FirstEnergy Corp. (FE) Q3 2013 Earnings Report, Transcript and Summary

Greetings, and welcome to the FirstEnergy Corp. Third Quarter 2013 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Meghan Beringer, Director, Investor Relations for FirstEnergy Corp. Thank you, Ms. Behringer, you may begin.

Thank you, Melissa, and good afternoon. Welcome to FirstEnergy's third 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 provision 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. Today, we will be referring to operating earnings, which are non-GAAP financial measures previously referenced as normal as non-GAAP earnings. Reconciliations to GAAP for operating earnings are contained in the consolidated 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; 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. Now I will turn the call over to Tony Alexander.

Thank you, Meghan, and good afternoon, everyone. I'm glad you could join us. This morning, we announced third quarter operating earnings of $0.94 per share in line with our expectations, and we narrowed the 2013 operating earnings range to $2.90 to $3.10 per share, maintaining the midpoint of $3 per share from our previous guidance of $2.85 to $3.15 per share. While there were a host of small items, some positive, some negative, the narrowing of the guidance primarily reflects that weather has essentially been neutral so far this year. Jim will provide a more detailed overview of the third quarter financial results, as well as an update on our cost control initiatives and financial plan we outlined earlier this year. Leila will provide an overview of regulatory developments. My comments today will focus on the actions we're taking to strategically reposition the company and improve its overall business profile. We've always said that one of our greatest strengths, is the diversity of our assets. Our mix of operations, as well as the size and scope of each of our 3 businesses provide the flexibility to capitalize on opportunities, while mitigating risk and we are using that flexibility to improve our business profile. I'll spend the next few minutes walking you through the actions we've taken to reduce our exposure to power markets, control costs and turn our strategic focus to more predictable and sustainable growth through systematic investments in our core regulated businesses. As you know, our competitive operations have been challenged not by operational performance, but by capacity in energy markets that do not support investment in, or in some instances, the operation of generating units. While we can debate for reasons this is occurring, the fact is, power prices have been weak for the last couple of quarters and we may be facing continued soft power prices for at least the next several years. As a result, we began to reposition our competitive business in 2012 and now through a series of even more aggressive actions have better positioned this business for the future. For example, we have reduced the size and mix of the fleet by closing and selling competitive units. Last month, we closed the Hatfield and Mitchell Power plants and we expect to complete the sale of certain hydro assets later this year. In addition, we completed the Harrison and Pleasants transfer this quarter. Once the RMR units are deactivated, our competitive fleet will be a little more than 13,000 megawatts. This is about the same size as our fleet prior to the Allegheny merger, but it's a much stronger platform of units, more environmentally controlled and more efficient overall. As a result of these actions, we reset our annual retail sales target to about 100 million-megawatt hours, which fits into our overall strategy to sell at retail about 25% more than our fleet produces. We also significantly decreased our competitive cost structure. Annual operating expenses have been reduced through our continued focus on managing fuel costs and O&M expense. And more importantly, our projected capital spending in the generation group over the next several years has been reduced by more than $1 billion through our recent actions. This includes additional reductions in our expected spend for compliance with Mercury and Air Toxics Standards , which is now at $465 million across the entire generation fleet, with only an estimated $240 million at our competitive units. The majority of the remaining capital will be invested in projects to extend the life of our nuclear assets, with new steam generators at Davis-Besse in 2014 and new steam generators and reactor head at Beaver Valley 2 in 2017. Finally, we expect to reduce debt by $1.9 billion this year. And as a result, significantly strengthened the balance sheet and improved our credit metrics. Through these initiatives, we have changed the character of our competitive generating fleet by reducing both risk and costs. And now we expect our competitive business to be cash flow positive over the next 3 years. While we will discuss the outlook for the competitive business in more detail at the EEI Financial Conference, the accumulative effect of these actions also puts us in a position to maintain investment-grade credit metrics over that period and retain the ability to take advantage of improving market conditions, or market rule changes that begin to recognize the value of baseload assets, diversity of supply and reliability. More importantly, the repositioning of our competitive operations shifts our earnings profile, with regulated operations representing about 80% of operating earnings this year and increasing, especially when coupled with the growth initiatives at the regulated businesses over time. Now let's turn to a closer look at our regulated initiatives, starting with the distribution business. On the utility side, as you know, we have an active rate case in New Jersey and expect to file in West Virginia by April 2014. We are also looking for near and mid-term opportunities to accelerate the modernization and efficiency of our utility distribution system, including smart meters in order to continue to enhance reliability to customers. These efforts are expected to produce additional rate base growth and associated modest earnings growth for our 10 operating companies over time. Overall, however, growth in our utility business will be primarily tied to economic conditions. While we have been experience only modest demand growth over the last couple of years from the very low points following the beginning of the recession, we believe we are now seeing the early signs of a sustained recovery. But we are cautiously optimistic that our service area will begin to again see the robust growth associated with manufacturing expansion. The signs of growth in industrial sales over the first 9 months of this year are encouraging, particularly the activity associated with shale gas in our region. Already, shale gas-related sales have resulted in 400 megawatts of new industrial demand in addition and an additional 500 megawatts of planned expansions at customer facilities. These projects are expected to result in nearly 4% industrial growth over the next 2 years. In addition, we see a robust pipeline of midstream projects with opportunities for an additional 4 million-megawatt hours of growth through 2018. And as these gas fields are more fully developed, the opportunity for additional manufacturing expansion could further accelerate growth. While we are optimistic about these opportunities in our distribution business, the majority of our growth over the next several years will come from investments in transmission. As we told you earlier, the transmission opportunity within the FirstEnergy footprint is in excess of $7 billion. So this is a near-term and importantly, a continuing platform for stable and predicable growth. And as part of our repositioning efforts, we will begin to increase our investment in our transmission business. Last week, our Board of Directors approved as a part of our energizing the future program, a new multiyear $2.8 billion incremental investment in a transmission reliability excellence plan. The plan includes additional transmission investments above current plans, which are expected to be about $500 million in 2014, growing to about $700 million in 2015 and about $800 million in both 2016 and 2017. This program will begin with investment primarily in ATSI, but will ultimately extend throughout our service area. We currently expect to fund these investments with a combination of debt and equity. These projects include rebuilding lines and equipment to improve reliability and reduce future maintenance costs, enhancing and expanding communication networks to harden the system and increasing system capacity to meet the service level and reliability requirements of our customers. We will provide a more detailed multiyear view of our expectations, including our planned investments, financing plans and growth opportunities in the transmission business and our outlook for the competitive business at EEI next week. Slide deck will be posted through our website on Sunday morning and I will be making a presentation Tuesday morning. For those of you who are not attending the event, a live webcast of my remarks will be available on our website. To close, the cumulative impact of our actions has been to reposition this company. These actions have resulted in a reduction of our exposure and risk to power markets, while simultaneously increasing growth through our regulated operations. And we expect that our regulated operations will represent a growing percentage of earnings, and more importantly, our overall growth, with the end result being an improved business profile. Our team will continue to look at every facet of our business to identify further opportunities to lower our costs, minimize exposure to risk and create value to our shareholders. And I am very excited about the opportunities as we position this company for the future. Now I'll turn it over to Leila for a regulatory update. Leila?

Thanks, Tony. This has been a busy period in our regulated service area and I will update you on the status of several matters in West Virginia, Pennsylvania, Ohio and New Jersey. In West Virginia, we achieved a settlement in August with the majority of the parties through our generation transaction involving the Harrison power station and received an order from the Public Service Commission of West Virginia on October 7, approving the transaction with certain conditions. On October 9, the company has accepted the conditions and the transaction closed. Mon Power sold its approximate 8% share of the Pleasants Power Station for about $73 million to Allegheny Energy Supply and Allegheny Energy Supply sold its approximate 80% share of Harrison to Mon Power at a book value of $1.2 billion. The transaction resulted in a net purchase price of about $1.1 billion to Allegheny Energy Supply, and Mon Power's assumption of a $73.5 million pollution control notes. The settlement also provided for a reduction of approximately $330 million to the West Virginia rate base valuation of Harrison. Mon Power now has 100% ownership of the Harrison power station. This transaction preserve the opportunity to use locally mined coal, sustaining employments and benefiting the regional economy. The terms of the agreement also require the filing of base rate case in West Virginia for Mon Power and the Potomac Edison, no later than April 30, 2013. We also continue to evaluate the opportunity for additional rate cases across our service territories to help insure timely recovery of our investment. Let's turn now to Pennsylvania. In September, the U.S. district court granted the public -- Pennsylvania Public Utility Commission motion to dismiss the Met-Ed and Penelec proceedings on the recovery of $254 million and marginal transmission losses and associated carrying charges through the transmission service charge writer. We disagree with this ruling and filed a notice of appeal with the U.S. Court of Appeals for the Third Circuit on October 29. We completed the process of refunding customers in May, but in light of the district court's September ruling, we recognized the impairment for this item in the third quarter financial statement. Also in Pennsylvania, Met-Ed, Penelec, Penn Power and West Penn Power filed as a default service plan with the PA, PUC yesterday. The plan outlines the method by which the companies will procure the supply for their default service obligations for the period of June 2015 through May 2017. The company's programs call for quarterly descending clock auctions to procure a 3, 12, 24 and 48-month energy contracts, as well as 1 RFP seeking 2-year contracts to secure a solar renewable energy credits from Met-Ed, Penelec and Penn Power. The company's expected decision from the PA, PUC within 9 months. In Ohio, the state Senate introduced substitute Senate Bill 58, which is aimed at modifying the energy efficiency provisions originally passed in 2008 under Senate Bill 221. The bill sponsor, Senator Bill Sykes, is presiding over a series of hearings and is pushing to get these modifications passed into law by the end of this year. The House of Representatives has also introduced a companion bill, House Bill 302, with committee hearings now underway. This path, Senate Bill 58 would set a spending limitation on the cost state-mandated energy efficiency programs in future years, clarify the energy efficiency measures that may count toward meeting the benchmarks and give our largest customers the ability to opt out of mandated programs and pursue their own energy efficiency programs. The bill has the support of every Ohio and owned investor utility and has broad breed support from larger business community, including the Ohio Chamber of Commerce and union groups, including the Affiliated Construction Trades, IBEW and Ohio ironworkers. In addition, the Industrial Energy Users of Ohio, Ohio Energy Group, Ohio Steel Council and more than 350 independent job creators and economic development groups across Ohio have voiced their support. Finally in Ohio, the POLR auction that took place on October 22 resulted in a clearing price for a 1-year product of $50.91 per megawatt-hour and a clearing price for 2-year product of $59.99 per megawatt-hour for the delivery period starting in June 2014. These results will be delighted [ph] with previous auctions and 1 remaining auction to establish retail generation rates from June 1, 2014, through May 31, 2015. In New Jersey, a prehearing order was recently issued setting forth the procedural schedule for JCP&L storm cost generic proceeding. Evidentiary hearings will be held in January regarding the amount and prudency of the 2011 and 2012 major storm costs. Hearings on our base rate case are scheduled to continue through mid-November. We still expect resolution of the base rate case by the first or second quarter of 2014. Also in New Jersey, the United States district court for the District of New Jersey recently ruled that New Jersey's long-term capacity agreement pilot program, El Cap[ph], is unconstitutional because it violates the supremacy clause of the U.S. constitution. Accordingly, JCP&L's 2 remaining contracts with suppliers under the El Cap[ph] law were determined by the federal court to be void. As always, we will continue working to ensure the best possible business environment for our company. Now I will turn the call over to Jim.

Thanks, Leila. Let's get started with a look at our financial results. You may want to refer to the consolidated report, which was issued this morning and is available on our website. As Tony mentioned earlier, our third quarter operating earnings of $0.94 per share were in line with our expectations. These results compare with third quarter 2012 operating earnings of $1.11 per share. On a GAAP basis, this year's third quarter earnings were $0.52 per share compared to $1.02 per share last year. The full list of special items that make up the $0.42 per share difference between GAAP and operating earnings can be found on Page 5 of the consolidated report. Most significant of these are regulatory charges of $0.36 per share, primarily related to the impairment of Met-Ed and Penelec's regulatory assets associated with transmission line losses, which Leila just mentioned. Other special items for the third quarter include trust securities impairment of $0.03 per share, plant deactivation cost of $0.02 per share, a decrease of $0.02 per share related to merger accounting for commodity contracts, restructuring charges of $0.01 per share and gains of $0.02 per share for debt redemption and mark-to-market adjustments. Turning now to the drivers of our operating earnings. A lower effective income tax rate increased earnings by $0.09 per share. I'll take a moment to talk through this item. In 2012, our effective tax rate was 41%, primarily due to increases in the valuation allowances against net operating losses. This year, as outlined in our earnings guidance, we assumed an effective tax rate of about 38%, largely reflecting the realization of state tax planning initiatives to simplify our tax structure and our estimated mix of earnings. Additionally, in the third quarter of 2013, in conjunction with filing our 2012 tax returns, we were able to eliminate state tax obligations associated with earnings that were previously allocated to certain tax jurisdictions. This resulted in a third quarter earnings benefit of $0.05 per share and will also reduce our state tax exposure for these jurisdictions going forward. Based on these efforts, our third quarter year-to-date effective tax rate is 36% and we now estimate our effective tax rate for 2013 at approximately 37%. Earnings also benefited by $0.02 per share as a result of lower general taxes. Looking at negative drivers. O&M expenses reduced third quarter earnings by $0.06 per share. Most of this increase is related to an O&M benefit in 2012 that resulted from the capitalization of utility project cost associated with aligning Allegheny's work management system. In addition, O&M also reflects higher expenses related to fossil outages during the third quarter of 2013. Earnings were also impacted by lower investment income of $0.03 per share, higher interest expense of $0.01 per share and increased depreciation expenses of $0.04 per share. We'll now move to a review of our business results, starting with distribution deliveries. Total deliveries decreased 2% in the quarter, or 817,000-megawatt hours and reduced earnings by $0.02 per share. Cooler summer temperatures compared to the third quarter of 2012 resulted in a 7% decrease in residential deliveries and a slight reduction in sales to commercial customers. Absent the impact of weather, third quarter residential sales would have been essentially flat compared to 2012. But more importantly, high-valued commercial sales would have been approximately 3% higher than last year on a weather adjusted basis. Year-to-date, residential and commercial demand is essentially flat on weather that is tracking near-normal across the first 9 months of the year. Although we are not yet seeing anything like a return to historic growth trends, housing starts continue to increase. The increase in weather-adjusted [Audio gap] increased 3% compared to the third quarter of 2012 led by higher demand from steel customers, largely related to shale gas activity and the automotive sector. While our regional economy is still lagging the country, demand from our industrial customers is up slightly year-to-date. And as Tony mentioned, we're seeing some bright spots in this area. Moving to commodity margin at our competitive business. Commodity margin decreased earnings by $0.13 per share compared to the third quarter of 2012. The overall decline in commodity margin reflects increased competitive pressures, as well as the $10 drop in wholesale prices that took place in late 2011 and early 2012, when our retail sales position for 2013 was still about 50% open. Our fourth quarter results will reflect similar pricing and tightened margins compared to 2012. However, we expect our average prices to begin trending upwards starting in the first quarter of 2014. The average rate for 2014 committed sales is about $1 per megawatt-hour, above our 2013 expectation of $53 per megawatt-hour, and committed sales for 2015 are currently about $4 higher than 2013. Generation output from ongoing units increased by 1.6 million megawatt-hours. Fuel expense increased as a result of higher output, but the impact was moderated by lower fossil fuel prices that were negotiated in 2012. Capacity revenues from our generation fleet also increased as a result of higher auction prices. The increase in ongoing generation output was driven by greater economic dispatch of our fossil units based on higher power prices and the absence of a temporary idling of the W-8 [ph] Sammis plant last year. However, the timing of several unplanned and forced outages during the third quarter of 2013, mainly for a reactor coolant pump at Davis-Besse and generator repairs of Sammis resulted in loss sales opportunities and higher purchase power costs this year. Purchase power expenses also increased due to market prices that were higher on average than 2012 and greater retail channels sales volumes. Commodity margin also decreased as a result of increased transmission rates to serve POLR load in Pennsylvania, primarily reflecting the transfer of certain transmission charges to suppliers that took place in June, as well as increased capacity expense, primarily due to a higher rate associated with our retail sales in the MACT region. Contract sales increased to 1.9 million-megawatt hours compared to the third quarter of 2012. Total megawatt-hour sales in our competitive operations increased 7% and benefited earnings by $0.08 per share as the higher volume on these sales offset lower prices. Looking at each of our channels, structured sales increased 81% due to higher municipal, cooperative and bilateral sales. We achieved 15% growth in market sales driven by our ongoing campaigns in Pennsylvania, Ohio, Illinois and Maryland. Direct sales to the large and medium-sized commercial and industrial customers increased 3% due to customer growth in Central and Southern Ohio. Governmental aggregation sales increased 11% due to our continued expansion into Illinois, where 109 new communities have been signed since the third quarter of last year. And POLR generation sales decreased 9%, consistent with the ongoing realignment of our portfolio. FirstEnergy Solutions continues to selectively growth its retail business and increased its retail customer base by 219,000 customers or 9% in the past 12 months. As FES becomes more selective in response to greater competition, margin pressure and a slightly reduced sales target in future years, we expect this customer growth to slow. However, FirstEnergy Solutions continues to focus on profitable sales across a variety of channels and customer groups. We have the resources to generate about 75 million to 80 million megawatt-hours from our ongoing fleet and our asset-backed sales strategy continues to target selling about 25% more than we produce. For 2013, our committed sales stand at 108 million megawatt-hours and we continue to expect full year competitive generation output of 93 million megawatt-hours this year, consistent with our earlier guidance. For 2014, we have booked about 82 million megawatt-hours and we expect to boost that number in January as we have a significant contract renewal cycle beginning later this year. Our committed sales for 2015 are about 43 million megawatt-hours, again, consistent with the lower end of our glide path. Let's turn to an update on the financial plan that we introduced in February. Through a series of actions this year, we have made significant progress towards completing the plan, strengthening our credit metrics and reducing our risk profile. Starting at our competitive subsidiaries. In October, we completed the Harrison Pleasants transaction, which Leila mentioned. And by the end of the year, we expect to complete the sale of 527 megawatts of competitive hydro assets for approximately $400 million subject to various closing conditions. These transactions, coupled with our $1.5 billion equity infusion from FirstEnergy Corp. and $1.9 billion of expected debt reduction at FES and Allegheny Energy Supply, have positioned our competitive businesses to better navigate current market conditions. And looking forward, the maturity of existing sale-leasebacks will result in an additional $400 million debt reduction by 2017. We've also strengthened the balance sheets at our utilities as part of our efforts to refinance debt and reduce short-term borrowings. In August, we completed a $500 million long-term issuance at JCP&L. At our hybrid utilities, we redeemed more than $1.1 billion of long-term debt and issued securitized debt of approximately $445 million, and Mon Power is financing the Harrison transaction with a mixture of debt and an infusion of equity from FE Corp. At the parent level, earlier this year, we issued $1.5 billion in FE Corp. notes at very attractive and low interest rates, extended the maturity on existing credit facilities to May 2018, and upsized the FirstEnergy Utilities facility by $500 million. And finally, in late September, we filed a registration statement with the SEC to register 4 million shares of common stock to be sold to registered shareholders and employees under our dividend reinvestment and stock purchase plan. We expect to issue approximately $100 million of equity going forward on an annual basis by fulfilling obligations under this plan and other share-based benefit plans with newly issued shares. This financial plan, which is now virtually complete, successfully improve the balance sheet at our competitive and regulated businesses and enhance liquidity in a very short period of time. And we remain committed to investment-grade credit metrics at each of our businesses. Finally, last quarter, we told you that we were targeting $150 million to $200 million in cost control opportunities beginning in 2014. We have identified a total of $170 million in reductions with about $130 million representing O&M reductions. These cost actions are well underway and include changes to medical and other benefits and a realignment of our staffing, which was completed during the third quarter. We will continue to look for opportunities to further reduce our cost, while preserving the flexibility to create and take advantage of opportunities across all of our businesses. We have, however, repositioned the business profile of the company by reducing exposure to competitive markets and by moving forward with a more predictable and stable growth plan. As Tony stated earlier, our regulated operations are expected to represent about 80% of operating earnings this year and increase over time. Now I'd like to open the call up to your questions.

[Operator Instructions] Our first question comes from the line of Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Just on -- I knew, you're going to probably give us a lot more detail at the EEI and the transmission spending. But just kind of as we start to plot out the capital being deployed. Can you walk through what, if any, approvals need to be made to start spending the money? And if there's any threshold requirements over economic benefit or any sort of measures that have to be considered when you guys look at these dollars being deployed?

Well, at this point, Dan, as we start this project, most of this is, is internal approvals only. We're concentrating initially on our 69 kV system and the 34.5 kV system, which will be upgraded to 69. So much of what we do will be below power siding approvals or any other specific approvals. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And then you said that those dollars can be targeted primarily at ATSI in the first few years that should we see the majority of that first 4 years can be kind of independent in the ATSI structure or is that going to creep into some of the legacy Allegheny transmission systems as well?

Well, we have a fairly robust transmission program over the next several years. Part of which we talked about before and more will discuss at the EEI Financial Conference. But we'll be spending across the footprint. The transmission reliability program that we announced today is primarily ATSI. We'll begin in ATSI, I should say. Dan Eggers - Crédit Suisse AG, Research Division: Okay. So the 14 and 15 is ATSI, and then it probably catches up in the other jurisdictions?

Well, again, we're only talking about the incremental spend over and above what we're already planning, that is primarily ATSI at the beginning. Yes. Dan Eggers - Crédit Suisse AG, Research Division: Okay. Great. And then I guess just on the cost cutting program, Jim, with $170 million of cash benefits. Do you guys have any feel for kind of what the underlying O&M growth rate is going to be if we look at 14, 15, 16 just to try to get a handle on inflation?

We're not in a position to give any of that O&M growth rate. But the way I look at this, Dan, is these actions we've taken are going to help mitigate any types of cost increases going forward such as general wage increases and that. Dan Eggers - Crédit Suisse AG, Research Division: Do you think you in kind of flattening out of O&M, is that the right way to read that?

Well, Dan, why don't you wait until we provide guidance in the future. We're doing everything we can just like we always have to maintain O&M and only incur the types of costs that are absolutely we can't really avoid.

Our next question comes from the line of Jonathan Arnold with Deutsche Bank.

Just staying on transmissions, Tony, I think you said that your intent was to finance the $2.8 billion with debt and equity. So -- I mean, are we saying that this $100 million a year that Jim spoke to is sufficient to provide to go to the the equity piece of build out or is that sort of a separate financing that you weren't really speaking to?

Jonathan, my plan is to give you a little more detail next week. I think what Jim was trying to indicate, basically, is that the minimum amount of equity that's going to be necessary will be the continuation of whatever that program as we call it, it's the dividend reinvestment and the employee benefit types of programs. So I would -- so from your modeling standpoint, you can assume that that's going to continue through at least this period, and then we will be evaluating in discussing more with you next week some of the options as the transmission spend grows over time.

Okay. So we start sort of a -- will look forward to hearing that next week.

Our next question comes from the line of Julien Dumoulin-Smith with UBS.

So first, perhaps not to spill to much in there for next week, but could you perhaps summarize, if you will, the growth trajectory and output base from on EPS perspective, you're talking about for transmission, just kind of summarizing everything?

It's up. You'll hear about it Next week.

All right, fair enough. I'll hang tight there. With regards to the hedge position in '15, you talked about a $4-megawatt hour improvement on what it seems to be like 43 million megawatt hours. How much of that -- is that correct, first off?

Yes.

How much of that is derived from capacity price improvement versus through energy hedge position, if you get what I'm saying? Like because I take it that, that price is in on-inclusive numbers?

Yes, it is. And Donny is here. He can jump in. But the majority of that increase, Julien, would be from the capacity.

Yes, that's correct. Jim made reference back to the 13 number. And so as the roll-off occurred and we faced lower wholesale prices, obviously, the energy component gets depressed, Julien.

Now I don't want to push this too far, but is there actually a negative offset in the energy and actually the capacity more than offset the decline in the energy price? Or is it...

Yes, I thank you know what the capacity prices are out there. So you can calculate that Julian, and I have not that done that calculation.

Our next question comes from the line of Paul Fremont with Jefferies.

I guess my first question is have you guys looked at potential opportunities to ultimately separate out your transmission business?

Paul, we look at all types of opportunities. Obviously, as we think about how we're going to finance and address these issues over time. Right now, we're pretty comfortable with where we're at. That doesn't necessarily mean that it'll stay that way. But that clearly is something that has been on our radar screen for quite some time.

And the other question that I have is with respect to the O&M cut of 130 that you've already identified, how much of that is utility and how much of that is competitive business?

I don't have the exact breakdown on that, Paul. But I would say it's probably about in the 50/50 range since a lot of it deals with benefit reductions that would be similar for all of our staff. I would just look at 50/50.

Our next question comes from the line of Stephen Byrd with Morgan Stanley.

I wanted to first talk about your -- the coal cost for your fleet. As you look out, obviously, the coal industry is facing pressure. Do you see opportunity there in terms of further negotiations in terms of your coal cost and your outlook given the pressure that the coal industry is facing? Or how should we think about your coal cost over time?

Go ahead, Donny.

Stephen, this is Donny. I think we have a pretty solid track record over the years of being able to keep our coal cost low and actually push them down even in a rising market. So obviously, we'll continue to pull on all of the levers. I think it is getting more difficult as our coal suppliers are hitting points to where they're kind of operating at some of their cash cost, so it becomes more difficult. But we'll continue to pull on all those levers.

Understood. And then I guess just switching over to the big ass side of things. Tony, you mentioned at the beginning, the gas outlook is challenging and the power price outlook is challenging. As you all look out today and you think about the size of your retail business at about 100 million-megawatt hours overtime, which is I guess about 25% above fleet output, do you see that staying fairly stable? Or given the sort of gas and power look as you see it out in '15 and '16, is there a potential that, that retail business would need to get a bit smaller than the 100 million-megawatt hours?

I don’t -- I'm not seeing that. I think it's perhaps just the opposite in terms of whether or not you want to take some additional risk as opposed to give up customers. So I think there will be a balancing as we go forward in that portfolio.

Our next question comes from the line of Kit Konolige with BGC.

Just a couple of sort of fill-in-the-blanks type of questions. Tony, you mentioned that you expect that you may be facing -- market may be facing weak power prices over the next several years. What -- it seems to me you've been more bullish than that in the past. What has changed your mind?

Well, I think, Kit, in the main, I'm still bullish on the competitive markets overall. But reality is we had a PJM auction for 16 and 17, which was, I think, in everyone's thought process is much weaker than any one anticipated. The delay in shutting down generation across the overall footprint, as well as the, what is it, a parent reliance and the market on what I consider to be a softer generating substitutes or resources all have an impact. The question will be what happens over time? And from our perspective, it's far more important for us to manage our business given that if it stays soft, we're prepared and positioned where we're cash flow positive, and we can talk about more of the details later. And if it improves, and we certainly would like to see some of the obstacles eliminated to help that happen, we'll be in a very strong position to take advantage of it.

Fair enough. I noticed though that in your...

But we're not going to sit back and hope and wait.

Right.

We're going to take action.

What role -- where do you see -- let me just ask it this way. What's your kind of middle and longer-term growth rate that you project for your service territories? And in assessing future pricing in PJM, what you do see as the growth rate for sales in PJM overall?

Again, I'm -- we're not going to talk about that kind of stuff, Kit, as we go forward, nor am I going to give you an indication of how I -- where I think the markets are going to go. We're targeting about 100 million-megawatt hours in sales. We think we can accomplish that. We're over that this year, so it'll be a little bit of pruning as opposed to acquiring, but I think we'll be doing both over the next several years as we reshape that portfolio to customers and markets in areas in which we can produce greater returns.

Our next question comes from the line of Paul Patterson with Glenrock Associates.

I just wanted to touch base with you on just the transmission again. Is this -- this $2.8 billion is part of the $7 billion I think you said before, is that correct?

Yes.

Okay. And what sort of triggered this appraisal of this need? Was there -- was it Sandy? Was there -- I mean, is there anything that -- is it cyber stuff? What -- I mean, it seems like a pretty large increase that you guys have come up with. I'm just wondering what led you guys to it?

Well, I think it's a combination of factors. All of these items -- I mean we don't come up with this list in a day. All these items are systematically -- as we evaluate our system, much of which in terms of age of infrastructure is reaching towards end of life. It's time now to begin the process of putting that system in a position where it provides continuing strong service to customers and now is the time to start it. Obviously, we were hoping that the economy would have recovered earlier that there would have been different opportunities across the footprint. But with what is happening around us and for many conversations we've had with customers in terms of what they'd like to see our system be capable of doing, what we're trying to do is address those as we prepare the system for what is going to have to be capable of delivering down the road.

Okay. Now there have been a whole bunch of transmission proposals for market-to-market congestion between MISO and PJM. I was wondering if you saw any opportunity in that? And also, if you saw any potential impact to PJM markets as a result of some of the things that are being proposed by some of your -- some of the other guys around you?

Well, I'm not -- we're concentrating primarily inside our footprint. We've got a large transmission system, and our focus is on that. Obviously, I think being able to increase transmission capability inside PJM would be helpful. I mean, it's frustrating that we can get generation from Louisiana to Ohio, but we can't get from the Ohio River to Philadelphia. So there are a lot of things that can be addressed inside that space over time. It all takes time and it all takes a lot of effort to accomplish. But the fact of the matter is, from our perspective, we're looking internally. We're not looking for projects that have long lead times with respect to either approval processes or likely construction processes. And we'll give you a lot more of that detail in this upcoming meeting.

Okay. And then just on sort of a housekeeping item. On Page 14 of the cash flow statement, there's an $18 million noncash gain from asset sales and I was just wondering what that represented? And I guess, that sounds like -- it was a noncash benefit to net income, I guess, is what that looks like to me. What was that?

That was the sale of the synchronous condensers from FirstEnergy Solutions to ATSI.

Okay. So there is a net income impact for the company?

Not on an operating basis.

Okay. So it's part of the -- okay. And you guys, can you give us -- I know you guys are sort of hesitating on giving guidance for 2014, but any sense as to what a normalized tax would be for 2014?

No, I mean if you look at the tax rate, it's going to range somewhere from 37% to 38% this year, primarily closer to 37%. But the tax rate in any given year is going to be based on the mix of earnings. So we'll have to look at it as we kind of prepare for 2014 earnings guidance.

Our next question comes from the line of Steven Fleishman with Wolfe Research.

Just on the -- first clarification on the transmission spending plan. I know there were some much lower base spending before the new plan. Is that included in the numbers you provided or that -- what was the base before this?

I think our base transmission spend over this time frame, I'm not sure we've identified that in the past, but this would be in addition to that. But we'll try to give you a better sense for that as we go forward. So I think the only real transmission spend we've identified, which is obviously in part of the base plan is the significant amount of transmission investment that's being put in place across our system to deal with power plants that are being shut down by 2015. Now if I remember that number, and don't hold me to this, but I think it was in the $700 million range. And then to that, you would add kind of the normal transmission spending that we have in each of our service areas, including for projects like the light project in Jersey at Jersey Central Power & Light that was announced about a year or so ago. So all of those kind of come together, kind of normal baseline spending that you're going to do in any event, the kind of additional spending you have in connection with power plant shutdowns, enhancement programs like the Jersey light program. And now on top of those is the additional transmission incremental spend of $2.8 billion.

Okay. And then just also on distribution. I know you mentioned things like smart grid and such. Is there a meaningful increase in the rate base investment or CapEx and distribution?

Well, we spend in excess of about $1 billion a year on distribution capital. So rate base grows every year. There will be opportunities and I think Leila will be seeking them out in the various jurisdictions. There are areas in distribution not of -- electric distribution not unlike in gas distribution where underground facilities should be getting replaced and we ought to work through the kind of mechanisms that the gas industry generally has, which typically are more favorable than the electric. So there's a lot of opportunities not only with respect to smart meters, but with respect to upgrading aging infrastructure overall. Operator, we'll take one more call.

Our next question comes from the line of the Angie Storozynski with Macquarie. [Technical Difficulty]

We can barely hear you.

Maybe this is going to be better. I had a question about your expectation for ATSI capacity prices given your transmission CapEx. Do you expect that ATSI will continue to clear at a premium versus RTO? Your spending quite a bit of CapEx on your transmission lines, so how should we think about ATSI capacity prices going forward?

Donny, could you answer that?

Angie, this is Donny. I think as time goes forward, there's probably a lower probability that ATSI separates. But I would think probably this coming May, it will probably still separate would be my guess. But what you'll see is, as we get out beyond that period if it still separates.

Okay. Secondly, when you mentioned the price, the sale price for the FES' secured sales volumes and you told us that we do know what the capacity revenue or the capacity prices are, should we assume that you are averaging out the spike in ATSI capacity prices throughout say '15, '16? Or should we assume that there is just as the cleared prices where -- that we have a sudden spike in capacity revenues, hence, the contribution of capacity through '15 sales prices is higher?

Angie, in general, those are going to be levelized capacity charges depending on obviously the length of the contract. We do have a few customers, not many, but a few customers that allow the capacity as a pass through, so that would be the one exception.

And lastly, Tony, you mentioned free cash flow positive. The expectations and investment-grade rating expectations for FES for the next 3 years. Do you include '13 in this comment or is it '14, '15, '16?

Yes, Angie, we would include all 4 years in that. We've made a significant improvement there in '13 with our competitive business unit, the metrics. Okay. Thank you. I'd like to thank everyone for joining us on the call today. We remain committed to providing value to shareholders, while positioning FirstEnergy for sustainable long-term growth. Thanks for your support and your interest in FirstEnergy, and I look forward to seeing you many next week at EEI.

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