FirstEnergy Corp. (FE) Q1 2012 Earnings Report, Transcript and Summary

Meghan Beringer - Anthony J. Alexander - Chief Executive Officer, President and Executive Director Mark T. Clark - Chief Financial Officer and Executive Vice President William D. Byrd - Chief Risk Officer and Vice President of Corporate Risk Leila L. Vespoli - Executive Vice President and General Counsel Harvey L. Wagner - Chief Accounting Officer, Vice President and Controller Irene M. Prezelj -

Dan Eggers - Crédit Suisse AG, Research Division Stephen Byrd - Morgan Stanley, Research Division Steven I. Fleishman - BofA Merrill Lynch, Research Division Julien Dumoulin-Smith - UBS Investment Bank, Research Division Jonathan P. Arnold - Deutsche Bank AG, Research Division Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division Gregg Orrill - Barclays Capital, Research Division Greg Gordon - ISI Group Inc., Research Division Paul Patterson - Glenrock Associates LLC Kit Konolige - Konolige Research, LLC

Greetings, and welcome to the FirstEnergy Corp.'s First Quarter 2012 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Ms. Meghan Beringer, Director of Investor Relations. Thank you, Ms. Beringer, you may begin.

Thank you, Jackie, and good afternoon. During this conference call, we will make various forward-looking statements within the meaning of the Safe Harbor Provisions 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 that 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 Release link. Reconciliations to GAAP for the non-GAAP earnings measures we will be referring to today are also contained in that 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; Mark Clark, Executive Vice President and Chief Financial Officer; Leila Vespoli, Executive Vice President and General Counsel; Jim Pearson, Vice President and Treasurer; Harvey Wagner, Vice President, Controller and Chief Accounting Officer; Bill Byrd, Vice President, Corporate Risk and Chief Risk Officer; and Irene Prezelj, Vice President of Investor Relations. I will now turn the call over to Tony Alexander.

Thanks, Meghan, and good afternoon, everyone. Thank you for joining us today. We will be reporting first quarter results, and quite frankly, they were solid despite the very mild temperatures that Mark will discuss in more detail. Based on these results and our continued confidence in our business strategy, we are reconfirming 2012 and 2013 non-GAAP earnings guidance of $3.30 to $3.60 per share and $3.10 to $3.40 per share, respectively. Turning now to a review of recent events. I'll start with an update on our actions to address new environmental regulations, including the plant retirements we announced earlier this year and the current cost expectation for compliance with those regulations at our remaining fleet. Finally, I'll look at recent state regulatory issues. Then Mark will discuss first quarter results, including recent economic activity across our region and review our retail strategy. Okay, let's get started. As you know, we announced plans earlier this year to retire units at 9 of our older coal-fired plants by September 1, 2012, as a result of the new EPA Mercury and Air Toxics Standards, otherwise known as MATS and other environmental regulations. This includes units at 6 competitive plants in Ohio and Pennsylvania and 3 regulated plants in West Virginia. As a part of this process, PJM Interconnections conducted a review to determine the impacts these retirements could have on system reliability. In March, to address PJM's preliminary reliability concerns, we filed an application proposing approximately 800 megawatts of new combustion turbine peaking generation to be installed at our existing Eastlake plant. It is our intent to offer these units into PJM's capacity auction next week. If they clear the auction, we would begin construction efforts to meet a targeted in-service date of spring 2015. In addition, to bridge the ATSI region to early 2015, PJM's current planning assumption is for reliability must run arrangements, or RMRs, for Eastlake units 1 through 3, Lake Shore unit 18 and Ashtabula unit 5. This involves a total of 885 megawatts, which will help ensure reliable electric service for the Cleveland region. We anticipate that the RMR arrangements will be structured so that PJM will compensate us to keep the units available for operation through early 2015. At that time, we plan to go forward with retiring those units. In addition to the RMRs and the new combustion turbine generation at Eastlake, our transmission group, working with PJM, has identified a number of transmission projects that can be implemented over the next several years and are expected to also improve reliability in the ATSI zone. While we do not have final estimates for the cost of these transmission projects, we are currently projecting a capital spend of between $700 million and $900 million over the next 4 to 5 years. We expect to earn a return on these transmission investments from the time we begin construction. The remaining competitive units slated for retirement, Eastlake units 4 and 5, Bay Shore units 2 through 4, Armstrong and R. Paul Smith are expected to be retired as planned by September 1 of this year. The 3 West Virginia plants included in these announcements are regulated and we have provided the West Virginia Public Service Commission with information regarding the plant deactivations. We also anticipated deactivating these units by September 1. I know many of you are closely following the PJM capacity auction scheduled for next week. Just so we're all clear, we cannot and will not predict the pricing outcome of that auction. We believe the actions we are taking, building 800 megawatts of combustion turbine capacity at Eastlake and the transmission reliability projects, will benefit the region. We continue to fully support and encourage a utilization of competitive market mechanisms to provide the appropriate incentives to all market participants. Turning now to the investment required to address MATS at our remaining coal fleet. At our analyst meeting, we told you Jim Lash's team identified lower cost solutions and allowed us to cut our anticipated expenditures roughly in half, from $2 billion to $3 billion in our original estimate, down to $1.3 billion to $1.7 billion. As we continue to find alternative approaches to meeting these requirements, including the possibility of coal firing certain units with natural gas, I can say that we are now comfortable with the lower end of the revised range. We expect to finalize our plans later this year, and we will continue our efforts to further reduce these costs if possible. Looking now at regulatory issues, starting with New Jersey, where the Board of Public Utilities has requested information about JCP&L's earned rate of return, we have received a procedural schedule from the BPU and filed a brief supporting JCP&L's position. We expect a board response in June. We provide financial information to the BPU quarterly and we continue to believe that JCP&L's electric rates are just and reasonable, and that the Rate Council's request does not provide sufficient reason for the BPU to order a base case rate at this time. Turning now to Ohio. In April, our Utilities filed an application with the PUCO for a 2 year extension through May of 2016 of our very successful Electric Security Plan. If approved, the extension would continue to allow Ohio Edison, Cleveland Electric Illuminating Company and Toledo Edison Company to establish retail generation prices for their standard service customers through a competitive bid process. While similar to the process now used by those companies, the proposed expansion will take the last 2 auctions under the current plan, which are scheduled for this coming October and January of next year, and extend the delivery time frame from 1 year to 3 years. This is expected to benefit the Ohio customers by mitigating potential price volatility that may otherwise occur. The current ESP, which has been in place since June of 2011, has resulted in price certainty, lower prices and more than $10 million in annual economic development funding and low income assistance to FirstEnergy's utility customers and communities in Ohio. More than 20 parties, including the majority of those who were signatories on our existing ESP have supported the new ESP. PUCO has a set of plans to hold hearings on our plan starting on May 21. If our proposed plan is approved in June, we would have the opportunity to capture lower wholesale generation prices and blend those market-based power prices throughout the new ESP period. Also in Ohio, FirstEnergy Solutions continues to be a strong advocate for competition in the Dayton Power & Light market rate offer and AEP Ohio's Electric Security Plan cases. In particular, AEP wants to restrict shopping in its territory by imposing above market capacity charges on competitive suppliers. These charges would severely limit the savings customers in the AEP territory, including a number of large governmental aggregation communities that passed ballot measures last fall, would otherwise achieve from competitive markets and in fact amounts to a windfall for AEP. We expect that PUCO to make a decision on the AEP case by mid-summer. Now I'll turn this over to Mark for a review of first quarter.

Thanks, Tony. And like Tony, I'd like to welcome everyone this afternoon. Today, I will discuss first quarter results, and as part of that discussion, I'll touch on recent economic activity in our region and the continued progress of our retail strategy. As Tony mentioned, we delivered solid results during the quarter, excluding special items, first quarter 2012 non-GAAP earnings were $0.82 per share, compared to $0.75 per share in the first quarter of 2011. On a GAAP basis, this quarter's earnings were $0.73 per share, compared to $0.15 per share in the same period last year. I'll take a moment to remind you that earnings for the first 9 months of 2011, as well as earlier periods, were revised in connection with our adoption of the change announced in January, in the method of accounting for pensions and other post-employment benefit plans. Moving on now to a review of our first quarter results. As in the past, it may be helpful for you to refer to the consolidated report to the financial community we issued this morning. First, I'll take a moment to review the special items from the first quarter of 2012, which are detailed on Page 4 of the report. Special items have the net impact of decreasing this quarter's GAAP earnings by $0.09 per share. By comparison, in the first quarter of 2011, special items reduced GAAP earnings by $0.60 per share. Special items in the first quarter of 2012 included benefit of $0.06 per share for mark-to-market adjustments, which was offset by a $0.05 per share charge related to plant closings, which includes both revenue and expenses, as well as activities in preparation to deactivating the units. A $0.04 per share decrease in earnings related to merger accounting for commodity contracts, and a $0.02 per share related to tax legislative changes. There were also 4 special items that each reduced GAAP earnings by $0.01 per share. They were the impairment of nuclear decommissioning trust securities, merger costs, the impact of non-core asset sales and impairments and regulatory charges. Turning now to the other first quarter drivers, which are highlighted on Page 1 of the consolidated report. As we walk through these, we will once again discuss FirstEnergy on its stand-alone basis with the impact from Allegheny separated. Since there was only 1 month of the Allegheny results included in the first quarter 2011, beginning next quarter, our total company results will be presented in a combined year-over-year format. And in fact, the Allegheny contribution is one of the positive drivers of the first quarter, as it continues to be accretive to earnings, including the impact of shares issued in conjunction with the transaction. On a merger-related note, over the last weekend of March, we successfully completed the integration of our ITN business networks, which include about 100 different systems. While this was and will be a significant synergy item, it was also an important cultural milestone for our employees. It was a tremendous effort. I'm proud of our entire team for accomplishing this task in a remarkably short period of time. Another positive driver was lower operating costs. Last year, we had a first quarter refueling outage at Beaver Valley Unit 2. This year we benefited from having all of our nuclear units in service, as well as from lower costs in our Fossil operations. And the final positive items were lower interest expense and revenue linked to excise taxes. Moving now to items that reduced first quarter results, and since it was such a significant factor during the quarter, I'll start with a discussion of the weather. Nationally, this was the fourth warmest winter in the last 117 years and the warmest month of March since 1950. We certainly experienced the same conditions in our region, where heating degree days were 25% below 2011 levels and 22% below normal. In fact, when we look at the impact of abnormal whether on our company as a whole, including all 10 utility companies and generation sales, the cumulative impact was $0.12 per share this quarter. Obviously this affects our full year earnings forecast, but as Tony said earlier, we are reaffirming our guidance for 2012 and 2013 based on the strong performance of our retail business. Let's now turn to the distribution deliveries which reduced earnings by $0.05 per share. The extremely mild weather resulted in a 4% decrease in total distribution deliveries. Residential deliveries decreased 8%, while commercial deliveries were down 2% and industrial deliveries were relatively flat for the company as a whole. However, consistent with the recent trend of growth in certain pockets of the regional economy, industrial activity continues to improve in Ohio. Sales to that group were up 3% versus the first quarter of 2011. As a number of our steel customers expand to meet demand from shale gas exploration, including a new mill at the Republic Steel facility in Lorain, Ohio. As you know, our service territory sits directly atop both the Marcellus and the Utica shale formations. In addition to jobs and growth in the steel sector, this is also translating into an uptick in investment associated with drilling activity and infrastructure in our Pennsylvania and Ohio service areas. The state of Ohio had the fourth largest increase in job growth in the nation in 2011, and data is showing that 9% of the new employment is related to shale exploration. It's encouraging to see growth in our region and like everyone else, we are hoped to continue seeing more positive signs, especially in the commercial and residential sectors. Let's move now to commodity margin, which decreased earnings by $0.02 per share overall this quarter. As always, when we discuss commodity margin, we're talking about the interplay of many different components. In each quarter we like to break out the positive and the negatives. A detailed summary can also be found on Pages 2 and 3 of the consolidated report, including additional information on megawatt hour volumes. Before I get into the individual elements of commodity margin, I'll note that generation output from our ongoing competitive fleet, which excludes those units we plan to retire or deactivate, decreased by 2.4 million megawatt hours or 13% compared to the first quarter of 2011, reflecting lower demand and soft power prices. Nuclear output increased due to the absence of any refueling outage in the quarter. This was offset by a lower output from our supercritical fossil generation and lower utilization of our subcritical fleet, which continues to be impacted by low natural gas prices. While our coal inventory increased with the decline of Fossil output, we also took advantage of certain market opportunities to build our inventory above what we would consider typical levels for this time of year. This had a negative impact on cash in the first quarter, which we expect to reverse over the remainder of the year. Let's move on to the 5 items that decreased commodity margin. These include: increased capacity expense as a result of FES serving more retail load; higher purchased power cost, chiefly related to economic purchases; a reduction in FES wholesale electricity sales to the spot market; lower sales of Renewable Energy Credits; and finally, a decrease in net financial hedges associated with the FES sales in generation portfolio. Looking now at the 4 positive elements of commodity margin. First, our generation fleet earned high-capacity revenues in connection with ATSI's June 2011 transition from MISO to PJM. We also experienced lower PJM congestion, network and transmission line loss expense. Fuel expenses were lower, primarily related to the impact weather had on demand. And finally, FirstEnergy Solutions continues to successfully execute its retail strategy by hedging or selling forward to retail customers and by shifting sales volumes within and among retail channels, we believe we have significantly mitigated the financial impact of the weakness in the wholesale markets. Contract sales increased 9% in the quarter, as FES experienced a 28% increase in direct sales, a six-fold increase in NAS market sales and nearly 1 million megawatt hour increase in structured sales. A significant portion of the growth in direct and NAS market sales took place outside our traditional footprint in markets including Central and Southern Ohio, Pennsylvania, Illinois, Michigan and New Jersey. Government aggregation sales were lower for the quarter as the result of weather, but FES continues to successfully expand this channel. In fact, you'll recall that 50 communities in Central Ohio voted to adopt governmental aggregation for their electric service last November. FES won 42 of those contracts, or about 90% of those communities that have selected a supplier and began service to some of those communities during the first quarter. While FES had a similar impact associated with weather, their success at increasing the movement of sales from polar to direct and the movement within and across channels essentially offset a portion of the negative weather impact. FirstEnergy Solutions' hedged position for the balance of 2012 is now at 91%, and we are at 60% for 2013. Let me close with a brief overview of our financing activities. As I referenced earlier, we are in the process of putting together a new $1 billion transmission company credit facility, and extending our existing $4.5 billion credit facility by 1 year through 2017, which will provide us with a solid liquidity position going forward. We are also in the process of negotiating the early buyout of the 1987 Bruce Mansfield sale leaseback arrangement, which will take a future obligation off the table opportunistically. And finally, this quarter we plan to file an application seeking a financing order with the PUCO under the new Ohio securitization legislation, as we've already announced. Together, these initiatives continue our progress towards the financial initiatives outlined last year and at our February Investor Day. Combined, these initiatives place us in a much stronger position for the increase in capital program over the next several years. As Tony mentioned, we are aggressively managing our MACT spend, and now expect to be at the low end of the $1.3 billion to $1.7 billion range we announced at the February analyst meeting. That is well down from the initial $2 billion to $3 billion estimate and importantly, we continue to evaluate options for further reductions. We're also addressing incremental capital spending related to building 800 megawatts of combustion turbine generation at Eastlake, as well as the projected transmission reliability investments all over the next 4 to 5 years. Although we will continue to assess our overall capital program, we are likewise evaluating our funding opportunities for these projects. As Tony said, we are pleased with our results for the quarter, and more important, we are confident that we are on track to meet our goals and guidance for the year. Thanks for listening. And now I'd like to open up the call to your questions. Thanks.

[Operator Instructions] Our first question is coming from Dan Eggers of Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: It looks like you guys are on course to get the customer shift you were looking for, but the EPA issues have probably complicated the story a little bit. If they were to be successful in front of commission and you do see the reversal in the shopping caps, how would the mix shift that you guys saw this quarter potentially reshuffle if you started mitigating some of the contracts because the capacity prices got goofy?

I think it wouldn't change our strategy at all. I mean, we've got aggregated communities that voted to aggregate. As I said earlier, Dan, we've moved additional load into Pennsylvania, Michigan, Illinois. So there are a lot of markets outside of Central Ohio, but we're really pleased with where the retail group is and what they've been able to do, particularly shifting megawatt hours within channels and into different markets. So I don't think it would change what we're doing one iota. Dan Eggers - Crédit Suisse AG, Research Division: Okay, and then on the coal generation side, with the low output on the sub-criticals and the super-criticals as well, can you talk a little bit about your coal supply considerations and inventories and if you're continuing to shift your expectations for coal generation output for the year versus the analyst day?

Yes, I think that's a great question. We are shifting our focus. We had some opportunities to build up our coal inventory in the first quarter. Those opportunities are no longer are there and we will be reversing that and actually burning down our inventory over the last 9 months of the year. And on a cash basis, we expect to end about where we thought at the beginning of the year. So cash to cash, it's about even. We just took advantage of some opportunities and we're pleased where we are. But a little long from where we would normally be, but nothing out of the norm. Dan Eggers - Crédit Suisse AG, Research Division: So we shouldn't be perpetuating the 16% utilization rate on the sub-criticals for the rest of the year, I guess, is the punchline?

No, I wouldn't.

Our next question is coming from Stephen Byrd of Morgan Stanley.

I just wanted to talk about the retail business. It looks like you've had great success in expanding your sales there. Could you talk a little bit about the competitive dynamics in the context of the pricing that you're getting on sales relative to -- as you see trends in power prices relative to hedge prices, are you seeing the ability to weather the storm in terms of the economics of hedges relative to changes in just power prices which are driven by gas? Are you seeing that sort of as a -- is that turning out to be a good buffer or are hedges on that side following directly along with power price moves?

I'd take for this year, 91%'s already sold. So it's not going to have much impact next year at 60%. One of the avenues that we're using to address the power prices, and I think our retail group's done a great job is understanding the margin within each channel within each EDC, within each channel, so we can move megawatt hours between EDCs to try to generate higher margin and then move between channels themselves to generate higher margin on the same megawatt hour, so power prices being power prices what they are, there is a certain reality to it, but we're pretty comfortable with where we are, we're getting away from the polar, more on to the direct, more contract, extending some of the contracts out for longer terms. I think we're pretty comfortable. I don't know. Bill, do you want to add anything?

I agree with everything Mark said. It's 5 to 1 [ph], so I mention that the, inevitably, over time, our retail revenue will reflect market conditions if they don't change, but that movement to market will take years given our retail strategy. It's not something that would occur very quickly.

Our next question's coming from Stephen Fleishman of Bank of America Merrill Lynch.

Just a question regarding your comments on the funding some of the new projects such as the transmission. At one point in time, you had talked about potentially selling transmission or the like. And I'm just curious if the funding opportunities could be something where you would think about separating out transmission in some way, or is it more likely traditional sources?

I think it's more traditional sources. Transmission right now is a strong contributor to earnings. It helps support the dividend. It generates a nice return. I think Jim is looking at the more traditional sources of funding. I don't know if you want to speak to that. But no, I -- we're not looking at selling any transmission asset or anything like that. We're just trying to fine tune what the MACT spend is going to be. We're trying to fine tune what demand sell lease purchase price is going to be, and in the context of all of that, we'll be tweaking our overall funding strategy.

Okay. And I guess one other question is just, maybe I don't know if maybe Bill wants to address this, but just the change in dynamics in PJM, coal to gas switching, some of the things they've seen. Is it affecting in any significant way that the basis of your different generation assets that's meaningful to the value of those assets? Or is it not that big a difference?

It's not really that big of a difference. The basis has shrunk with the decrease in overall market levels, but we aren't seeing anything that wouldn't be explained with consistent movement with the overall market.

Our next question is coming from Julien Dumoulin-Smith of UBS.

So first on the transmission CapEx what you delineated there over the next 4 to 5 years, in terms of timing, is that sort of nearer term or is that toward of '15, '16, '17 spending, primarily?

That's a good question. I just spoke to the head of our Utilities group yesterday about that question. It's pretty even. There's a little bump up in '14, a little bump to '15, but it's not outrageous or anything like that. It's fairly smooth over the period of time, but we're just really, to be honest with you, in the initial phases of it, they're doing a lot of work, we have asked them to look at different things. This is probably similar to MATS. We get into it, we start looking at different options, scenarios, trying to figure out different ways to reduce our cost. So it's, I would say for planning purposes, it's smooth, but it is very, very preliminary.

And how much of that is at risk around potential competitors trying to do comparable transmission projects, it would seem?

Well, I think the utilities are going to do the projects, or they could assign them to ATSI or TrAIL or one of those, I don't, I mean that thought's never even crossed my mind. So...

That's a good sign. And then frankly, on cost-cutting, looks like a pretty strong first quarter here. What is the trend year-to-date? How are we looking, maybe more structurally beyond that? I know you guys always kind of take a hard line.

I think one of the biggest benefits as we're still seeing the synergy savings I alluded to. Having all of our systems integrated now means that all of our operating groups are on the same working platform. It also means that we can start reducing the size of the IT staff, because they're all integrated. So I think those of you that know Tony know that he's never satisfied with us unless we're taking a hard look at all of our expenses.

Great. And just a quick last one on DR. You guys alluded to on the ESP, with regards to potential bidding and some incremental into the upcoming auction, but that depended on the timing of the approval. Could you maybe talk about how much incremental DR you're thinking about, I mean, that's not asking about forecasting price or anything, but just anecdotally between yourselves and others, what you're kind of seeing out there?

Hello, this is Leila. With respect to the demand response, we would have needed a commission order before the capacity option. Given the current schedule that is not going to happen. So I would not anticipate any demand response being embedded into the capacity option. And let me explain the rationale for that. Our current ESP only goes -- it ends the day before the period of the next auction would start. So in terms of what the Utilities would have to bid, they don't have any customers, they don't have a tariff that would be in place for that period of time, so it would be impossible for them to bid any demand response into the auction. So by missing the deadline, at least that portion of what we had contemplated going forward within on the ESP would drop off. But as Tony mentioned, there are still other benefits associated with the ESP that would hopefully require a timely order by the commission.

Our next question is coming from Jonathan Arnold of Deutsche Bank.

Hello, guys. I was just -- on the transmission investment again, sorry to come back to this. Could you give me a little bit more detail about what kinds of things, these -- are they lines or is it upgrading of substations and the like? And are these upgrades embedded in the parameters that PJM modeled, so when they did the remodel of the auctions. So I know you've been in talks with them about how to address reliability. So just curious how that works into the planning process.

Now Jonathan, we can give you a little bit of detail on that, and I think both of these projects have been identified as part of the PJM process. So I'll give you a high level, Bill can fill in the details. But probably 3 major components. One there'll be some substation enhancements that'll be added to the system. So we'll be expanding several substations and perhaps even adding a couple in the process. We plan on taking some of the existing generation resources that are being retired and adding or making them synchronized condensers, and third would be long lines. We have some open towers that we will be stringing additional wire on into the region and more longer-term, probably an additional line into the Cleveland area. So those are basically the components. So it's really structural in terms of substations, fold-in support through synchronous condensers, and some additional lines going into the region.

Jonathan, if you would contact our investor relations folks after the meeting, they can provide you with a link to the PJM website. PJM posted a document last Thursday that delineates each and every transmission project. There's 4 to 5 dozen projects and additionally, they can provide you with a link to a -- the meeting material from the PJM transmission expansion advisory committee meeting on Friday, which gives you more detail and information on these projects that you can ever hope to digest.

Was my summary okay? I gave you the highlights, you can get into the details later, Jonathan.

Yes, I'm taking that to mean that then most of these are in a kind of they're out there and known about.

Yes, 1 of the 3 buckets.

Okay, and can I ask on one other thing. I noticed in your commentary about sales in the quarter you'd sort of attributed the decline mostly to mild weather, which seems to suggest that there was some underlying pressure on usage that that wasn't explained by weather. Is that what you're saying and could you comment on such usage generally what you're seeing with customers?

I think -- hopefully, I said the opposite. Weather was a significant driver. Residential obviously is weather driven. Commercial, generally the smaller commercial, is weather driven. Industrials were flat. Ohio industrials are up 3%, and we're seeing a lot of good shifting of margin within and around the channels of the retail group. So in the FES's case, they've actually offset some of the weather impact. So I would say it's the opposite.

Within distribution mark, when you kind of made the comment about of just deliveries, so not so much about your margins but just more what you're seeing in underlying trends.

I think the underlying trend for the quarter was weather. And then industrials are flat across the system, but up in Ohio. Our head of our Utilities group mentioned to me this morning they're adding a third shift up at the Ford facility in Cleveland. That's the first time they've had a third shift in I can't recall when. Lordstown just got off 3 shifts working 24 hours a day. You've seen a lot of investment activity. I guess I'd have to say I'm optimistically positive.

Our next question is coming from Paul Ridzon of KeyBanc.

In your 2012 earnings guidance, the uplift from a full year of Allegheny was $0.26 I believe, and that looks like it dropped to $0.17. What drove that, just weather?

I don't know. Harvey?

I would say it's just operations. Right.

But that $0.26 was -- also has been captured in the first quarter, correct?

No, I think weather in first quarter attributable to Allegheny was $0.02. I'd have to sit and -- I don't know.

We can do a more granular analysis for you offline.

Give us a call after the call, and we'll walk you through it.

Our next question is coming from Hugh Wynne from Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: I have to say I was very impressed by your ability to maintain your commodity margin largely intact even as power output fell by 1/8. That really shows the retail strategy paying off. But my questions go to a couple of other points. I want to understand the sustainability of some of the earnings gains you had, particularly within commodity margin, your net MISO PJM transmission turned into a contribution this year of $0.10. And is that something that's likely to reverse? Is that related to the low levels of power demand? Or is it related to the re-dispatch plan from the low gas price environment? Or is this something that we can expect to see again in the future?

Hugh, this is Bill Byrd. That's largely reduced congestion expense on the grid, relative to historical periods. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Right. I understand, but is it something that we'd like to see or expect to see again? Or do you think it's related to the low level of power demand or the re-dispatch of the power plants? Or something that's likely to reverse in the future?

I'm not sure I'd say it's likely to reverse, but it certainly reflects current market conditions and will reflect future market conditions. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Okay. And then similarly on your O&M, you mentioned that the O&M expense is down, partly due to the absence of the nuclear refueling and the lower Fossil O&M expense. Is that a gain in earnings power that we would likely see reduced in future if the load following plants would operate at more normal levels?

I don't think so. I think we'd look at whether we'd do an economic purchase or run our own units, particularly the subcritical units. Clearly, we're better when the nukes are running, they dispatch lowest possible cost of our fleet. No, I wouldn't say that would be the case. I think we've done more economic purchases with some of the lower power prices. Nukes are running flat out, and the critical units are running itself. No. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: I don't think we're quite not talking about the same thing, though. I'm not talking about purchase power, just the operation and maintenance expense. Is the low operation and maintenance expense related to the low operation of the load-following plants?

Well, we're not going to spend money on overtime. We're not going to spend a lot of money given the low power prices. We're not going to accelerate units coming back online justified, unless the price justifies itself. If the price stays down, we'll run the units commensurate with where the market is. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: And consequently, incur the lower O&M?

Yes, yes.

Our next question is coming from Gregg Orrill of Barclays Capital.

I was wondering if you could talk a little bit more about the lower estimate for the MAC spending and what's behind that?

Oh I think in the main, Gregg, we are pushing very hard at looking at all of the options that are available to us. I think the first analysis was a, essentially a capital solution. The second analysis is what can we do to drive capital cost out and improve the overall operation of the plant. So for example, investigating using natural gas as a co-firing vehicle which reduces the amount of, obviously it reduces the amount of emissions you have to treat, and improves the overall efficiency of the equipment that is already on many of our large facilities. So we're just continuing to push hard on the engineering and the alternatives that might be available to continue to operate the fleet inside the EPA requirements, but with the least amount of capital as possible.

Sometimes I think it is as simple as challenging the assumptions and the concepts our engineers come up with.

Our next question is coming from Greg Gordon from ISI Group.

So you guys said earlier that you expected that you would burn down some of your coal inventory by year end.

Yes.

And I'm just wondering as we think about your bidding -- your dispatch behavior in the market, I mean, right now we're in a shoulder period. Gas is displacing ahead of coal. We're going to get into summer, and most of your power generation resources are going to be necessary to be utilized, but wouldn't coal still be dispatching as a sort of a peak resource and wouldn't you be cycling down in the off-peak, or how are you thinking about bidding behavior? Are you going to bid in at assuming spot price per coal, the weighted average cost of coal? Explain to me how, even with the dispatch order having flip-flopped, you still expect to be able to run the plants at a relatively low cost and burn down these piles. I'm just a little bit confused given what we sort of know to be what's happening in the marketplace.

I don't know if I said we were reversing our dispatch order. We sold out 91% for '12, so we're going -- not to be selling a lot into the wholesale market anyways, we weren't planning on it. So, now Bill, you want to...?

And I think it's -- we're aren't talking about any radical change in anything. I think it's a change at the margin, if you will, during the past quarter and past winter. Maybe if we could back pyre instead of generated and save $0.10, we would make that decision on a daily basis. Going forward, we'll put more emphasis on the wear and tear that, that creates on the unit, and that same decision going forward, we would say let's generate the power and not buy it. So I think it's just a slight change in emphasis and how to balance the cost and economics, if you will, on the margin.

Greg, I think that to Bill's point, if you assumed that coal was up maybe $100 million in cash for the quarter and we buy around $2.5 billion, you can get a sense that we're not talking about big changes to get back in line.

Our next question is coming from Paul Patterson of Glenrock Associates.

Just a follow-up on Hugh Wynne's question on the net MISO PJM transmission expense. If I understood you guys correctly, you see these market conditions are continuing and that benefits sort of going forward for some time, is that correct? Is that how we should think about?

Yes. This is Bill Byrd. One thing I forgot to mention in responding to Hugh, another aspect of that decreased congestion is first quarter of '11, a lot of our plants were still in MISO. Now they're all inside the fence of PJM and that helps not having to cross the interface, helps tremendously with our congestion expense and that will be a sustainable benefit, regardless of market levels.

Okay. And then on the net financial sales and purchases that was sort of a negative $0.05. Can you elaborate a little bit about that?

I'll let Bill comment too, but I mean you have the economic purchases and you have the revenue on the other side. So I don't know if that's what you mean.

Well, I'm just sort of wondering how we should think about that going forward?

Primarily those financial purchases were basis swaps per hit, basis hedges which were fixed for floating swaps. So when our underlying basis expense was lower, the hedge came out negative.

That makes sense. Okay. And then there was a court order that came out in Michigan with AEP's capacity formula rate case that you guys were a party to, that you guys I think protested, actually. And there was an order that came out yesterday. And I was wondering just what's your thought about that and perhaps the implications for how it might be related to what we see in Ohio, with the deferred case that AEP has there which you guys are also, I think, involved in. Any thoughts you'd like to share with us that?

Paul, this is Leila. I haven't had an opportunity yet to read the order, but my sense about it is that it's a good signal in that they indicated to AEP that the proposed pricing might be high. There are a lot of good signals in that case, so obviously we'll be looking to that going forward because I think you're right in that it could be setting a tone for what happens here in Ohio. But I think what came out of Michigan yesterday was a positive side, a very positive side.

Okay, great. And then just on the energy efficiency impact on the ATSI situation does it serve what the DR, I guess that you were talking about earlier that I guess will not be bidded in now. Could you give us a sense as to how much that was in megawatts?

The demand response if you kind of look at what we have in our current ESP under the tariff, roughly 200 megawatts. So that will be the asset that has not bid in. The energy efficiency component is actually a separate kind of thing. That piece of it will likely be bid to the auction, the upcoming auction.

Okay. Great. And then finally the distribution deliveries. Did that -- did those figures include the leap year? I'm sorry if I missed that.

Yes. Jackie, how about if we take one more -- we have time for one more question.

Our last question is coming from Kit Konolige of Konolige Research.

So maybe you could just review a little bit more, you talked about the total of 5 negative deltas in the commodity margin and 4 positives. Should we be able to think of these as some of the pluses and minuses being related or offsetting for example, wholesale sales are down, contracted sales are up, fuel expense versus purchase power. Can you discuss the offsets that kind of logically fit together there?

Actually you were doing a pretty good job. So there are offsets and I think you were just going right down the list. If you do one, you have the other. Purchase power is maybe up for economic reasons, but fuel will be down. Wholesale, as we close out our position in '12 and we're already over 90%. You would expect to see lower wholesale sales, and market has an effect on that as well. So I think you've got it nailed pretty well. Thank you. And thank you all for joining us today. We certainly appreciate your continued support and interest in FirstEnergy and thank you.

Thanks, everyone. Bye now.

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you all for your participation.