FirstEnergy Corp. (FE) Q1 2013 Earnings Report, Transcript and Summary

Meghan Beringer Anthony J. Alexander - Chief Executive Officer, President and Executive Director Leila L. Vespoli - Executive Vice President and General Counsel James F. Pearson - Chief Financial Officer and Senior Vice President Donald R. Schneider - Principal Executive Officer and President Irene M. Prezelj Steven R. Staub - Vice President and Treasurer

Dan Eggers - Crédit Suisse AG, Research Division Jonathan P. Arnold - Deutsche Bank AG, Research Division Julien Dumoulin-Smith - UBS Investment Bank, Research Division Stephen Byrd - Morgan Stanley, Research Division Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Paul Patterson - Glenrock Associates LLC Michael J. Lapides - Goldman Sachs Group Inc., Research Division Charles J. Fishman - Morningstar Inc., Research Division Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division Greg Gordon - ISI Group Inc., Research Division Raymond M. Leung - Goldman Sachs Group Inc., Research Division

Greetings, and welcome to the FirstEnergy Corp. First Quarter 2013 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 for FirstEnergy Corp. Thank you. Ms. Beringer, you may begin.

Thank you, Manny, and good afternoon. Welcome to FirstEnergy's first quarter earnings call. First, please be reminded that during this conference call, we will make various forward-looking statements within the meaning of the Safe Harbor 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 the 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 on today's call are Tony Alexander, President and Chief Executive Officer; Leila Vespoli, Executive Vice President and General Counsel; Jim Pearson, Senior Vice President and Chief Financial Officer; Donny Schneider, President of FirstEnergy Solutions; Jon Taylor, Vice President, Controller and Chief Accounting Officer; Steve Staub, Vice President and Treasurer; and Irene Prezelj, Vice President, Investor Relations. Before we begin, I'd like to mention for anyone who has not already visited, that we recently launched a new page on our Investor Relations website for fixed income investors. It includes data on frequently used information, including our long-term debt, credit ratings, liquidity and credit facilities, and financing structure. Look for the Fixed Income investors link on our Investor Relations homepage. You can also find a link to this information on our Investor Relations app for the iPhone and iPad. Now I will turn the call over to Tony Alexander.

Thanks, Meghan, and good afternoon, everyone. Thank you for joining us. Today, I'll provide a general overview of our first quarter results and accomplishments, and a review of the progress we've made on our financial plan. Leila will join us for a brief regulatory update, and then Jim will provide more details on first quarter results. Okay, let's get started. Today, we announced first quarter non-GAAP earnings of $0.76 per share. These results are solidly in line with our expectations, with a return to normal weather providing incremental benefits compared to the first quarter of 2012. As we described during our last earnings call, our focus in 2013 is on successfully executing our plans to control costs, continue to improve operational performance and explore growth opportunities in our regulated and competitive businesses. We expect this strategy to help us address the impact of market conditions and regulatory challenges, while positioning our company for long-term growth when the economy and power prices recover. Another very important objective for 2013 is implementing our financial plan, which was structured to improve the balance sheet, enhance liquidity and maintain investment-grade credit metrics. As Jim described in February, the plan focuses on reducing debt at our competitive companies, primarily FES and Allegheny Energy Supply, by about $1.5 billion. We have made great progress on this front in a very short period of time by successfully executing numerous parts of the plan. I'll take a minute to walk you through these developments. In early March, we issued $1.5 billion of senior unsecured notes at FirstEnergy Corp. in an offering that was positively received. We completed the transaction with a mix of 5- and 10-year notes at very attractive rates of 2.75% and 4.25%, respectively. We then funded tender offers at FE Solutions or FirstEnergy Solutions and Allegheny Supply -- and Allegheny Energy Supply, as we repurchased $665 million of outstanding senior notes. In April, we completed the early redemption of $400 million of FES senior notes that were due in 2015. We also reduced lease debt by about $100 million with the repurchase of certain remaining lessor interests in connection with the 1987 Bruce Mansfield sale-leaseback transaction, and expect $90 million of additional lease debt to amortize naturally through the remainder of the year. In addition, in April, we issued notice for $235 million of tax exempt bonds, which will be repurchased in early June. Combined, these actions will result in a reduction of long-term debt by about $1.5 billion at our competitive businesses. In addition, our Met-Ed subsidiary issued $300 million in senior unsecured notes due in 2023, and used the proceeds to refinance $150 million of maturing debt and reduce short-term borrowings. Our Ohio utilities filed a registration statement with the SEC to securitize certain deferred costs, and this process continues to move forward. And finally, we started discussions with our bank groups to extend the maturity of our existing $5.5 billion credit facilities for another year, through May of 2018. We're also looking to exercise the accordion option, which will increase the total size of the facilities to $6 billion. We expect to complete this process in a few days. By taking these actions to reduce -- or to refinance short-term borrowings with long-term debt at rates at that are at historic lows, we have made solid progress on our financial plan we laid out for this year. Further, we continue to move forward with our plan to sell up to 1,240 megawatts of unregulated noncore hydro generation assets. We have retained an independent advisor and commenced marketing activities with a goal of completing this process in the second half of the year. We plan to use the proceeds to complete our debt reduction plans. Our success with the actions we have already taken, particularly the bond deal with FirstEnergy Corp. means the Harrison transaction, while still important to both West Virginia and FirstEnergy Solutions, is no longer critical to the successful completion of our financial plan. Leila will talk more about Harrison in a few minutes. As we discussed previously, we still expect to issue equity later in the year to further strengthen our balance sheet. We will determine the exact level, up to $300 million, later in the year, as we get more clarity on our other initiatives. Moving now to an update of our businesses. With respect to the construction of simple cycle peakers in Eastlake, Ohio, American Municipal Power has notified us that they do not intend to proceed with the project. With this development, the Eastlake peakers will not be bid into this month's PJM RPM auction for the 2016-2017 period. Since we already have substantial transmission investments planned to support reliability in this part of the ATSI zone, approximately $700 million through 2016, we do not expect AMP's decision to not proceed with the project to have any significant impact on the auction. We will continue to work with PJM to address the need for any additional transmission projects, which would create additional investment opportunities, beyond the projects identified through 2016 or in future years, to further bolster and support system reliability in that area. Looking at our distribution deliveries. As you may recall, the first quarter of 2012 was abnormally warm. Our distribution sales benefit -- benefited from a return to weather that was slightly colder than normal this year. Jim will provide more details on this topic in a few minutes. At FirstEnergy Solutions, we continue to focus on expanding our retail business, strengthening our brand among customers in both new and existing targeted markets and implementing our multichannel sales strategy. We increased our retail customer base by about 800,000 customers or 42% since March of 2012. More importantly, while sales margins are compressing somewhat as a result of continued pricing pressure, our strategy of channel shifting, for example, moving kilowatt hours from POLR to higher-value retail channels such as mass market and government aggregation, continues to help offset the impact of lower market prices. FirstEnergy Solutions sales book, which targets 104 million megawatt hours in 2013, is essentially filled. While we have had considerable success in building our customer base, forward prices, as you know, have dropped about $10 per megawatt hour from early 2012 and have continued to lag in that same range. As we continue to see downward pressure on power prices, we are adjusting our forward hedging strategy, so that sales for future years fall into the lower range of the glide path we have established, allowing more opportunities to capture potential improvement in power prices. Finally, with respect to the Mercury and Air Toxics Standards Rule, or MATS, we were granted extensions for compliance through April 2016 in both Pennsylvania and West Virginia for our Hatfield, Bruce Mansfield, Fort Martin, Harrison and Pleasants stations. These extensions provide for an additional year, as I said through April 16, for compliance at these units. And as we continue to refine our capital expenditures related to MATS, we are lowering our estimated costs to approximately $925 million from the $975 million previously reported. We continue to believe that a focus on our core generation, distribution and transmission businesses provides greater flexibility, growth opportunities and financial stability than any single standalone business. And we continue to manage our businesses with a combination of long- and short-term strategies, which is helping us weather current market conditions. We believe that as the economy and power prices improve, we are well positioned to take advantage of growth opportunities, resulting from more robust conditions. Now I'll turn this over to Leila for a regulatory update.

Thanks, Tony. In February, I provided a review of the key regulatory and legislative issues that we will address in 2013. And today, I will update you on the status of several of those matters in Ohio, New Jersey and West Virginia. In Ohio, the state senate has introduced legislation reevaluating the aggressive energy efficiency standards that were passed in Senate Bill 221 in 2008. As you may know, Ohio investor-owned utilities, including FirstEnergy, must achieve annual compliance targets, ultimately resulting in a 22% reduction in electric consumption by 2025. In light of rising program costs, as well as the changing economic landscape since Senate Bill 221 was passed, the Senate Public Utilities Committee is evaluating whether changes should be made to the existing law. FirstEnergy is actively involved in this process and is advocating changes that we believe make more sense for our customers and help foster solid economic growth in Ohio, including the development of shale gas. Also in Ohio, we continue to participate in a proceeding at the PUCO regarding the alternative energy rider that recovers our costs associated with procurement of renewable energy credits required under Ohio's renewable energy portfolio standard. A decision is expected in the second or third quarter of 2013. With regard to our pending rate case in New Jersey, the Board of Public Utilities established a generic proceeding to review the prudence of certain storm costs. By July 1, 2013, JCP&L is expected to file a detailed report of its storm costs, for which it intends to seek recovery from ratepayers. On April 4, 2013, JCP&L filed a motion with the BPU, requesting that the commission reconsider its March 20 order, and rule that the company's cost in response to major storm events will be reviewed and considered in the pending base rate case and not be considered in the generic proceeding. In the alternative, JCP&L requested that the BPU issue an order clarifying the procedures and processes that the BPU will apply to coordinate the generic proceeding with the base rate case, to enable recovery of the costs for the major storm event. Such coordination would include holding the base rate case in abeyance pending conclusion of the generic proceeding. We expect the commission to rule on our motion in May. Hearings are currently scheduled in the base rate case from mid-September through mid-November. Turning now to West Virginia. On April 23, we received FERC authorization for the proposed Harrison/Pleasants transaction to transfer nearly 1,500 megawatts from our competitive operations to our Mon Power subsidiary. We await approval from FERC of our filing related to financing for the transaction. At the same time, we continue to work through the state regulatory process. On April 26, various parties filed their testimony. Rebuttal testimony is due by May 17 and hearings are scheduled from May 29 through May 31. We believe the proposed transaction is good for the state of West Virginia, as it is expected to help ensure reliable power for our West Virginia utility customers for many years to come. The proposed transaction is and remains very positive for the West Virginia economy and our customers of our utilities in West Virginia. Thank you for your time. Now I will hand the call over to Jim for a review of the first quarter results.

Thanks, Leila. Let's go ahead and get started with a review of the first quarter. You may want to turn to the consolidated report as I walk through our results. Looking at the first quarter of 2013, non-GAAP earnings were $0.76 per share, while GAAP results were $0.47 per share. In the first quarter of 2012, non-GAAP earnings were $0.82 per share, while GAAP earnings were $0.73 per share. As Tony mentioned, our non-GAAP earnings were solidly in line with our expectations for the first quarter, with some incremental benefit year-over-year due to colder weather. On Page 4 of the consolidated report, you can find a list of special items that make up the difference between the GAAP and the non-GAAP results. The largest of these special items is $0.18 per share in debt redemption cost related to the debt reduction efforts at FES and Allegheny Energy Supply. Other special items for the first quarter of 2013 include regulatory charges of $0.04 per share, a decrease of $0.03 per share related to merger accounting for the commodity contracts, plant deactivation cost of $0.01 per share, a decrease of $0.01 per share from impacts of the sale or impairment of noncore assets, a decrease of $0.01 per share related to mark-to-market adjustments and trust securities impairment of $0.01 per share. Let's turn now to distribution delivery, which increased earnings by $0.07 per share. Overall, deliveries increased 979,000 megawatt hours or about 3%, primarily due to weather that was significantly cooler than the same period last year and slightly cooler than normal. Residential deliveries increased by 6% quarter-over-quarter, again, primarily due to the impact of weather, while commercial and industrial deliveries increased slightly compared to the first quarter of 2012. To put the impact of weather in perspective, heating degree days were 30% higher than in 2012, but only 2% above normal. When we adjust deliveries for the impact of the extra day in 2012 due to leap year, first quarter 2013 sales in the industrial class were up 1.5% quarter-over-quarter. Sales increased in both the chemicals and refinery segments, but were down overall in steel and automotive. One of the bright spots we see is certain customers within the steel sector are starting to fill increased orders for pipe used in shale gas drilling, with expectations for increased usage continuing through the year. Adjusting for both leap year and the swing in weather, first quarter 2013 sales were down 2% in residential and 1% in commercial. Sales in these classes continue to remain weak. We also took a look at residential sales over the longer period to see if there were any identifiable trends. That analysis revealed that, since 2007, our residential customer count and usage has been relatively flat. Commercial and industrial sales are still down versus 2007 at 6% and 8%, respectively. Looking at other first quarter drivers, earnings also benefited by a total of $0.05 per share from the combination of lower operations and maintenance expense, a lower effective income tax rate and lower general taxes. These gains were offset by higher depreciation expense of $0.02 per share and lower regulated transmission earnings of $0.02 per share, consistent with our expectations due to a lower rate base at TrAIL, the Trans-Allegheny Interstate Line Company, and lower net system peak demand. Finally, I'd like to provide additional detail on commodity margin at our competitive business, which reduced earnings by $0.14 per share compared to the first quarter of 2012. While we continue to successfully execute our retail strategy, gains from this initiative were offset by lower revenues related to historically low PJM capacity prices, which reduced earnings by $0.19 per share. These prices will remain in the range of $16 to $28 per megawatt day through May 2014, as a result of the auctions held during the recession years of 2009 and 2010. As we have noted previously, subsequent auctions in 2011 and 2012 resulted in prices that are substantially higher, above $100 per megawatt day for the period of June 2014 through May 2016. This drop in capacity prices should have resulted in a drop of about $6 per megawatt hour in our overall competitive rate. However, our actual decrease was just $3 per megawatt hour, pointing to the benefits of our channel-shifting strategy, and our average retail rate of $54 per megawatt hour is consistent with the expectations we laid out with our 2013 earnings guidance. So we're right on target with where we said we would be. Excluding the impact of the lower capacity revenues, commodity margin for the quarter was up $0.05 per share year-over-year. Overall, contract sales revenue in our competitive operations increased 4% or $0.09 per share. Looking at each of our channels, the continued successful expansion into Illinois drove a 36% increase in governmental aggregation sales during the quarter. Mass market sales, driven by growth in Pennsylvania and Ohio, increased 46% with the introduction of several new marketing campaigns. Structured sales increased 92% due to increased municipal, cooperative and bilateral sales. Direct sales to large- and medium-sized commercial and industrial customers increased 7%, primarily due to higher sales in central and southern Ohio. And finally, POLR sales continued to decrease consistent with our retail strategy to realign our sales portfolio. The successful growth in our retail sales resulted in a 4% increase in total generation output, and capacity factors of 73% at our supercritical and 54% at our subcritical units compared to 65% and 24%, respectively, at those units last year. With this additional generation output came higher fuel consumption. Although the fuel rate is also in line with our expectations. Our retail sales growth also resulted in increased purchase power and transmission expenses and lower wholesale sales. Commodity margin was also impacted by lower sales of renewable energy credits and lower capacity expenses compared to the first quarter of 2012. Overall, we are pleased with the quarter's results and also with the progress we're making in the implementation of our financial plan for the year. We plan to continue to strengthen our balance sheet, while also looking for additional opportunities to reduce our costs. Most importantly, we are positioning the company to take advantage of opportunities created by expanded competitive markets and improved economic conditions. Now I'll open the call to your questions.

[Operator Instructions] Our first question is from Dan Eggers of Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Hey, just following up on Tony's comments and Leila's comments about Harrison. Can you just maybe help us understand how important it is you think, at this point in time, to move that asset over from a balance-sheet perspective relative to a customer-benefit perspective? And then given kind of the wide -- or the low bid made in the intervenor testimony, how important is it to take a lower price or accept a lower price to get this done relative to keeping it at FES if the pricing doesn't make sense?

Yes, well, I'll start off with that, Dan. Well, let me start off. I think the low price of the $565 million or whatever is, that's just a nonstarter. So I'll leave that at that. From a balance-sheet perspective, we think we're in pretty good shape by getting the FirstEnergy Corp. bond deal down, where we upsized it to $1.5 billion. And we also feel we're in a very good position with the hydro sales, so we feel real comfortable about that. And as you know, we plan to infuse equity from FirstEnergy down into Mon Power associated with this asset transfer. If the asset transfer doesn't go forward, we would likely infuse that equity that we have planned for Mon Power down into FES. So I think we'd end up at a good position for the balance sheet there at FES.

Yes, Dan, this is Tony. As I'm looking at this, I think this is far more important to West Virginia and Mon Power, in terms of providing them with a stable and long-term resource that they can rely on, than it is, at this point, from a balance sheet standpoint at FES or FirstEnergy. Dan Eggers - Crédit Suisse AG, Research Division: But if it didn't transfer, you'd feel comfortable keeping that extra capacity at FES?

Absolutely. It's a great asset. So that's not a consideration. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And then I guess on RPM outlook, I know you guys have kind of signaled, Donny, I think, of kind of flattish in prior comments. With the clarity on the DR rules and the AMP project not going through, is there any change in your thought process?

Give me that again, Dan, because I was talking the same time you were. Dan Eggers - Crédit Suisse AG, Research Division: Oh, I'm sorry. I was just going to ask Donny, since last -- he said prior that RPM expectations were relatively flat or that's kind of where you thought it was going to come. Just curious if you had any updated thoughts, now that we have the DR rule clarification out of FERC and the decision on the AMP project not going forward.

I really haven't changed my opinion here, Dan. We'll see here in a couple of weeks, obviously, where the auction comes out. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And then just one last question on industrial load. I mean, you said that you're seeing signs that steel was looking better. The first quarter had pretty good demand growth. Are you reevaluating what you guys think normalized load growth is going to be at this point, Tony, or is this just a little early?

Dan, I think it's a little early. It's still spotty. We're seeing real strength right now in steel and in chemicals, and there is absolutely a lot of upside if we can get this manufacturing and further development of the shale gas plays really into an economic development engine for this area. But I think it still too early to say, because some of the other things are not as strong. Automotive's down a little bit, but the fact of the matter is there's been a number of announced projects, that as they go forward, should provide some upside on the industrial sales side. So right now, I'm cautiously optimistic that we're going to start seeing the economy improve and begin to see some of the expected real growth that can occur in this area as a real energy center for America.

The next question is from Jonathan Arnold of Deutsche Bank.

Just a quick one. So the use of proceeds, if you are successful in Harrison and hydro, because you've already hit your delevering targets at FES, I think, with this new deal in April, should we just assume more of the same or something different?

We would use those proceeds, Jonathan, to pay down some of the short-term borrowings that we have there right now associated with paying down the debt.

At FES?

That's correct.

The next question is from Julien Dumoulin-Smith of UBS.

So just following up on Dan's question a little bit here. With regards to ATSI specifically, what do you expect there in '16, '17 just to be explicit?

I expect to get the results about May 24, I think is the date.

Okay. Fair enough. And again, kind of following up on a little granular detail here, the energy efficiency component of the Ohio program recently approved. As of today, what is the total megawatts that you're seeing come out of that program that you'd expect to bid?

Roughly, right now we're expecting a delta from what we maybe would have put in versus what the commission order would require us to do, I assume that's what you're getting at, of roughly 160 megawatts.

Great. And again, broadly speaking, if you could summarize, not to put it too cutely here. But a lot of other peers of yours have framed upside to power forwards in a dollar-per-megawatt-hour fashion. I'd be curious if you guys would be willing to opine using a comparable metric out in '15 or '16 or what have you?

I think it's always interesting. I've heard what they've said in the main and I don't really have any reason to say otherwise. I think there's going to be a lot more generation removed from both the energy and capacity markets as we go forward. That will bring the demand -- the supply side more in balance over time. I'm not sure that, that's fully reflected yet in the forward prices that we're seeing out there. And on the demand side, we're certainly hopeful that, by the time we move into these time frames, there is more robust economic activity than we've seen here recently. So a combination of demand and supply, as it naturally would affect prices, we would expect to see some upside.

Great. And then maybe just last one here. How does that fit into your hedging strategy here? I mean, you talked about being in the lower range of the glide path, et cetera.

Again, it just means that we're going to hold some sales back to take advantage of higher energy prices as they materialize in time, because we truly believe that they are going to rise. And therefore, we're going to slow down the amount of, otherwise, contracting we would do into forward periods.

[Operator Instructions] The next question is from Stephen Byrd of Morgan Stanley.

I wonder if you could talk a little about the process you're going through with PJM, given the Eastlake peaker decision. Is there anything we should be looking for in the near term in terms of the assessment of further transmission needed? If, for example, anything that might come out before the auction or any other discussion from PJM as to shortfalls in the ASTI zone or anything else we should be looking for, I guess, at PJM?

I'd say, at this point, probably you shouldn't be looking for anything in the near term. Remembering that the '15, '16 auction did not clear the peaking unit at -- in that area, transmission requirements were put in place to address those concerns, as well as RMR agreements or RM, whatever -- RMR agreements which should cover that period. I would expect by the time that we get to the '16 and '17 time frame and beyond is where people would begin looking at whether or not any additional transmission's required. So I'm not expecting anything near term.

Understood. And just wanted to follow-up on Dan's question on the credit. I just want to make sure that I understood the message there. As I understand it, the message is that you have -- you've done quite a bit of refinancing and work there. You have hydro assets that you can sell and you may or may not issue up to $300 million of equity. And as you look at that, that puts you in a position to be able to maintain your credit position. Is that fair?

Yes, I would say that was fair, Stephen. And one of the things I said to the earlier question of -- on the FES side specifically is if the Harrison asset transfer goes through, then we will use those proceeds to continue our debt reduction there. If that transaction would not go forward, then the money that we had targeted to infuse from FirstEnergy holding company down to Mon Power, we could use those proceeds to infuse down into FirstEnergy Solutions, bolster their equity and give them those proceeds to pay down debt.

The next question is from Neel Mitra of Tudor, Pickering. Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: As we look at FE holdco, now that you've raised enough debt that you can deleverage enough at FES, what are the factors that we should look at to see whether you're going to kind of use the full $300 million? I guess, what are the puts and takes that would decide whether you would decide to use that? And what would it be used for, the full $300 million?

Well, I would say the primary thing that we'll be looking at, Neel, would be the hydro asset sale, when we get that completed and how successful we are there. But as we said, we do plan to issue equity sometime towards the end of the year and it would be up to $300 million. So I'd say the key benchmark to be looking at would be the hydro sale. Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then now that, I guess, we've seen a run up in '13 gas, how have your coal plants been running? Are the capacity factors higher now that we're seeing higher dark spreads than last year?

Yes, I think we said that the critical units were running around 74%. We probably have that number right there.

Yes, Page 12 of the consolidated report. The base load units were at 73% capacity factor versus last year at 65%.

Our next question is from Paul Patterson of Glenrock Associates.

Just a few quick ones on the AMP Ohio deal. As I recall, there was some sort of transmission offset in terms of CapEx. I'm just wondering the kind of CapEx savings that you might be seeing because of this? And if you could just give me a little bit more clarity as to why it doesn't impact the RPM? Is that because of other things like the energy efficiency ruling or something else?

Well, I think on the first part of your question, Paul, I think we originally said that the transmission spend was going to be several hundred million dollars higher, absent building this plant. But we'll have discussions with PJM, and that additional spend is not likely to incur -- to occur until after 2016. And it could be as late as 2019 or '20. So I think that's the answer there. As far as impacting the capacity auction, as Tony said, the '15, '16 auction did not include AMP, and so the changes between '15 and '16 and '16 and '17 will be on what PJM's assessment is on demand growth, what happens with DR and if there's any new generation. So...

Okay. I see what you're saying. So you were talking about relative to last year, the fact that -- Okay, I got you. It wasn't there before so is that what you mean? Okay, I didn't...

Yes.

Sorry to be slow on that. Okay. So just the energy efficiency ruling, what's the number of megawatts that's associated with that?

Hi, Paul. This is Leila. Roughly a delta of 160 megawatts.

Okay. And then just on this transmission side, the net system peak seemed to impact you guys and I was wondering sort of if you could elaborate a little on that. It sounds like weather and sales are sort of higher in the territory and stuff. I was just wondering what that net system peak demand reduction, what that signified versus...

That isn't for the current year. That's set on prior years' net peak demand. And I think that was actually for the end of '10, beginning of '11, where that peak was, maybe from July 1, 2010 through June 30 or May 31 of '11. So that peak demand has -- deals with prior periods. It has nothing to do with this current year.

Our next question is from Michael Lapides of Goldman Sachs.

Questions both on the regulated side of the house and on the nonregulated side. I just wanted to double check the time line. When do you expect new rates per the general rate case in New Jersey for JCP&L? When do those go in effect?

Michael, I'll let Leila jump in on this. But at this point, we have various things in front of the commission. It's the generic proceeding on the storm costs. We also have filed for a base rate increase and we've asked the commission to consider the storm costs as part of our base rate proceeding. But at this point, we would not expect that rates would go into effect until probably the first or second quarter of 2014. We have our -- currently, we have hearings scheduled for the September through the November time frame. So it's not likely we will hear anything until early next year.

And Michael, this is Leila. Just to add a little bit to that. Should they want to go forward with the generic proceedings and allow the results to flow into the rate case, it would offset the timing that Jim just laid out by a month or 2. I would imagine it would be a manageably short period of time. So that can get elongated a little bit.

Got it. And then one question on the balance sheet. Just what kind of feedback have you gotten from the rating agencies regarding just total consolidated leverage metrics. You've done a really good job of reducing debt at FES, but so far, pre the asset sales, it seems that you've just simply added debt at the holding company to reduce debt at FES. I'm just curious what kind of feedback the rating agencies have provided on consolidated debt metrics?

Well, they came out with a report, I believe it was in the February timeframe, where they gave a report on FirstEnergy consolidated. We've shared our plan with them. I think they're waiting to see the success of some of the financial initiatives that we've laid out, as well as the outcome in the Jersey rate proceedings. So I think they're waiting to see the end results of all of those. But we've fed them all of the information, and we're in active dialogue with them.

Okay. And then last item. If I look at Page 13 in the release, where you show kind of all your contract sales and your wholesale sales. One thing that stands out a little bit is just -- and I know your total megawatt hours sold has gone up year-over-year, but so has your purchase power level, especially your spot purchase power. Meaning your total purchase power is up almost 2 terawatt hours year-over-year, your spot purchase power is, I don't know, up 1.7 and change. Just curious about kind of risk management and how far in advance you procure those spot megawatt hours. I'm just trying to think about exposure, kind of exposure to future volatility in spot power prices for -- to purchase power to supply your retail customers.

Michael, this is Donny. It depends on the time frame in which we need those purchases. Obviously, if it's a summertime load issue, we'll either go out and buy -- we'll buy forwards or we'll buy call options to cover that. And if it's associated with the shoulder months, which is sometimes more likely, believe it or not, because we'll have units on scheduled outages, we'll let some of that ride in the spot market, not a large percentage of it, but we'll let some of it ride. We're very comfortable with being able to procure power to serve load. For years, prior to our merger with Allegheny, we served all of the Penelec and Met-Ed load. I think that, in total, was about 30 terawatt hours a year, and we did all -- almost all of with purchased power.

Okay. But how does that flow through? Let's say this summer, you're buying power in the spot market to serve your retail load, and for some reason, there's -- someone else has planned outages and there's a spike, a $10 or $15 increase per megawatt hour. How does that impact retail margins? And how does it impact -- I'm just trying to think about the exposure to volatility, kind of week over week or month over month, in power prices. And I don't mean kind of the $1 or $2 dollar movements. I mean, like we saw in New England this past winter, where you saw major movements in the short-term pricing.

Yes, I think that the short answer is, Michael, we would not leave ourselves that exposed. We're going to -- if we're into the summer months and it's on-peak power requirements, we're going to cover that up with a combination of forwards and calls.

Got it. So it's safe to assume by, like a May, June time frame, you've probably locked up the summer requirements, unless the demand is ridiculously hot, in which case other parts of your business would benefit.

Absolutely. Even earlier than May and June.

The next question is from Charles Fishman of MorningStar.

If you do have a lower glide path on your contract sales, will that change your strategy as far as how quickly you reduce your POLR sales over the next few years?

Charles, I don't -- this is Donny by the way. We generally use POLR sales almost as a plug, if you will, depending on how our other sales are going, and obviously, we also take a look at how competitive that POLR sale is. So they could be related, that if we've slowed down and we've become more selective around our retail sales and a good opportunity comes along in the POLR market, we may step into that little stronger. But it would really depend on what the competitors were doing in that particular auction at the time.

Okay. So I guess what I'm hearing is, they're not as directly related as maybe I thought.

No. No, they're not directly related.

The next question is from Paul Ridzon of KeyBanc.

I had to jump off and on so I'm not sure if you went over it. If you did, I apologize. But your latest thoughts on Signal Peak?

Signal Peak, it's producing very well. I think we're into the third long wall move. I think, probably beginning next year, we'll start on the surface mining. So at this point, it's performing very well. We're getting low cost out of the mine, production's increasing. And I would say ultimately, we would look to sell the asset. We've said that, that's not a business that we want to be in long term. But it's not one of the assets that we're focused on right now.

What is long term?

I would say probably within the next 5 years.

Our next question is from Greg Gordon of ISI Group.

Just on the idea of hedging and you being sort of at the low end of your sort of hedge channel versus the high end. I just went back and pulled up your last Analyst Day presentation, where you present sort of a visual guide to how you think about hedging. So is it fair to say, looking at that, that for 2014 then, given where you are this time of year, that you'd be about 55% to 60% sold forward at this point?

Yes, that's about right, Greg.

So the rest of it's open and can either be sold wholesale or into POLR?

That's correct.

And the final question comes from Raymond Leung of Goldman Sachs.

Can we talk a little about, one, provide me a quick update on securitization, I think the Ohio units have something. Can you provide some time line on that? And then also you mentioned the potential equity injection related to the asset transfer for Harrison or otherwise injecting equity down to FES. Can you sort of provide me some context of what the source of funds would be? And then the last thing also, can you talk a little bit more about the bank line extension and the accordion feature? Can you just discuss that a little bit more? Is that just a $0.5 billion incremental if you use the accordion feature?

Let me take that since I was last one, Ray. Yes, our bank credit facilities, we expect to close that in the very near term and we're going to extend that out by 1 year through May of 2018. And yes, the accordion feature will be for $500 million and that will at the corp. level. As far as the securitization, we've filed our registration statement. We've got comments back from the SEC. We're in the process of responding to those comments. And my expectation, that in the very near future, we'll be ready to take that to market.

And what the use of proceeds would be for securitization?

Well, that would be to buyback debt at Ohio Edison, Cleveland, and Toledo Edison.

Okay. And my last question on source of funds for the equity injection.

Yes, the source of funds, as we had always said from the Mon Power asset transfer, we would infuse equity into Mon Power from FE Corp. So we went out, we raised $1.5 billion, so it would be funds that were sitting there at FE Corp. And instead of pushing those down to Mon Power, we could push them down to FES if we need be. I'd like to thank everyone for joining us on the call today. We appreciate your support and your interest in FirstEnergy. Thanks everybody.

Thanks, everyone.

Thank you. Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation.