第一能源 (FE) 2013 Q1 法說會逐字稿

Greetings and welcome to the FirstEnergy Corp. first quarter 2013 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 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, so they 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.FirstEnergy Corp.com\IR.

Participating in 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; Donnie Schneider, President of First Energy Solutions; John 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 would 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 page. 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 will 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 will 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 First Energy Solutions, 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 we due in 2015. We also reduced leased debt by about $100 million with the repurchase of certain remaining lesser 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 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 are 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 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 1240 megawatts of unregulated non-core 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 at FirstEnergy Corp., means the Harrison transaction, while still important to both West Virginia and First Energy 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 East Lake, Ohio, American Municipal Power has notified us that they do not intend to proceed with the project. With this development, the East Lake 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 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 First Energy Solutions, we continue to focus on expanding our retail business, strengthening our brand among customers in both new and existing target markets and implementing our multi-channel 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 polar 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 paths 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 Pleasance stations. These extensions provide for an additional year, like I said, through April of 2016, 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 stand-alone 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. Today, I'll 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 continued 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 rate payers.

On April 4, 2013 JCP&L filed a motion with the BPU requesting that the Commission reconsider its March 20 order and ruled that the company's costs 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 advance 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 for mid-September through mid-November.

Turning now to West Virginia, on April 23 we received FERC authorization for the proposed Harrison/Pleasance transaction to transfer nearly 1500 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 for 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 turn 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 the list of special items that make up the difference between the GAAP and non-GAAP results. The largest of these special items is $0.18 per share in debt redemption costs 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 costs of $0.01 per share, a decrease of $0.01 per share from impacts of the sale or impairment of non-core 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 refineries 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 the TRAIL, the Trans-Allegheny Interstate Line Company, and lower net system peak demand.

Finally, I would 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 continued 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 are 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, corporative in 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. 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 super-critical and 54% at our sub-critical units, compared to 65% and 24%, respectively, at these 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 are 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) Dan Eggers, Credit Suisse.

Just following up on Tony's comments and Leila's comments about Harrison, can you maybe help us understand how important it is, do you think, at this point in time to move that asset over from a balance sheet perspective relative to the customer benefit perspective? And then, given the wide or the low bid made in the intervenor testimony, how important it is 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?

I will 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 are in pretty good shape by getting the FirstEnergy Corp. bond deal doing, where we up-size it to $1.5 billion. We also feel that we are in very good position with the hydro asset 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 had planned for Mon Power down into FES. So I think we would end up at a good position for the balance sheet there at FES.

Dan, 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 at FirstEnergy.

But if it didn't transfer, you would feel comfortable keeping that extra capacity at FES?

Absolutely. It's a great asset, so that's not a consideration.

Okay, and then I guess on RPM outlook, you guys have kind of signaled, Donnie, 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 at the same time you were.

Oh, I'm sorry. I was just going to ask Donnie, since last -- he said prior that RPM expectations were relatively flat or that's kind of where he 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.

No, I really haven't changed my opinion here, Dan. We will see here in a couple of weeks, obviously, where the auction comes out.

Okay. And then just one last question. On industrial load, you said you were 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 are 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's still too early to say because some of the other things are not as strong. Automotive is down a little bit, but the fact of the matter is there have 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 are 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.

Okay, thank you, guys.

Jonathan Arnold, Deutsche Bank.

Just a quick one on -- so use of proceeds, if you are successful in Harrison and hydro, because you have already hit your de-delivering 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.

Okay, great, thank you.

Julien Dumoulin-Smith, UBS.

So just following up on Dan's question a little bit here, with regard to ATSI specifically, what do you expect there in 2016-2017, just to be explicit?

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

Alright, fair enough. And again, following up on the 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 seen come out of that program that you would expect to bid?

Roughly, right now, we are 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 are getting at -- of roughly 160 megawatts.

Great, thank you. 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 that $1 per megawatt hour fashion. I would be curious if you guys would be willing to opine using a comparable metric out in 2015 or 2016, or what have you.

I think it's always interesting. I've heard what they 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 supply side more in balance over time. I'm not sure that that's fully reflected yet in the forward prices that we are seeing out there. And on the demand side, we are 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 the last one here -- how does that fit into your hedging strategy here? You talk about being in the lower range of the glide path, etc.

Well, again, it just means that we are 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.

Okay, fair enough, thank you.

(Operator instructions) Stephen Byrd, Morgan Stanley.

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

I would say at this point probably you should be looking for anything in the near-term, remembering that the 2015-2016 auction did not clear the peaking unit in that area. Transmission requirements were put in place to address those concerns as well as RMR agreements -- or RM, whatever they are -- RMR agreements, which should cover that period. I would expect by the time we get to the 2016 and 2017 time frame and beyond is where people would begin looking at whether or not any additional transmission is 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 wanted to make sure that I understood the message there. As I understand it, the message is that you have done what 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 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.

Understood, great, thank you very much.

Neel Mitra, Tudor Pickering.

As we look at FE holdco, now that you have raised enough debt that you can de-leverage enough at FES, what are the factors that we should look at to see whether you are going to 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?

I would say the primary thing that we would be looking at, Neel, would be the hydro asset sales, 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 would say the key benchmark to be looking at would be the hydro sale.

Great. And then now that I guess we've seen a run-up in 2013 gas, how have your coal plants been running? Are the capacity factors higher now that we are 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 baseload units are at 73% capacity factor versus last year of 65%.

Okay, great, thank you.

Paul Patterson, 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 will have discussions with PJM, and that additional spend is not likely to occur until after 2016, and it could be as late as 2019 or 2020. So I think that's the answer there.

As far as impacting the capacity auction, as Tony said, the 2015-2016 auction did not include AMP. And so the changes between 2015 and 2016 and 2016 and 2017 will be on what PJ's assessment is on demand growth, what happens with DR and if there's any new generation. So --

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

Yes, yes.

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

Roughly a delta of 160 megawatts.

Okay, and then just on this transmission side, the net system peak seemed to impact you guys. I was wondering if you could elaborate a little on that. It sounded like weather and sales are higher in the territory and stuff. I was just wondering what that net system peak demand reduction -- what that signifies versus (multiple speakers) --

That isn't for a current year, that's set on prior years' net peak demand, and I think that was actually for the end of 2010, beginning of 2011, where that peak was, maybe from July 1 of 2010 to June 30 or through May 31 of 2011. So that peak demand has deals with prior periods. It has nothing to do with this current year.

Okay, thanks a lot.

Michael Lapides, Goldman Sachs.

Questions both on the regulated side of the house and on the nonregulated side. I want to just 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 into effect?

Michael, I will 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 cost. We also have filed for a base rate increase and we have asked the commission to consider the storm cost 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.

Just to add a little bit to that, should they want to go forward with the generic proceedings as and allow the results to flow into the rate case, it would affect the timing that Jim just laid out by a month or two. I would imagine it would be a manageably short period of time. So that could elongate it 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 have done a really good job of reducing debt at FES, but so far, pre the asset sales it seems that you have just simply added debt at the holding company, reduce debt at FES. 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 time frame -- where they gave a report on FirstEnergy consolidated. We have shared our plan with them. I think they are waiting to see the success of some of the financial initiatives that we have laid out as well as the outcome in the Jersey rate proceeding. So I think they are waiting to see the end results of all of those. But we have fed them all of the information and we are in active dialogue with them.

Okay. And then last item -- if I look at page 13 in the release where you show all of 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 purchased 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 and just trying to think about exposure, exposure to future volatility in spot power prices to purchase power to supply your retail customers.

It depends on the time frame in which we need those purchases. Obviously, if it's a summertime load issue, we will either go out and we will buy forwards or we will buy call options to cover that. If it's associated with the shoulder months, which is sometimes more likely, believe it or not, because we will have units on scheduled outages, we will let some of that ride in the spot market -- not a large percentage of it, but we will let some of it ride. We are 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, and I think that in total was about 30 terawatt hours a year. And we did almost all of them with purchase power.

Okay, but how does that flow through? Like let's say this summer you are buying power in the spot market to serve your retail load, and for some reason someone else has plant 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 exposure to volatility week over week or month over month in power prices. And I don't mean the $1 or $2 movements like we saw in New England this past winter, where you saw major movements in the short-term pricing.

Yes. I think the short answer is, Michael, we would not leave ourselves that exposed. We are going to -- if we are into the summer months and it's on peak power requirements, we are 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 demand is ridiculously hot, in which case other parts of your business would benefit?

Absolutely, even earlier than May and June.

Got it, thank you, guys, much appreciated.

Charles Fishman, Morningstar.

Thank you. 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?

You know, Charles, I don't -- this is Donnie, 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 have become more selective around our retail sales, and a good opportunity comes along in the POLR market, we may step into that a 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 are not as directly related as maybe I thought?

No, no, they are not directly related.

Thank you.

Paul Ridzon, 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 are into the third longwall move. I think probably beginning next year, we will start on the surface mining. So at this point, it's performing very well. We are getting low cost out of the mine, production is increasing. And I would say, ultimately, we would look to sell the asset. We have 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 are focused on right now.

What is long-term?

I would say, probably within the next five years.

Okay, thank you very much.

Greg Gordon, ISI Group.

Just on the idea of hedging and you being at the low end of your 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 as to how you think about hedging. So is it fair to say, looking at that, that for 2014, then, given where you are at this time of year, that you would be about 55% to 60% sold forward at this point?

Yes, that's about right, Greg.

And so the rest of it is open and can either be sold wholesale or into POLR?

That's correct.

Okay, guys, thank you.

Operator, we will take one more question.

Raymond Leung, Goldman Sachs.

Michael got my one question about the rating agencies, but could we talk a little bit 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 provide me some context of what the source of funds would be? And then the last thing would 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 $0.50 billion incremental, if you use the accordion feature?

Let me take that, since that was the last one, Ray. Yes, our bank credit facilities we expect to close that in the very near term, and we are going to extend it out by one year through May of 2018. And, yes, the accordion feature will be for $500 million-dollar, and that will be at the FE Corp. level.

Okay, great.

As far as the securitization, we have filed our registration statement. We have got comments back from the SEC. We are in the process of responding to those comments. And my expectation that in the very near future, we will be ready to take that to market.

And what would the use of proceeds be for securitization?

That would be to buy back debt at Ohio Edison, Cleveland and Toledo Edison.

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 and 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.

Okay, thanks, guys.

Okay, Ray.

I would 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.