第一能源 (FE) 2012 Q2 法說會逐字稿

Greetings and welcome to the FirstEnergy Corp. second 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, Irene Prezelj, Vice President Investor Relations for FirstEnergy Corp. Thank you, Ms. Prezelj. You may begin.

Thank you, Latanya, 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, Donny Schneider, President of FirstEnergy Solutions, Jim Pearson, Senior Vice President and Treasurer, and Harvey Wagner, Vice President, Controller and Chief Accounting Officer. I'll now turn the call over to Tony.

Thanks, Irene. And good afternoon everyone. Thank you for joining us. Today I will provide an update on our plant and retail operations, regulatory matters and the impact of recent storms. I'll finish with a discussion of our non-GAAP earnings guidance and then Mark will talk about our earnings drivers and provide the detail on our second quarter results.

Let's get started with an update on our generating units. As mentioned on previous occasions, we've been rigorously evaluating the environmental controls that will be needed to meet the new environmental regulations, including the Mercury and Air Toxic Standards rule, or MATS, that is scheduled to go into effect in 2015. As a result of this analysis, we have significantly reduced our projected capital investment related to MATS compliance. We now estimate an investment of about $975 million across our fossil fleet. This is down from the $1.3 billion to $1.7 billion estimate we provided in February, and well below our initial projections of $2 billion to $3 billion. While we still have work to do to confirm and refine our current estimate, we are clearly moving in the right direction.

At the same time, we are moving forward with our previously announced plan to deactivate units at seven of our older coal-fired plants by September 1 of this year. Again, as a result of the MATS and other environmental rules. The affected units are Eastlake 4 and 5, Bayshore 2, 3 and 4, and the Armstrong, R. Paul Smith, Albright, Willow Island and Rivesville plants. We expect to continue operating Eastlake 1 through 3, Lakeshore and Ashtabula until early 2015 coinciding with the conclusion of reliability must run or RMR arrangements with the PJM Interconnection. We filed with FERC regarding RMR compensation for these units in July.

As you recall, we also proposed to construct four gas-fired simple cycle peaking units totaling 832 megawatts at the Eastlake plant. This proposal was contingent on the capacity clearing the PJM capacity auction which was held in May. However, these units did not clear. And as a result we will not proceed with their construction at this time.

As we make changes in our generating fleet, we are moving forward with a number of transmission projects that have been approved by PJM and will be implemented over the next several years in practically all of our service territories, Ohio, Pennsylvania, West Virginia, New Jersey and Maryland. A number of these projects are specifically designed to help address potential issues related to plant deactivations in the ATSI zone in Northern Ohio. One of those projects includes converting the Eastlake and Lakeshore units to synchronous condensers. We are currently projecting a capital spend of $700 million to $900 million through 2016 for these transmission related projects across the five state region. And we expect these transmission investments to be an important part of our growth going forward.

Now let's move now to a review of current regulatory activity. In New Jersey the Board of Public Utilities agreed with the rate council's request for a base rate case for our JCP&L utility. We continue to believe that there's no basis for the rate council's claims. In fact, JCP&L's rates have decreased by approximately 10% since 2008 and are the lowest electric rates among the four New Jersey electric distribution companies regulated by the BPU. We are preparing for our case and plan to file by November 1 as requested by the Commission.

Looking at our Ohio operations, last month the Public Utilities Commission approved our utility's proposed electric security plan, which is essentially a two year extension of our current ESP. The new ESP will be effective from June 2014 through May of 2016, and allows Ohio Edison, Cleveland Electric Illuminating Company, and Toledo Edison to conduct power auctions to secure generation supply for a longer period of time for customers who do not shop. This should help shield customers from potential price volatility by blending energy and capacity prices over the term of the plan.

Also in Ohio, on July 2 the PUCO issued an order in the AEP Ohio capacity case that will require AEP to charge competitive suppliers the RPM market price for capacity. This eliminates the pricing capacity proposed by AEP that would have limited customer choice and increased prices. We are cautiously optimistic that these actions will restore meaningful savings for all AEP Ohio customers who elect to receive service from a competitive supplier. And will enhance the market available for FES. But that decision will not be clear, or entirely clear, until the PUCO rules on the AEP's modified electric security plan which is expected later this week.

Market based capacity pricing will give businesses and customers access to electric generation prices that are at historic lows. FirstEnergy Solutions strongly advocated for customers' rights to shop and we believe that these changes, if implemented in the right way, will result in lower electric bills for customers and improved business climate in Ohio. FirstEnergy Solutions continues to prove that competitive markets work. For example, FES increased its customer base by nearly 17% since the second quarter of 2011, producing a 16% increase in retail sales. And while Mark will talk more about FES including an update on our hedge position for the remainder of 2012 and 2013, the continued success of our retail strategy is clear. It is better positioning our Company. Even so, we are facing very depressed prices. And at the same time, we are addressing increased environmental costs and government mandates and policies that impact both the supply and demand of electricity. We will work through these issues and I remain committed to further developing our retail operations and positioning the Company to take advantage of improving economic conditions over time.

Finally, let me spend a few minutes on the storms that cut through our utility service territories in late June and early July. During the last weekend in June, a straight line windstorm called a derecho, something I'd never heard about, tore across central Ohio, southwestern Pennsylvania, Maryland and West Virginia service territories causing outages for 566,000 of our customers. This windstorm, with winds of up to 90 miles per hour, caused the most significant damage our Company has ever experienced on our transmission grid. West Virginia was the hardest hit area with more than two-thirds of the 380,000 customers in our Mon Power service territory affected. Restoring service proved very labor intensive. For example, in one remote location crews had to replace 19 damaged poles to restore power to only a handful of customers.

While we were cleaning up from the derecho, another wave of thunderstorms brought on by the extreme heat caused major outages in our Toledo Edison and Jersey Central service territories. These outages were resolved in a matter of days. Total restoration costs are estimated to be in excess of $130 million, substantially all of those costs will be incurred in the third quarter. Approximately 70% of the total costs are capital. Most of the remainder is expected to be deferred for future recovery. We have deferral mechanisms in place in Ohio, Pennsylvania and New Jersey, and we expect to file for approval to defer the costs in West Virginia later this quarter.

As we announced this morning, we are reaffirming our 2012 non-GAAP earnings guidance of $3.30 to $3.60 per share. While we remain confident in our long-term strategies, we will continue to assess our operations, particularly at our fossil fleet, in light of the continued sluggish economy and its effect on power prices. Now I'll turn over to Mark for an in-depth look at the second quarter. Mark?

Thanks, Tony. And good afternoon everyone. As Tony mentioned, I'll start with a review of second quarter results. Then I'll provide an update on the continued success of our retail strategy, and finally, I'll conclude with several comments on next year's forecast. Before I move on to the details of our second quarter results, I'll take this opportunity to remind you of several housekeeping items.

First, this is the first quarter we're presenting our total Company results in a combined year-over-year format, fully reflecting our merger with Allegheny Energy. Second, as we did last quarter, we are normalizing the revenues, expenses, and output related to the deactivation of our older coal-fired units. And finally, with the integration of Allegheny into our automated financial reporting systems in the second quarter, we've modified our regulated reporting segments to isolate all federally regulated transmission operations and state regulated distribution operations as separate segments.

Looking now at second quarter results, excluding special items, non-GAAP earnings were $0.60 per share compared to $0.70 per share in the second quarter of 2011. On a GAAP basis, this quarter's earnings were $0.45 per share, compared to $0.48 per share in the same period last year. As we move to the detailed review of second quarter 2012 drivers, it may be helpful for you to refer to the Consolidated Report to the Financial Community that was posted on our website this morning. Special items for the second quarter are detailed on page 4 of the report. These items have the net impact of decreasing GAAP earnings by $0.15 per share. By comparison, in the second quarter of 2011 special items reduced GAAP earnings by $0.22 per share.

Looking at the special items for the second quarter of 2012. A gain of $0.01 per share related to the impact of non-core asset sales, was offset by the following six items-- a charge of $0.07 per share related to plant closing costs which includes revenues, expenses and activities to prepare our older coal-fired units for deactivation as a result of environmental regulations; a $0.03 per share decrease in earnings related to merger accounting for commodity contracts; a $0.02 per share decrease related to tax legislative changes; an additional $0.02 per share decrease for mark-to-market adjustments; a $0.01 per share decrease for regulatory charges; and finally, a $0.01 per share decrease for the impairment of nuclear decommissioning trust securities.

Moving now to distribution deliveries. While the earnings impact of distribution sales was flat compared to the second quarter of 2011, total deliveries increased slightly. However, distribution deliveries have not recovered to the levels we saw in 2007 before the impact of the recession. Industrial deliveries were up 3% and commercial deliveries also increased slightly. In Ohio, we continue to see improving industrial activity, particularly in the steel and automotive industry. In our other states, sales are essentially flat. These increases and any earnings impact were offset by a 1% decrease in residential deliveries. We attribute this in part to customer conservation efforts in the face of the continuing tough economy, where underemployment and unemployment remain a significant factor. This trend seems to be consistent with what other utilities in our region are also reporting.

The impact of weather was slightly positive in the second quarter. The reason for the negligible impact is the temperatures were comparable to those we experienced in the second quarter of 2011. A relatively mild April and May, followed by a very warm June. Perhaps the best way to express this is by looking at second quarter 2012 cooling and heating degree days. Heating degree days were 19% below normal and just 1% below last year. While cooling degree days were 33% above normal but only 5% above 2011. This trend continued in July, while cooling degree days across our utility service territory were up 39% above normal, they were 3.5% below July of 2011.

Let's turn now to the items that are highlighted in the earnings variance box on page 1 of the Consolidated Report. There were three positive drivers. The first is lower operating costs. While we did have more days of nuclear refueling outages, they were offset by decreased cost in our ongoing fossil operation, as a result of fewer plant outages in the second quarter of 2012, compared to the same period last year. And the benefit of merger synergies and reduced storm costs in our energy delivery business, compared to last year's quarter. Another earnings benefit was lower general taxes, primarily due to lower gross receipts. And finally, we had lower interest expense as a result of recent financing activity.

Moving now to items that reduced second quarter results. First, depreciation costs increase. Second, we saw a reduction in other income, which includes lower investment income from the nuclear decommissioning trust, and the absence of revenue in the second quarter of 2012 from the sale of pole attachment lease rights in June of 2011. I'll conclude our earnings discussion with a review of commodity margin which is detailed on pages 2 and 3 of the Consolidated Report. In that report you'll also find additional information on megawatt hour volumes.

To start, actual generation output from our ongoing competitive fleet increased by 1.2 million-megawatt hours compared to the second quarter of 2011. Both nuclear and fossil plant utilization increased, resulting from fewer refueling outage days across our entire fleet in this quarter compared to the same period last year. Fuel expense was down for the quarter, while purchase power was up. Essentially offsetting each other for the quarter. While commodity margin had a net negative impact of $0.09 per share, this reflects the interplay of various positive and negative components, and overall we remain very pleased with the performance of our competitive business, FirstEnergy Solutions. You will note that contract sales increased 6% over the second quarter of 2011. Achievements in the quarter included further expansion into the competitive markets in Illinois, Michigan, New Jersey, and Maryland, as well as growth in both the large and medium commercial and industrial account segments.

Looking more closely at the industrial sales channel, we achieved a 16% increase in direct sales, a 3.5 fold increase in mass market sales, and structured sales that increased slightly as new load acquired outside our traditional utility footprint offset the expiration of some municipal and co-op contracts. I think I said industrial sales channels, but I meant to say individual previously. I apologize. While government aggregation megawatt hour sales decreased slightly, we began delivering power to 25 additional communities in Central and Southern Ohio during the second quarter.

One important point to make is that during the second half of the year, we will begin to deliver power under newly signed aggregation contracts with another 48 communities in Ohio and 6 new communities in Illinois. And polar sales continue to decrease, consistent with the realignment of our sales portfolio as part of our overall retail strategy. I'll mention here that FirstEnergy Solutions' hedge position for the balance of 2012 is 95%. While we are currently at 70% for 2013. Commodity margin for the second quarter of 2012 also benefited from lower congestion, network, transmission line loss expense.

On the other side of the equation, negative drivers of commodity margin were lower capacity revenues, primarily as a result of the lower capacity price in the ATSI zone that became effective in June 2012. The RTO price in June 2012 was $16 per megawatt day compared to $110 per megawatt day in June 2011. Reduced renewable energy credit or REC sales were $0.02 per share. Capacity expense increased as a result of FES serving more retail load.

Although there are myriad of factors affecting the net reduction in commodity margin, FES continues to benefit from its strategy of moving megawatt hours sales between channels. A retail volume increase of 16% helped to partially offset lower prices of approximately $4 per megawatt hour. And the $4 per megawatt hour decrease in overall retail rates, when adjusted for transmission cost changes for Ohio customers, and changes in capacity prices, is actually a $1 decrease. When you compare this to the dramatic decline of $10 in the wholesale market prices year-over-year, it points to the solid success of our retail program. While we were challenged by market conditions during the quarter, we strongly believe in our strategy and our business model and we will continue to take actions we deem necessary to ensure we are well positioned for the eventual economic recovery.

As Tony mentioned, we are reaffirming our 2012 non-GAAP earnings guidance of $3.30 to $3.60 per share. Looking to next year, we remain confident that the regulated side of the house, which includes our utility and transmission operations, will continue to provide a strong foundation and fully support the dividend. We see no change in their strategic role, nor in their ability to deliver. On the competitive side of our business, we have seen a significant number of changes. Some negative, some positive, and some yet unknown, that were not anticipated in our earlier forecast. Some of these changes relate to the regulatory side that will have an impact on the competitive side.

Just to name three examples that were not included in our prior forecast -- the new ESP 3 in Ohio; the October and January Ohio auctions; and the AEP ESP. And of course, the economy, which remains more depressed than we anticipated, as well as continued regulatory and political uncertainty will impact our estimates. A simple example is Casper. We expected to be in a position to sell Casper allowances given our fleet's compliance position, yet we still don't have an answer from the courts as to when or whether Casper will become effective. Once we have better clarity around the issues that require updating, as well as incorporating changes from our normal fall budgeting process, we will update next year's earnings forecast. Thank you very much for listening, and now I would like to open up to calls and your questions. Thanks.

(Operator Instructions).

Dan Eggers, Credit Suisse.

Good afternoon, guys. Just on the 2013 number, Mark, do I take this as you guys are withdrawing the '13 guidance number, or this is the number you're keeping, but you have certainly a number of issues at play that could affect it that we'll have to kind of wait and see how they play out for the rest of the year?

That's a good question, Dan. I think the answer to next year's forecast is both simple and straightforward. There have been a number of substantial changes that will affect next year's forecast. As I said, some are going to be positive, some are negative, and some we just don't know yet. What I do know is that I'm working with a pretty long list of changes. I mentioned the Ohio -- proving the Ohio ESP, expanding our October, January auctions, storm costs, the New Jersey case, coal transportation, power prices, transmission, whether we can accelerate, of course the big gorilla in the room, being the general economy, but let me just address two to give a little bit better flavor.

Our earlier forecast assumed a one year auction in October and January. While we believe the changes Tony mentioned at three years will help the consumer, it will also help FES. Another example was the AEP ESP. As Tony again said, we think that's very positive for the consumer, depending on how the Commission rules, it could be very positive for FES.

And as you just said, the point we're making is that we need to update a long list of items, which we plan to do along with our normal fall budgeting process. I apologize if that's a long answer, but it's a long list of changes that we have to get updated and that's what we're trying to do.

Okay. I think I got it. Thank you. And then Tony, I guess just can you share some thoughts out of the RPM auction results and where the pricing went, with the big demand response contingent in ATSI, how important do you think it is to get more of a physical resource in that market in the future, and your comfort around reliability in the region as we look forward.

Sure, Dan. I think demand response, when it comes in across a broad region and is not clearly identified in a particular area, has some benefit, but it's not the real type of benefit that you're looking for in what otherwise are fairly constrained areas. My sense is we're going to have to get a better handle on that to determine whether or not it is usable or is just an interesting thing to have, but it will not improve reliability in and around the area. My own sense is that many of the transmission projects, including the conversion of the generating units in and around Cleveland to synchronous condensers, will put us in a position to deliver reliable electric service in that area.

That's going to take some time to put all that in place. And that's why we have the RMR arrangements being contemplated. But we intend to work as aggressively as we can to meet the schedule and to be able to stay within the guide post that we kind of laid out for ourselves, and that is basically to not be in a position to be running any of our power plants beyond March of 2015 that we've otherwise scheduled to shut down.

Okay. I guess one last one. As you look at kind of the mix and the retail business or kind of the gain in customer count relative to where your projections were at the Analyst Day, it looks like they might be a little behind on some of the share gains, and LCI, MCI, maybe relative to plan. Where do you guys think you are in capturing the new customers over the course of the schedule and was there always kind of an assumption you'd have an acceleration the second half, more of the government ag activities?

I think we knew that once our retail group went, the government aggregation, it was just going to be a question of how fast you can get them transitioned over, which as you said was mostly in the second half. I think they've had great success in the large commercial, medium sized commercial. I think we're a little bit behind in the mass market but I know they've got some good plans to catch back up there. So Dan, I get a weekly report in terms of what we win and what we lose, and we're up for the year across all the different segments, particularly in Southern Ohio.

Okay. Thank you guys.

Julien Dumoulin-Smith, UBS.

Hey, good afternoon, guys. So first, kind of following up on Dan's first question there, if you could provide a sense of priorities, or rather impact, if you will. You listed out those few items. Which of those are most impactful? It seems as if a lot of those are actually positive items to 2013 EPS, as you think about the update. So if you were to kind of ballpark it, is this actually a revision downwards or upwards? I apologize if that's an obvious question.

I think it's an obvious question, but we don't have an obvious answer. We just have to get through a long list. I think as I said earlier, the retail group is 70% closed right now for '13, so power prices are going to impact them. I don't know what's going to happen with the economy, the election, taxes, a bunch of things like that. Power prices are not a positive. Depends on whether the Commission rules favorably this week. That could be a positive.

One big positive potentially is we've reduced the amount of spend on MATS from $1 billion, down $1 billion to $2 billion. We've got transmission spend. How much transmission spend can we accelerate into '12 that will affect '13. I don't know if I would characterize any one weighing more than the other. I think we've got to get our book closed for '13. We've got to see what you power prices are doing, how much more channel switching Donny's group in retail can do. So as I said, there are some really strong positives.

Power prices are not going to necessarily be a positive and we've got to wait for some regulatory outcome. And of course, the big potential positive would be the auction, since they're now into three years. So, good question. I just have a long list of things that we have to get updated, plus as I said before, this is really the time of the year we're doing our normal budgeting process. So, we've got to get just the normal budgeting updates incorporated.

Right. Thank you. Maybe a follow-up, again kind of to Dan's original set of questions here on ATSI. As we look forward and as we've seen your transmission spend announced in the quarter, how are you guys thinking about, not to jump the gun here, but the '16, '17 auction, and the ATSI zone and any kind of commentary? I imagine, or at least I understand, that the transmission is set to go into service prior to the next auction date?

Well, Julien, this is Tony, some of it will. Some of it will be, perhaps, beyond that. The real issue I see in terms of being able to get many of those transmission facilities in place will not necessarily be driven by the construction schedule, but will be more affected by our ability to acquire rights of way, ability to get outside crews in to support it, and doing that and getting the permits necessary to complete that amount of work in the time frame that we've laid out in front of us.

So we have some work to do. There's a lot involved in the process. We're in the early stages now of preparing environmental impact statements and all of the other parts, pieces and parts that will require regulatory approval, primarily from sighting organizations. And as we move in that time frame, we'll be better able to predict when we will have the particular parts of those projects in place, because this is not just one project.

There are a number of things that are going to be done. Substations are going to be enhanced. Additional ones are going to be built. New lines are going to be brought in to serve those. The synchronous condensers will be put in place. We'll have to see how all of those impact the schedule that we have now, as well as what the loads do in the Cleveland area between now and 2016 and 2017.

Great. Thank you for the clarity.

Gregg Orrill, Barclays.

Thanks a lot. I was wondering if you could talk a little bit more about the Ohio ESP approval and the provision where they change the polar auctions to three years versus one? And just whether you feel that is more attractive from a FirstEnergy Solutions standpoint, and if you'd be more interested in participating in those auctions?

Let me address that one first. The primary purpose of this is providing a more gradual glide path for our customers, so that we could take out the volatility that we otherwise would have anticipated happening between today's pricing, which are based on very low capacity costs in the main, and what we are seeing in the '14, '15, '16 kind of time frame. We thought smoothing, which is kind of consistent with what our utilities have tried to do for as long as I've been actively involved in trying to work through what otherwise are potential spikes in pricing, try to blend that out.

From an FES strategy standpoint, whatever that auction is, it is. Our strategy continues to be focused on direct sales to individual customers, pulling away from polar obligations and polar sales, because we believe that's the greatest opportunity for this Company to be successful over the long term. We will likely participate in auctions, and we do in multiple regions, and we'll likely also participate in these auctions. But again, much of that will depend on where is the status of our retail book of direct sales and how much we have available, or do we want to place in that kind of call auction associated with a polar transaction.

Thanks, Tony.

Ashar Khan, Visium.

Good afternoon. Can I just ask when should we hear back on the new guidance? Is it end of the year, next year or could you give us a time frame?

That's a good question. No, not really. I think we've got to get through the whole process. It's a long list. Got to get through our normal budget process. I think our Investor Relations folks told us that there's an analyst meeting early in '13, so can't be any later than that, and if we get it done sooner we'll get it done sooner. So just a lot of work we've got to get done between now and then.

Okay. And then could you just again -- I'm sorry to -- apologize for getting it repeated. Could you just go over the factors again, the changing factors, could you just repeat them, if you don't mind?

Well, these are just some of the ones off the top of my head that I put down. It's the approval of the Ohio ESP.

Okay.

The auction that's been extended from one year to three years in Ohio for both October and January.

Okay. So that's a positive, right?

Right. The storm costs and the request to defer those that Tony mentioned in his text in West Virginia. We've got the New Jersey rate case. All the plant deactivations is going to affect our coal and transportation costs, and those are all being negotiated by FES right now. Our power prices are going to affect the open position where FES is 70% closed. I think the last time we spoke was somewhere around 50%, 55%, something in that range, so they're right on their glide path and right where they need to be.

I spoke about transmission reliability investments, the fact that we don't have some of these big capital costs related to MATS, related to the peakers, the $500 million there. How much our Transmission Group can get accelerated on the transmission side both into '12, into '13. Then the big gorilla in the room is the economy, where the economy's going, what's going to happen with the tax cliff, are they going to extend it, not extend it. So those are just some of the things that I wrote down really quickly off the top of my head. I can assure you, the list is three or four times that length.

Then, can I just, Mark, for our purposes, I don't have the presentation in front of me. What had you assumed for the economy for '13 in terms of growth?

I think in the distribution side, Jim, do you know, like 1.5%.

It was about 1% to 1.5%.

1% to 1.5% on the distribution side but it doesn't necessarily affect what the retail group is doing. They're targeting a set number of megawatt hours at the highest possible margin. So, if the economy's going backwards or forwards, doesn't really matter to us because Donny's -- at the retail side, they're targeting a set number of megawatt hours, which I think in '13 is 112 as opposed to 104 in 2012. So, they target megawatt hours, the distribution models and forecasts around the economy, which as I said, was somewhere between 1%, 1.5%.

But the economy impacts the amount available to go after in the market. So they are integrally tied as to whether or not this economy's going to get back in growing or whether or not we're going to stay stagnant in 2007 levels. When in fact at the end of the day, we had assumed that this economy was going to get a little bit back on track. It clearly has not yet and it is impacting the estimates.

Okay.

That's correct.

Thank you so much.

Stephen Byrd, Morgan Stanley.

Good afternoon. I wonder if you could talk a bit about the trends you're seeing in competition levels on the retail side. Mark, you mentioned margins there were down just fairly modest $1 a megawatt hour, whereas wholesale prices fell significantly more. Is this in line with your expectations? Are you seeing certain emerging trends with respect to the degree of competition?

Actually, I have Donny Schneider here, he is the President of the Retail Group. I'm just going to let Donny speak for his group.

Great.

Stephen, clearly the competition's out there. I think we're doing a great job. One of the things that we monitor very closely is what we call our attrition rates, and so these are customers that we have -- that we've traditionally held and whether or not we're able to retain those. And in our residential space when you look across our EDCs, we're 3% to 4% year-to-date attrition in our FE Ohio. That's more like 1%.

So, we're doing very well at being able to retain those customers. In other EDCs, where we call our close to home EDC's, where we go after customers, we're doing quite well across the board, being able to secure market share that we had anticipated.

Okay. Great. Thank you. And just shifting gears over to PJM, there have been a number of conversations about the minimum offer price rule and there's continued discussions about potential modifications of that. I was just curious from your perspective how that process has been unfolding, anything just out of the ordinary as you've been going through that, is it proceeding as you had hoped? How do you see that shaping up in terms of potential changes to the [moper].

Steven, this is Donny again. My folks are involved with that. As you know, PJM has a very elongated process when it comes to these things, so they're actively involved. I think it's a little soon to tell, to speculate on how you that might come out. So, we're just going to have to watch it. Obviously, it's something we're very interested in and we're paying close attention to that. But a little soon in the process to speculate.

Understood. Thanks, Donny.

Paul Patterson, Glenrock Associates.

Good morning. The AEP ESP sounds like you guys thought that that might turn out positively for you. Is that -- just sort of wondering what your thinking is in terms of what's going to be coming out there and whether or not this capacity ruling was -- how that figures in your thinking. And also, I guess, there are remarks by Duke that they might be looking at this, the fact that they're an FRR entity, and therefore, they might be able to get a capacity cost, at least looking into that sort of issue. Any thoughts there you want to just elaborate on?

Hi, this is Leila Vespoli. I think the capacity order that came out was very favorable. They did defer one issue to AEP's ESP and that was how they were going to handle l the deferral between the 188 and RPM. So, we're still looking to see, and I guess that would be tomorrow, when the Commission issues its order on the AEP case, and hopefully we'll get that resolved positively, and kind of have a complete picture with respect to that. With respect to --

Duke.

Duke, yes. I apologize, I forgot the second part of the question. With respect to Duke, yes, they have raised issues with respect to that. If you think about how AEP presented their case, they presented a cost based case and that's what the Commission was looking at.

So, in setting AEP's state based FRR mechanism, they looked at cost. If Duke is thinking of trying to implement something like that, from our standpoint they have an ESP that's in place that incorporated RPM pricing. And so, with respect to that, I think that they would have a huge hurdle to clear with respect to that.

Okay. And then with respect to peak demand, just in the third quarter here we've seen a lot of hot weather in the Midwest, and we haven't -- and in the East Coast, and we haven't really seen much in terms of high peaks at PJM and I was just wondering if you could maybe sort of give us an indication as to what you're seeing on the demand response side? Are you seeing demand response in the energy market, which has been sort of a tariff that PJM has put in here, or any sort of comments you'd like to make on that?

This is Donny. I think Mark touched on the residential space being down a little bit. What we are seeing is that for a given number of residential customers, so if you assume an EDC where the residential customer count has not changed, the actual consumption is down a little bit, with what we would normally expect to see with these hot conditions. So it looks like the economy, the energy efficiency, et cetera, is starting to have a bit of a dampening effect on residential consumption.

Okay. And then just finally, Ashar asked about economic forecasts. As opposed to sort of sales growth, I was just wondering sort of a GDP forecast. What had you guys been assuming for 2013 just in terms of the economic rebound?

2.5%, but that really could get changed depending on what happens with the tax cliff, Paul. I don't know what that number is, but I've seen numbers like 3% to 5% if they don't extend it. You subtract that from anything and it's not pretty so. But we assumed about 2.5%.

Okay. Thanks a lot.

Paul Ridzon, KeyBanc.

With regards to your CapEx around environmental, it's come down pretty considerably. Where have you found that opportunity?

I think pretty much across the board, I think Tony challenged the folks to come up with creative solutions and they've done that. I think coal firing with gas is going to help. If the power prices stay low, there's some things we can put off, moving some of the outages around. It's pretty much across the board. We're pretty pleased with where they are, but we keep pushing them to lower that number too, so, Tony, you want to --

I think it's just a comprehensive look at each and every unit and each and every plant, and looking more holistically at the plant and its capabilities, and what you can do with existing equipment to enhance it and improve it. For example, the improved performance of precipitators, or tightening up so you don't have as many air leaks. A whole series of things, unit by unit specific, to eliminate kind of the large, bigger ticket items that would otherwise be kind of hung on the back end of the plant, because you're not making the rest of the facility as efficient and as effective as it can be.

One of the items you mentioned, Mark, around the uncertainty of '13 is power prices, but you took your open position from 45% to 30% and as you closed that 15%, how is that pricing relative to what you view when you did have guidance out there?

It's lower. I don't know, Donny, you want to speak to --

I think in the first quarter of this year, first and second quarter, we saw a drop-off of about $10 a megawatt hour on the wholesale prices.

Okay. Thank you very much.

Hugh Wynne, Sanford Bernstein.

You all have talked about the offsetting impacts of rising contract sale volumes against the decline in capacity prices and energy prices. There's also been a material mix shift in the composition of your contract sales from polar to large C&I. I was wondering if you could comment year-over-year whether the mix shift has been positive or negative to your commodity margin, or broadly neutral.

Hi, Hugh, this is Donny. You know, I would say it's been very positive. I'll just use FE Ohio as my example. If you think about when FE Ohio first opened up, and I'm using FE Ohio as an example, I could use any one of the EDCs as they progress from the beginning to where they are sometime later. FE Ohio opened up in the spring of 2009.

When it first opened up, there was very little shopping, and so as you went in there and procured tranches, if you were a participant in polar, you were receiving a nice margin and a nice volume. As time has went on, though, that volume has absolutely crept away from those polar providers. Today, in FE Ohio, you're probably somewhere in the neighborhood of about 80% of the customers have now shopped.

So if you had only participated in that polar procurement, not only looking now at 2012, not only would your rate have dropped off substantially, but more importantly, your volume would have been completely -- not completely, but 80% erased from where you were just three short years ago. So our move from polar to the LCI, MCI, gov ag, et cetera, has allowed us to secure that volume.

Hugh, this is Mark. I would add one additional caveat to what Donny just said. One of the things that we're working very diligently on and have a lot of algorithms on is suppose you can move a customer, megawatt hours between channels or inside a channel. You've got an LCI customer that's served by one EDC.

Can you move those megawatt hours over to another EDC in the same channel, but a higher margin or even within the EDC? And one of the big issues that comes up in the large industrial market is, can we take those megawatt hours and move them to any of the other channels, like mass market or something else. So they've spent a lot of time trying to move either within channels or out of channels to increase the margin.

Right. Okay. And if I could just ask a follow-up question regarding the radical reduction in your MATS CapEx. Is the co-firing with gas likely to be accompanied by a reduction in the variable cost of running the units that co-fire, or given forward prices for coal and gas, an increase in variable cost? And I guess if it's the latter, is it material?

A lot of that's going to -- Hugh, this is Tony. A lot of that's going to depend on the price of natural gas, obviously, and the relative price to an add in coal. We're looking at it more from an operational standpoint. There's not going to -- we'll have some flexibility, but you also have to include all the back end costs, where you're not going to dispose of as much material.

And you're not going to need as much material going in to your scrubber systems, because you're not having to deal with as much of the effluent. If they coal kind of a relative balance, my sense is it's going to be about neutral, with respect to the overall cost. Could be sometimes plus, could be sometimes a little negative.

Hats off to your engineers. That's pretty impressive savings. Thanks a lot.

Thanks. Operator, how about we take one more question.

Andy Levy, Avon Capital.

Hi, guys, how are you? Hey. Just want to try to clarify something. Obviously you guys know what you're doing as far as 2013, and you've articulated very clearly that there are numerous moving parts. At the same time, obviously by kind of talking the way that you guys have, it has caused some angst in your stock today. I just want to give you kind of one more chance to kind of come out and just try to make a little bit clearer whether we should be concerned that there could be a significant revision down to 2013 estimate.

It seems that a lot of the things are on the positive side. Obviously, the big gorilla in the room, as you mentioned, is the economy. But I just kind of want to give you one more chance to try to articulate that as your stock is down almost 4% right now.

Well, I can't articulate why our stock is up or down. There are a lot of factors other than just whatever our forecast is going to be. But at the end of the day, we're trying to say we have an awful lot of changes to make in our forecast, and we're just trying to be honest and upfront about it. Some of those changes are going to be positive as we close the book on the 20%, 15%, 20% that has to be closed, chances are it's going to be at lower prices.

Chances are we're going to accelerate some transmission. I couldn't tell you specifically today what our forecast is going to be. So I don't know how anybody else is going to be. It is what it is. We're just trying to be up front and honest that there are going to be a tremendous number of changes in our forecast from the last time we did it. It's a simple and straightforward statement.

Great. Thank you very much.

Thanks, Andy.

I would like to turn the call back over to Management for closing comments at this time.

Certainly, we'd like to thank everyone for joining us on the call today, and as always, we certainly appreciate your support and interest in FirstEnergy. Thanks a lot.

Thank you.

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