第一能源 (FE) 2012 Q1 法說會逐字稿

Greetings and welcome to the FirstEnergy Corp. first quarter 2012 earnings conference call. At this time all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (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. 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 re-confirming 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 will 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 nine of our older coal-fired plants by September 1, 2012 as a result of the new EPA Mercury and Air Toxic Standards otherwise known as MATS and other environmental regulations. This includes units at six competitive plants in Ohio and Pennsylvania and three regulated plants in West Virginia. As a part of this process, PJM Interconnection 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 megawatt's 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 megawatt's 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 four to five 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 four and five, Bay Shore units two through four, Armstrong and R. Paul Smith are expected to be retired as planned by September 1 of this year. The three West Virginia plants included in these announcements are regulated and we have provided the West Virginia Public Service Commission with information regarding the plant de-activations. We also anticipate deactivating these units by September 1. I know many of you are closely following that PJM capacity auctions scheduled for next week. Just so we are all clear, we can not and will not predict the pricing outcome of that auction. We believe the actions we are taking, building 800 megawatt's of combustion turbine capacity at Eastlake, and the transmission reliability projects, will benefit the region. We continue to fully support and encourage the 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 that 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 co-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 the 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 Counsel's request does not provide sufficient reason for the BPU to order a base rate case at this time.

Turning now to Ohio, in April, our utilities filed an application with the PUCO for a two-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 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 extension would take the last two auctions under the current plan, which are scheduled for this coming October and January of next year, and extend the delivery time frame from one year to three. This is expected to benefit 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 said it 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 continue to be a strong advocate for competition in the Dayton Power and 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 a competitive markets and in fact, amounts to a windfall for AEP. We expect the PUCO to make a decision on the AEP case by mid-summer.

Now I will turn this over to Mark for a review of first quarter.

Thanks Tony, and like Tony I would like to welcome everyone this afternoon. Today I will discuss first quarter results, and as part of that discussion, I will 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 will take a moment to remind you that earnings for the first nine months of 2011, as well as earlier periods, were revised in connection with the 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 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 four of the report. Special items had 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 a benefit of $0.06 per share from 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 $0.02 per share related to tax legislative changes. There were also four special items that each reduced GAAP earnings by $0.01 per share, they were, the impairment of nuclear decommission 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 one of the consolidated report. As we walk through these, we will once again discuss FirstEnergy on a standalone basis, with the impact from Allegheny separated. Since there was only one month of the Allegheny results included in the first quarter of 2011. Beginning next quarter, our total Company results will be presented in a combined year-over-year format. And in fact, the Allegheny contribution was 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 included 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 am 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 will 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 weather 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 explorations. It is encouraging to see growth in the region and like everyone else we hope to continue to 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 are talking about the interplay of many different components. And each quarter, we like to break out the positive and the negative. 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 increase due to the absence of any refueling outage in the quarter, this was offset by lower output from our supercritical fossil generation and lower utilization of our sub-critical 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 five items that decreased commodity margin. These include, increased capacity expense as a result of FES serving more retail load, higher purchase power costs, 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 and generation portfolio. Looking now at the four positive elements of commodity margin, first our generation fleet earned higher capacity revenues in connection with ATSI's June 2011 transition from MISO to PJM. We also increased 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 mass market sales, and a nearly 1 million-megawatt hour increase in structured sales. A significant portion of the growth in direct and mass 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 the direct channels, 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 credit facility and extending our existing $4.5 billion credit facility by one 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 lease back agreement which will take a huge 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 toward the financial initiatives outlined last year and at our February investor day. Combined, these initiatives place us in a much stronger position for the increasing capital program over the next several years.

As Tony mentioned, we are aggressively managing our MATS 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 to $2 billion to $3 billion estimate and importantly we continue to evaluate options for further reductions. We are also addressing incremental capital spending related to building 800 megawatt's of combustion turbine generation at Eastlake, as well as the projected transmission reliability investments, all over the next four to five 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)

Dan Eggers, Credit Suisse.

It looks like you guys are on course to get the customer shift you were looking for, but the AEP issues have probably complicated the story a little bit. If they were to be successful in front of Commission and you see the reversal in the shopping caps, how would the mix shift that you guys saw this quarter potentially re-shuffle if you started mitigating some of the contracts because the capacity prices got goofy?

I think it wouldn't change our strategy at all. 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 are really pleased with where the retail group is and what they've been able to do particularly in shifting megawatt hours within channels and into different markets. So, I don't think it would change what we are doing one iota.

Okay, and then on the coal generation side, with the low output on the subcriticals and the supercriticals as well, can you talk a little bit about coal supply considerations and inventories and if you are continuing to shift your expectations for coal generation output for the year versus the analyst day?

Yes, I think that is a great question. We are shifting our focus. We had some opportunities to build up our coal inventory in the first quarter. Those opportunities no longer are there and we will be reversing that and actually burning down our inventory over the last nine months of the year. On a cash basis, we expect to end about where we thought at the beginning of the year. So, cash-to-cash it is about even, we just took advantage of some opportunities and we are pleased to where we are. A little long from where we would normally be, but nothing out of the norm.

So, we shouldn't be perpetuating the 16% utilization rate on the subcriticals for the rest of the year, I guess is the punch line?

No. I wouldn't.

Okay. Great. Thank you guys.

Thanks Dan.

Stephen Byrd, Morgan Stanley.

Just wanted to talk about the retail business. Looks like you've had great success in expanding your sales there. Could you talk a little bit about the competitive dynamics and in the context of the pricing that you are getting on sales relative to, as you see trends of power prices relative to hedged 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 a -- is that turning out to be a good buffer or are hedges on that side following directly along with power price moves?

I think, for this year, 91% is already sold so it's not going to have much impact. Next year it's 60%. One of the avenues that we are using to address the power prices and I think our retail group has 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 are pretty comfortable with where we are. We are getting away from the POLR, more into the direct, more contract, extending some of the contracts out for longer terms. I think we are pretty comfortable, I don't know, Bill you want to add anything?

I agree with everything Mark said. It's spot on. I would also mention that 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 is not something that would occur very quickly.

Great, thanks very much.

Thanks.

Steve Fleishman, BofA 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 more traditional sources?

I think it is 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, we are not looking at selling any Transmission asset or anything like that. We are just -- we're trying to fine-tune what the MATS spend is going to be. We're trying to fine tune what the Mansfield sale lease purchase price is going to be and in the context of all of that we will be tweaking our overall funding strategy.

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

It is not really that big 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.

Okay, thank you.

Thanks, Steve.

Julien Dumoulin-Smith, UBS.

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

That is a good question, I just spoke to the head of our utilities group yesterday about that question. It is 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 is fairly smooth over the period of time, but we are just really to be honest with you in the initial phases of it. They are doing a lot of work. We've 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 costs. So, I would say for planning purposes, it is smooth, but it's 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 orone of those, I don't think -- that thought has never even crossed my mind. So --

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

Well, I think what are the biggest benefits is we're still seeing the synergies savings that 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 are all integrated. So, I think those of you that know Tony know that he's never satisfied with us unless we are taking a hard look at all of our expenses.

Great and just a quick last one on DR, you guys alluded to in the ESP with regards to potentially bidding in some incremental into the upcoming auction but that depended on timing of the approval. Could you maybe talk about how much incremental DR you are thinking about, just not asking about forecasting price or anything, but 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 auction. Given the current schedule, that is not going to happen. So, I would not anticipate any demand response is being bid into the capacity auction. 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 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.

Great, thank you very much.

Jonathan Arnold, Deutsche Bank.

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

No. Jonathan we can give you little bit of detail on that and I think most of these projects have been identified as part of the PJM process. So, I'll give you a high level, Bill can in the details, but probably three major components. One, there will be some substation enhancements that will be added to the system. So, we will 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 synchronous condensers. And the 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 is really structural in terms of substations, voltage 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 are four to five dozen projects and additionally they can provide you with a link to the meeting material from the PJM Transmission Expansion Advisory Committee meeting on Friday which gives you more detail and information on these projects than you can ever hope to digest.

Was my summary okay?

Yes. (laughter)

Those are the highlights you can get into the details later, Jonathan.

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

Yes, one of the three buckets.

Okay and could I ask one other thing on, I noticed that in your commentary about sales in the quarter, you attributed the decline mostly to mild weather, which seemed to suggest that maybe there was some underlying pressure on usage that wasn't explained by weather. Is that what you were saying and could you comment on 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 were up 3% and we're seeing a lot of good shifting of margin within and around the channels of the retail groups. So, in FES's case they've actually offset some of the weather impacts. So I would say it is the opposite.

(Multiple Speakers) Within distribution Mark, where you kind of make a comment about just deliveries, so not so much about your margins but more what you are seeing in underlying trends.

Well, 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 has got all three shifts working 24 hours a day. You've seen a lot of investment activity. I guess I would have to say I am optimistically positive.

Great, thanks a lot.

Paul Ridzon, 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, Mark?

I would say it is just operations.

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

I think weather in the first quarter attributable to Allegheny was $0.02. I have to sit and -- we can do a little bit more granular analysis for you off-line.

Paul, give us a call after the call and will walk you through it.

Sounds good, thank you.

Hugh Wynne, Sanford C. Bernstein.

I have to say I was very impressed by your ability to maintain your commodity margin largely intact even as power output fell by an eighth, 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 is likely to reverse? Is that related to the low levels of power demand or is it related to the redispatched plants and 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 is largely reduced congestion expense on the grid, relative to historical periods.

Right, I understand, but it is something that we would like to see or expect to see again or do you think it is related to the low-level of power demand or the redispatch of the power plants or something that is likely to reverse in 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.

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 were to operate at more normal levels?

No. I don't think so. I think we would look at whether we do an economic purchase or run our own units, particularly the subcritical units. Clearly we are better when the nukes are running, they dispatch at the 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. So, no.

I don't think we're quite talking about the same thing though.

Okay.

Not about purchase power, just about the operation and maintenance expense. Is the low operation and maintenance expense related to the low operation of the load following plants?

Well we are not going to spend money on overtime. We're not going to spend a lot of money given the low power prices and we're not going to accelerate units coming back online unless the price justifies it. So, if the price stays down, we'll run the units commensurate with where the market is.

And consequently incur the lower O&M?

Yes, yes.

Thank you.

Ashar Khan, Visium.

My question has been answered. Thank you.

Thank you.

Gregg Orrill, Barclays Capital.

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

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 essentially a capital solution. The second analysis is what can we do to drive capital costs 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 reduces the amount of emissions you have to treat, and it improves the overall efficiency of the equipment that is already on many of our large facilities. So, as you -- we are 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.

Thanks Tony.

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

Greg Gordon, 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, right now we are in a shoulder period. Gas is displacing ahead of coal. We are going to get into the 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 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 for coal, weighted average cost of coal? Explain to me how, even with the dispatch order having flip-flopped, you ask 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 know to be what is 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 to not be selling a lot into the wholesale market anyways and weren't planning on it. Bill, you want to --?

I think it's -- we are not talking about any radical change in anything. I think it is a change at the margin, if you will. During the past quarter and past winter, maybe if we could buy power instead of generate it and save $0.10 we would make that decision on a daily basis. Going forward, we will 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 is just a slight change in emphasis and how to balance the costs and economics, if you will, on the margin.

Greg, I think 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 were not talking about big changes to get back in line.

Okay, thanks guys.

Paul Patterson, Glenrock Associates.

Just to 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 benefit sort of going forward for some time, is that correct? Is that how we should think about it?

Yes, this is Bill Byrd, one thing I forgot to mention in responding to Hugh, another aspect of that decreased congestion is the first quarter of '11, a lot of our plants were still in MISO. Now they are 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 finance -- financial sales and purchases, that was a negative $0.05, could you elaborate a little bit on that?

Well, I'll let Bill comment, too, but you have that 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 should we think about that going forward?

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

Okay, I got you. That make sense. And then there was a FERC 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 is your thought about that and perhaps the implications for how it might be related to what we see in Ohio with the FERC case that AEP has there which you guys are also I think involved in. Any thoughts you'd like to share with us on that?

Paul, this is Leila, I haven't had an opportunity yet to read the order, but my sense about it is that it is a good signal in that they indicated to AEP and that their proposed pricing might be high. There are a lot of good signals in that case, so, obviously we will be looking to that going forward because I think you are 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 on the positive side, a very positive side.

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

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

Okay, great. And then finally, the distribution deliveries, do those figures include the leap year? Sorry if I missed that.

Yes.

Okay, thank you very much.

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

Kit Konolige, Soleil - Konolige Research.

Could you just review a little bit Mark, you talked about the total of five negative deltas in the commodity margin and four positive, 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 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 because of economic reasons, but fuel would be down. Wholesale, as we close our position in '12 and we are 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.

Okay, sounds good. Thanks.

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. Goodbye, now.

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