 80 terawatt-hours. That will leave you about -- just short of 50 terawatt hours open.

Okay. At what point do you think you guys will be ready to give us some sort of a mark-to-market or sensitivity analysis on your position as commodity markets do change?

Greg, that's something that we're working on, and we should be in position to do in some future call.

Our next question comes from the line of Naz Comuala [ph] with Fidelity Investments.

I just had a question for you. I wanted to ask about coal piles and if you had any deliverability issues, and just if you could speak to that going into the summer.

Okay. I think our stockpiles are about 24, 25 days right now. We would typically have about 30. So my sense is we probably had some -- experienced some issues this winter, but I wouldn't classify them as significant or overall substantial, the type of things that we typically see, although this winter was a little more challenging on the Ohio river than normal. So we're pretty comfortable with where our inventories are at and our ability to continue to build those as we move into the summer to then have adequate inventories as we move into next winter.

Okay. Have you had to burn any gas in order to keep your coal piles at a certain level, or it's all been normal on that front?

It's all been normal on the front.

This is Jim. I'd like to thank everyone for joining us on the call today. For those of you who are still in the queue to ask a question, a member of the IR department will reach out to you. Our 3 core businesses, distribution, transmission and competitive energy services, provide us with the flexibility to capture value for our investors. Our first quarter results in our distribution and transmission businesses were within our expectations, and we are encouraged by continued signs of a more substantial economic recovery in our service area. And we will continue working to change the rules, policies and practices that currently create both negative reliability and price impacts in competitive markets, and we have taken action to mitigate the impact of current market conditions. We appreciate your continued support, and we remain committed to providing long-term value and sustainable growth. Thank you.

Thanks, everyone.

This concludes today's teleconference. You may disconnect your lines at this time, and thank you for your participation.