第一能源 (FE) 2013 Q4 法說會逐字稿

Greetings and welcome to the FirstEnergy Corp Fourth 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, Meghan Beringer, Director of Investor Relations for FirstEnergy Corp Thank you, Ms. Beringer. You may begin.

Thank you, Christine, and good afternoon. Welcome to FirstEnergy's fourth 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 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 information and financial releases link. Today, we will be referring to operating earnings, which is a non-GAAP financial measure.

Reconciliations to GAAP earnings from operating earnings are contained in the consolidated report, as well as on the investor information section on our website at www.firstenergycorp.com/ir. Please note that our annual report on Form 10-K is expected to be filed within the next several days.

Participating in today's call are Tony Alexander, President and Chief Executive Officer, Leila Vespoli, Executive Vice President Markets and Chief Legal Officer, Jim Pearson, Senior Vice President and Chief Financial Officer, Donald 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. I will start today's call with an overview of 2013, including our unaudited results and accomplishments. We will also take another look at our areas of focus for 2014 and the next several years. I will then turn the call over to Leila.

In January, Leila took on an expanded role that now includes responsibility for our competitive business, so she will provide a power market outlook, in addition to her normal update on regulatory developments. Finally, Jim will share a more detailed overview of the fourth quarter financial results and review our 2013 financial achievements. Then he will discuss 2014 initiatives before turning the call over for questions. Let's get started.

This morning, we announced operating earnings of $0.75 per share for the fourth quarter of 2013 and $3.04 per share for the full year, at the upper end of our guidance, which reflects our strong operating performance for the year. As you know, 2013 was a challenging year for the Company as we took action to improve our financial position, lower our cost structure, and position the Company for more stable and predictable growth through our regulated holdings.

Some of our key accomplishments included successfully implementing our financial plan, which reduced our debt at our competitive business by $1.5 billion, improved its credit metrics, and strengthened its balance sheet. We reconfigured our competitive generation fleet and as a result, reduced cost while retaining a mix of generating assets that is more cost-effective, efficient, and environmentally sound.

We also successfully completed the Harrison and Pleasants asset transfers, which is expected to help ensure reliable power for our Mon Power and Potomac Edison customers in West Virginia for many years to come. We deactivated the Hatfield and Mitchell plants and we recently completed the sale of certain hydro units. Finally, we announced a long-term growth strategy in our transmission business, targeting $4.2 billion in investments over the next four years.

In combination, these actions and others are repositioning the Company's business profile to be far more focused on regulated operations. Respecting our business results for 2013, I'll start with our competitive operations. During the year, contract sales at FirstEnergy Solutions increased 9% from 2012 to nearly 109 million megawatt hours.

Full-year total generation output was nearly 93 million megawatt hours, which is about a 4% decrease from 2012 and that largely reflects the smaller size of our competitive fleet that occurred during the calendar year 2013. Our nuclear fleet completed several significant achievements, including the successful installation of new low-pressure turbines at both Perry and Beaver Valley Unit 1. These installations will increase our nuclear capacity by about 45 megawatts.

Both Davis-Besse and Beaver Valley continued their overall strong and safe operating performance and Perry returned to the Nuclear Regulatory Commission's routine level of oversight, recognizing its improved operational and safety performance. We also completed a large volume of work at Davis-Besse to support the steam generator replacement project which began February 1, 2014.

Our fossil fleet also performed well and after significant work to ensure the most economic approach to address upcoming environmental requirements, we began installation of the new emissions equipment at our units. Earlier this month, we received notice that PJM would discontinue the RMR arrangements for our Eastlake and Lake Shore plants as of September 15, 2014; about six months ahead of schedule.

As a result, we plan to deactivate those units later this year, which will leave us with one remaining RMR agreement for the Ashtabula plant, which is a 244 megawatt facility and that agreement will run through April 2015. We are moving forward with our plans to convert Eastlake's generating units to synchronous condensers. That will improve grid reliability through voltage regulation.

The unit 5 synchronizer was installed and became operational in 2013 and we expect to complete the conversion of units 1 through 4 by the summer of 2015. Leila will provide more insight into our committed sales and other expectations for 2014, but it is important to recognize that, despite the unlevel playing field and competitive capacity in energy markets, we continue to be a strong supplier of choice by customers.

Moving now to a review of our distribution business: during 2013, total distribution sales increased by 1%. We are encouraged by the slight growth in commercial sales of 0.5% on a weather-adjusted basis, particularly because the commercial sector has not shown any meaningful recovery since the beginning of the recession. Residential sales were up slightly, but more importantly, we increased our residential customer count across the system.

We now serve more customers than we did in 2007, which was the peak year of economic activity, pointing again to a growing customer base. Another bright spot is sales to industrial customers, which were up a healthy 2%. This was primarily driven by manufacturing segments related to the shale gas in our region, as well as a slight pickup in the automotive sector.

We are cautiously optimistic that we are seeing signs of more sustained recovery in both the commercial and industrial sectors and that these are indicators of an economic in-turn that could help drive growth in our utility business. From a reliability standpoint, our utilities had a solid year in 2013 and we continue working to enhance our service to customers, particularly during severe weather.

As an example, we recently implemented an incident command system to plan and manage our facilities, equipment, personnel, and communications during storm events. In addition, during 2013, we completed our new transmission control center, which is designed to make our current high level of transmission service reliability even better. The control center operates approximately two-thirds of our bulk transmission system and features the industry's most advanced monitoring and operations technologies.

Shifting now to our expectations for 2014 and the next few years, as we have said, we have significantly repositioned our business mix and earnings profile by turning our strategic focus to more predictable and sustainable growth through systematic investments in our core regulated businesses. We are targeting 80% or more of our earnings through regulated operations in 2014 and going forward.

As you know, this morning we affirmed our 2014 operating earnings guidance of $2.45 to $2.85 per share, including operating earnings guidance range for each of our segments. We also provided a first quarter operating earnings range of $0.35 to $0.45 per share, which includes the planned Davis-Besse extended refueling and steam generator replacement outage that started on February 1, as well as our estimates for the impact of extreme weather.

We intend to set a relatively conservative course over the next few years that is focused on taking advantage of well-defined and attainable opportunities. In our utility business, while we anticipate only modest load growth of about 0.6% in 2014, with most of that coming from the industrial sector, our service area is solidly positioned to benefit from further development in the Marcellus and Utica shale fields and the manufacturing growth that should accompany that development.

My sense is that when this area is successful in attracting a cracker plant, it will stimulate and accelerate the manufacturing expansion potential in our service area. While economic strength is the most critical engine for distribution growth, we also continue to prepare for rate cases that will be filed in West Virginia in April and potential cases in Pennsylvania later this year.

These efforts are expected to produce associated modest earnings growth for our utility companies over time. In our transmission business, consistent with our announcement late last year, we are starting to move forward with the $4.2 billion in capital expenditures through the 2014 through 2017 time frame. These investments are expected to support continued system reliability and enhance service to our customers while driving much of our growth over the next several years.

We will initially focus on investments in axing on the 69 kV system and above in Ohio and Pennsylvania and certain other projects in TrAILCo; both of which receive formula rate recovery. With the introduction of this transmission growth program, we expect to begin to see an uptick in our results from this business over the next two years, followed by a more significant earnings contribution starting in 2016.

While these planned investments in growth will take some time to fully execute, we remain committed to creating value through our significant and diverse asset base. We appreciate your support. Now, I'll turn it over to Leila for a regulatory and power markets update. Leila?

Thanks Tony. I will start with an update of the status of several matters in New Jersey, Pennsylvania, and Ohio before moving to a high-level look at FirstEnergy solutions and developments in our region's power market. Starting with New Jersey, yesterday we signed and filed a settlement agreement with board staff and rates counsel to permit recovery and base rates of $736 million of JCP&L $744 million of costs related to the significant weather events of 2011 and 2012.

The agreement, upon which no other party took a position to oppose or support, is now pending approval before the Board of Public Utilities. Of course, we still do have a base rate case pending in New Jersey. Hearings have concluded and we filed our reply briefs in this case yesterday. We expect resolution of the base rate case within the next four months.

Let's turn to Pennsylvania for an update on the transmission service charge rider, which relates to the recovery of $254 million in marginal transmission losses and associated carrying costs for the June 2007 through March 2008 period. As you know, we completed the process of refunding Met-Ed and Penelec customers in this case last spring and we recognized an impairment for this item in our third quarter financial statements after the US District Court dismissed our proceeding.

However, we continue to believe in the merits of our position and during the fourth quarter, we appealed to the Third Circuit. Briefs have been filed and an oral argument has been scheduled for April 9. Moving now to Ohio, in December, the Public Utilities Commission denied our hearing request for recovery of $43 million of renewable energy credits purchased to comply with Ohio's Renewable Energy Portfolio Standard.

On December 24, we filed a notice of appeal and motion for stay of the PUC order with the Supreme Court of Ohio. The court granted our stay on February 10. I should also note that two additional parties appealed the case: the Office of Consumers Counsel and the Environmental Law and Policy Center. We expect briefing will occur through the spring, but we do not expect an opinion from the court this year.

Ohio's POLR auction that took place on January 28 resulted in a clearing price of $55.83 for a one-year product and $68.31 for a two-year product for the delivery periods starting June 2014. FES won five, one-year tranches and two, two-year tranches in this auction. These results are blended with previous auctions to establish retail generation rates starting June 1, 2014 and will affect certain of our retail rates.

Significantly, these prices are about $5 and $8 higher than the auction that took place in October and would indicate the bidders are beginning to allow for some additional risk premium. Respecting our competitive business, FirstEnergy Solutions increased its retail base by approximately 100,000 customers during 2013 and now serves about 2.7 million customers. Going forward, we intend to be more selective in our sales strategy and response to market environment and our smaller generating fleet.

In fact, on February 12, we completed the previous announced sale of 527 megawatts of competitive hydro assets for approximately $395 million. We expect our fleet to produce 77 million megawatt hours and our sales strategy targets 99 million megawatt hours this year. Consistent with our glidepath, we are well-hedged with 94 million megawatt hours currently committed for 2014.

Looking ahead, we have booked 52 million megawatt hours for 2015 and 29 million megawatt hours for 2016, with a substantial portion of the sales in government aggregation and POLR channels. These sales are on track with the lower end of our glidepath and should allow us to take advantage of any increases in market and energy prices that may occur in that timeframe.

Now, let me take a moment to discuss, in more detail, the extreme weather in our region over the past months and in January, in particular, that impacted our competitive (inaudible) business. We incurred increased purchase power expense related to higher than forecast customer usage during several extreme weather periods, as well as additional energy necessary to replace unit availability. Beaver Valley Unit 1 was not operating for most of January while we replaced the main transformer.

We were fortunate to have a spare on the plant site. We also experienced some other unplanned fossil unit outages and D rates. We also expect to see increased PJM charges for ancillary expenses in the first quarter of 2014, the majority of which we expect to recover from retail customers. These expenses include synchronous and operating reserves, which are necessary for reliability and socialized across the low serving entities based on load share.

PJM is still assessing the January settlement data and we plan to provide a more detailed update during our first quarter earnings call in early May. The situation with market power prices in January was the product of baseload generation that was stretched to its limit and exasperated by gas units that impacted by constrained gas transmission and high spot trading prices.

Together with others in our industry, we will continue to diligently focus on advocating for reforms that are necessary to ensure that the PJM market is in a position to provide reliable power and stable prices to customers. Now I will turn the call over to Jim.

Thanks, Leila. Let's move right into 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 fourth quarter operating earnings of $0.75 per share were at the higher end of our expectations.

These results compared to fourth quarter 2012 operating earnings of $0.80 per share. On a GAAP basis, this year's unaudited fourth quarter earnings were $0.34 per share, compared to a loss of $0.35 per share last year. The full list of special items that make up the $0.41 per share difference between GAAP and operating earnings can be found on page 4 of the consolidated report.

Most significant of these are a charge of $0.51 per share related to the transfer of our Harrison and Pleasants plants in West Virginia, a $0.14 per share charge related to planned deactivation costs associated with the closure of fossil units and regulatory charges of $0.12 per share. These were partially offset by a gain of $0.38 per share related to our annual pension and OPEB mark-to-market adjustment which benefited from a higher discount rate.

Other special items for the fourth quarter include trust securities impairment of $0.02 per share, non-core asset impairments of $0.02 per share, a decrease of $0.02 per share related to merger accounting for commodity contracts, and a gain of $0.04 per share for other mark-to-market adjustments. Let's move now to review a of our business results.

In our distribution business, higher revenues increased fourth quarter earnings by $0.05 per share as total distribution deliveries increased 4% or 1.4 million megawatt hours compared to the fourth quarter of 2012. On the residential and commercial side, the gains during the quarter were largely weather driven, with colder winter temperatures driving 3% increases in both residential and commercial sales.

Adjusted for weather, residential sales were essentially flat, while commercial sales were up slightly. As Tony said, this continued a positive trend from the third quarter, which comes on the heels of a very long period of no commercial growth. Looking at industrial deliveries, sales increased 6% compared to the fourth quarter of 2012, driven again by shale gas activity in the steel sector, as well as continued growth among our automotive customers.

Reiterating Tony's comments a few minutes ago, our outlook for load growth remains cautious, but these are bright signs relative to what we have seen in the year since the recession began. To provide more transparency in our distribution business and as a result of the Harrison plant asset transfer in the fourth quarter, we're providing operating margin at our regulated generation business, which increased earnings by $0.02 per share in the fourth quarter.

Moving to commodity margin at our competitive business, commodity margin decreased earnings by $0.09 per share compared to the fourth quarter of 2012 and total competitive generation output decreased by 3.3 million megawatt hours in the quarter. Fuel expense was lower in the quarter helping to offset the higher purchase power cost that resulted from the Hatfield and the Mitchell plant closures, the Harrison transfer and the increased contract sales.

Contract sales increased 2.3 million megawatt hours compared to the fourth quarter of 2012. Looking at each of our channels, structured sales nearly doubled compared to the fourth quarter of 2012, due to higher municipal, cooperative, and bilateral sales. Governmental aggregation sales increased 10%, largely reflecting further expansion into Illinois, where we have signed 108 new communities since the fourth quarter of last year.

Marketing campaigns in Pennsylvania, Ohio, and Illinois resulted in a 27% increase in mass-market sales. Direct sales to large and medium-sized commercial and industrial customers increased 2%, reflecting service to more customers in Central and Southern Ohio. Other drivers of commodity margin include higher capacity revenues, increased capacity expense and transmission cost, and lower wholesale sales.

Looking at the other drivers of fourth quarter results, higher O&M expense decreased earnings by $0.06 per share. This primarily reflects more normal operations expense in 2013 as compared to the fourth quarter of 2012, during which much of our work force was involved in storm recovery activities. Finally, lower interest expense impacted results by $0.01 per share and investment income increased earnings by $0.02 per share, mostly from higher nuclear decommissioning trust income and higher earnings from our investment in Signal Peak.

As Tony mentioned in his opening remarks, one of our key achievements in 2013 was strengthening the credit metrics and balance sheets of our operating companies. We achieved this through the successful execution of the financial plan that we outlined early in the year. I'll take a moment to walk you through the highlights of these activities.

We issued $1.5 billion in FE Corp long-term notes at a very attractive interest rate. We significantly improved credit metrics at our competitive business through a $1.5 billion equity infusion from FirstEnergy Corp, combined with $1.5 billion in debt reduction at FES and Allegheny Energy Supply. We extended the maturity of our existing credit facilities to May 2018 and increased the FirstEnergy utilities facility by $500 million.

We also strengthened the balance sheets of our utilities through our efforts to refinance debt, reduce short-term borrowings, and through securitization in Ohio. Through this series of actions, we successfully improved the balance sheet of both our competitive and regulated businesses and enhanced consolidated liquidity. We remain committed to investment grade credit metrics at each of our businesses.

Beginning in 2014, we are entering a capital intensive period with expenditures estimated at $3.3 billion this year, primarily due to the increased transmission investments. Over the next several years, we intend to fund the transmission expansion program through a combination of debt, previously announced equity issuances, through the stock investment and employee benefit plans, and cash.

While we expect our competitive operations to be cash flow positive, we intend to minimize other investments in our competitive business during this period, with the notable exception of the planned work to extend the life of our nuclear units and environmental compliance in our fossil units. We will continue to look for opportunities to further reduce our costs while preserving the flexibility to create and take advantage of opportunities to move forward with more predictable and stable growth. Now I'll ask the operator to open the line to your questions.

(Operator Instructions) Julien Dumoulin-Smith, UBS.

First, I just wanted to clarify your comments on the first quarter guidance here, if you could. Could you provide a little bit more clarity in terms of how much of the year-on-year impact is from the outages and perhaps, also, how much is impacted from the latest weather, if you will? Versus planned when you released the 2014 guidance?

Julien, in the main, if you look through the year, you've got to remember that, in part, the first quarter would not have only been affected by the Davis-Besse outage, which is scheduled for basically all of February and all of March, losing Beaver Valley was also impacting that January timeframe. The first quarter is going to be impacted by that probably more than we would have expected, but about in the same range as what we were originally anticipating.

As you think about the year, however, the growth in earnings from the segments were rising as time went on. For example, the capacity revenue in the first quarter of this year is about $27 a megawatt day or whatever that is. Starting in June, it goes to $126 per megawatt day. So there's a very large impact on capacity revenues quarter-to-quarter as you move through this time frame.

Also, when we talk about the annual guidance over the year, we need to think about the transmission investments that we're making and the earnings that arise from -- when you start those expenditures in January, they grow over time. As they're placed in service in the latter part of the year, those earnings tend to be more tail-end loaded then front-end loaded in this overall time frame.

While the first quarter expectations are probably a little lower than what people would have thought normally or just by dividing by four, they're not too far off what we would have otherwise expected.

Perhaps just to summarize, how do you think about your net exposure ultimately to the latest volatility in pricing? Was it a net benefit or a net reduction excluding the impact of the Beaver Valley outage?

Julien, we're going to go through all this stuff when we get through the first quarter timeframe. We're only through one month of the first quarter. But obviously, when you have the type of weather we had, we had more sales on both the competitive side and the utility side, in January, than we otherwise would have anticipated.

Obviously, with the extension of the Beaver Valley outage, part of which we've already talked about, earlier I think, either this year or towards the end -- earlier this year. That had an impact. Clearly, the prices were somewhat higher than we would've otherwise anticipated. But we're also seeing some PJM costs that are little higher than we would have anticipated, but we don't have the final bills on all of those things yet.

I think, at this point, the best way to look at it is that, from a Company perspective, guidance range is the same and segment ranges are the same. So how they shake out during the year and the actions we will take offsetting one way or the other will take place naturally as it always does during a year when you're dealing with multiple issues.

Great. Thank you.

Neel Mitra, Tudor, Pickering, and Holt.

When you look at super peak periods, do you typically use the FE fleet with [peakers] to serve that demand or do you usually go out into the spot market to procure some of it? Because I know that your fleet is more heavily weighted towards the baseload than the peaking generation. So just wanted to know how you handled that going forward?

Neel, this is Donnie. We rely heavily on our fleet, as you know, but we also utilize call options and purchase power, as need be. If the fleet's running flat out the way per design, we're pretty well-hedged. We don't have to rely much on the spot market.

Okay. I'm trying to understand this just a little bit better. Is the exposure that you incurred in Q1 as a result of some of your baseload plants being out and on a unplanned outage and you being forced to buy power? Or was it from the spot power that you would buy from the peaking transaction side of it?

Yes. As Leila and Tony both said, obviously, we had the Beaver Valley outage, that was off almost the entire month. In addition to that, while in aggregate for the month, our fossil fleet ran pretty well. We did have some outages at our Mansfield plant that occurred at inopportune times; specifically, when it was the very coldest weather and the prices were the very highest. Having to buy to replace for those outages was expensive.

Got it. Leila, can you outline the strategy in Pennsylvania for the rate cases with the four utilities? Are you going to file them at different times or all at one time? Or are there certain utilities where you plan not to file rate cases?

Neel, we are still looking at that. But I would imagine when we file, we would file the cases that we are going to file for this year at one point in time. But as to the particular utilities, I'm not prepared to say right now. Obviously, we would want to talk to folks in Pennsylvania and chew that up before announcing that publicly.

Okay. Thank you very much.

Dan Eggers, Credit Suisse.

I'm just trying to understand the guidance question a little bit better, so I apologize if I'm beating this to death. But if you assume normal weather for the three quarters of the year, as you would have laid out the plan when you guys devised it for the year, where would you guys fall out within the $2.45 to $2.85 range?

Dan, I think if I understand your question, you're trying to find out where we would fall between the two goalposts? The $2.45 to $2.85?

Right.

I think where we're at and as the way I see it right now, although we had some extreme weather and had some higher costs, there's other items that we've identified that would help offset that. One example would be the higher prices than we originally expected would happen in the Ohio auction. I'm pretty comfortable that we are still right in the same range that we talked about on the last call.

Okay. So you're comfortable in the middle of the range, still, so the first quarter variance was within your plan?

Yes. I'm still comfortable that we're at the same place within our range. Yes.

Okay. Leila, on New Jersey, can you just give an update on what's going on with the CTA and where the JCP&L rate case gets done with that issue still outstanding?

Okay. A lot of moving pieces and parts in Jersey. With the settlement of the storm case, we roughly, with respect to the $7.5 million that's roughly the equivalent of $1.5 million in revenue requirement, so while the settlement deals with the prudence, if you will, of those dollars, what it doesn't settle is whether the 2012 storm dollars are going to go back into the rate case.

If you recall, the BPU had indicated that 2011 storm costs would go back and so roughly, according to our approach in how you would look at those storm costs roughly, the revenue requirement roughly $23 million would go back into the base rate case. We are now briefing as to whether the 2012 storm costs should go back in. But if you think about the commissions or the BPU's original order, establishing the test year, they established a 2010 test year, but also included any out of period measurable changes that were shown to be prudent, were major in nature and consequence, and that were quantified through proof and had reliable data.

I think the 2012 storm costs fit all those categories so I think we have a very good argument to pull those storm costs back into the base rate case. Where we stand with respect to that, reply briefs have been filed. ALJ has 45 days to issue their decision if there's no extensions. Reply exceptions are generally around 30 days and the BPU may be another 30 or 60 days.

With respect to the CTA, I would've loved to have a position paper by the [staff]. Unfortunately, that did not come out prior to the briefs in the rate case. Staff took a position that was consistent with the BPU's order which said that, until we have an ultimate decision in the CTA generic proceeding, we were going to continue with what their prior position had been.

Staff's brief essentially was they were negative with respect to us and the CTA. While I still would like to see an order coming out of the commission with respect to the generic proceeding and the CTA, it is definitely on a slower path than I would have anticipated.

Is there a chance the CTA can get done before the case gets done? If it's not getting done, is there a way to slow down your case in the hopes it does get resolved? Because it's not an inconsequential issue.

You're correct. It's not an inconsequential issue. It's roughly $56 million in revenue requirements and roughly would negate about a quarter of the rate base. Just looking at it from that perspective shows the gross unfairness of applying a CTA adjustment in this case. I would hope the BPU would look at that, at the fact that JCP&L already has the lowest rates in the state of New Jersey, which, again, further exasperates the consequence of that.

But right now, we need the staff to issue an order and I haven't seen a timeline for that to happen. Ultimately, if the BPU should issue an order and should it be negative in terms of not providing for the CTA in an appropriate manner, our option would be to file another rate case and by that time of the decision in the next case, I believe we should have a resolution of the generic case.

Great. Thank you for that.

Jonathan Arnold, Deutsche Bank.

On the competitive segment, the interest expense around $35 million before capitalization in fourth quarter. Is that a reasonable run rate going forward or is there something else going in there or have we kind of found a new level with all the repositioning of the balance sheet?

Yes. I think it would generally be slightly higher than that, Jonathan. You might recall we called in one pollution control note that was about $230 million-some and we had about a $10 million favorable interest adjustment associated with that.

In 4Q and specifically in competitive?

Yes. That generally drove the $0.01 improvement in earnings that I talked about.

So the number from third quarter is probably a better level?

Yes. I would say that is correct, Jonathan.

Okay. Great. Thank you. I missed the number that you had on the hedging for 2015, if you wouldn't mind repeating that. I think I got 94 million megawatt hours in 2014 and 29 million megawatt hours in 2016.

That was in yours, Leila.

It was Leila.

Yes. We have 52 million megawatt hours in 2015, Jonathan.

Okay. Is this as of right now or is that as of the end of the year?

Yes. That's current. Right now.

Okay. You talked about being at the lower end of the glidepath and a bit positioning yourselves to take advantage of moves. But we've seen some moves, particularly, in the winter pricing in 2015 and to an extent in 2016. Can you talk at all about what you've been hedging? Are you kind of locking in any of that seasonality or just generally trying to stay as open as you can given the increased volatility we've seen in the market?

Jonathan, this is Donnie. We've not really tried to position it for seasonality up to this point. Generally, what happens is the customers are going to buy to line up with the planning year, so to speak, so it's not unusual for a customer to want to buy June through May. Or perhaps they'll buy on a calendar year, but to this point, we haven't seen much customer demand for a seasonal -- not to say that we won't be looking at that, but at this point, we have not had that opportunity.

Great. Thank you very much, guys.

Steve Fleishman, Wolfe Research.

This question might be for Leila. I think you mentioned the PJM ancillary cost that some of those get passed through to customers. Is that just in certain states and how does that work? How do we know which areas get passed through or not?

It's pursuant to contract in the specific language within the contract, so it's not a state-by-state kind of thing.

Okay. So it's certain types of your customer classes in the retail business?

It's not even the same throughout particular classes. It is as that contract language was developed for that particular customer or grouping of customers. So there's no way I can even give it to you by segment.

Okay. Okay. Some of the costs, as you get this data come up, will be costs that you absorb, but some of those you'll be able to essentially pass through your contracts to the customers?

Correct.

In the future, do most of your contracts have that clause, so new ones do but not older ones or vice versa?

I think it would be safe to say that we're going to be adding that language where we can in the future.

Got you. Okay. Thank you. Just wanted to clarify that.

Stephen Byrd, Morgan Stanley.

I wanted to just explore retail margins in the out years. Just given the kind of volatility that we're seeing, I think on some of your prepared remarks, you talked briefly maybe recognition of greater volatility being reflected in markets. But I was just curious if you could talk at a high level to, given the kind of volatility you're seeing, is that impacting how you see the margin potential on the retail side of things?

Yes. Stephen, this is Donnie. I think, especially if you look at the Ohio POLR auction and you can see that those prices are up substantially, I think that's reflective of the volatility. Obviously, as we move forward and price new contracts on the retail side, we will bake in the higher volatility so that will naturally drive the margins up, if you will.

Okay. Understood. Relating to the volatility, topic, given the kind of volatility we've seen, does that cause you to think further about the right size overall of the retail position in terms of the target gigawatt hours or are you comfortable where you are?

Stephen, I think you are always looking at where your right level of sales are and in part, it's driven by what the market provides or delivers to you. If customers are willing to pay the risk premium associated with carrying the volatility in the market, then I suspect you'll see retail sales at certain levels.

If customers are not anticipating paying that, then I would expect it would be adjusted downward because the costs don't go away from a volatility standpoint and some part of the market's going to have to carry it. At the end, it's going to be whether or not it's going to be from a customer standpoint or ultimately, at that point, whether or not a retail market for customers exits in the same format that we see it today.

That's very helpful. Thank you.

We're already seeing the impact of variable pricing on not only industrial customers, but residential and commercial customers that have chosen that path. Whether or not they stay in that environment over a long period of time is -- if volatility continues to be a issue in the market, and my own sense is that perhaps it will given the structure of it, we could see some very different forms of retail contracts.

Could you just speak, Tony, maybe a little further to those different forms of retail contracts that you're thinking of?

Like Donnie said, there could be more adjustment clauses in them. There could be more risk premiums added to fixed contract. There's a whole series of things that could be put in place to try to mitigate or address those types of differing issues.

Stephen, the list of Tony just gave, one of the things that you clearly look at is tolerance bands. What we're seeing today in the marketplace is any customer that had decided to go to an hourly kind of product, they're already calling us and wanting something different because they were obviously hit by these very high prices in the month of January.

I see. So some of your customers are seeking to reduce that risk so we'll just have to see the degree to which they're willing to pay to get that risk protection. Okay. Thank you very much.

Paul Patterson, Glenrock Associates.

Following up on Steve's question with respect to these ancillary service calls, you mentioned that there was still some settlements and settlement billing that had to come out of PJM, regarding January and February and obviously, March coming up. Any sense that we might see in terms of how much -- if there's any variation with this -- or any quantitative numbers that we might be talking about that some range in terms of exposure here?

I could tell you with respect to global PJM and ancillary services and again, these are parsed out on low ratio share, just kind of order of magnitude, for ancillary services, the billing throughout PJM for January 2014 equaled the charge for ancillary services for all of 2013.

Which is how much? Roughly speaking. If I'm putting you on the spot and you don't have it, that's okay.

$800 million.

That's PJM total, Paul.

No. I've got you. But you guys feel with your contracting and everything and your hedging that you've been able to really mitigate the exposure to this stuff? Correct? If I understood you guys correctly, right? It's all in guidance, in other words?

We are working through that process right now on a contract by contract basis and we're working with PJM to make sure that the billings that ultimately get charged to us are appropriate.

Okay. Fair enough. Finally on the Ohio alternative energy rider, that $40 million, is there any ongoing exposure other than that which you guys are going to court on? Is there any other exposure going forward that we should think about with respect to that?

No. I don't believe so.

Okay. Great. Thanks so much.

Greg Orrill, Barclays.

On Davis-Besse, I was wondering if you could talk a little bit more about the scope of the work around the unplanned concrete fixes during the current outage and the level of correspondence that's required with the NRC?

Yes. I'll try to give you as much as I can, Greg. Don't hold me as being the expert on this at this point. I've been briefed a couple of times, but we'll go through the process. We believe that what we've found is not structurally significant to the overall shield's integrity and it is fixable in the upcoming -- when we actually close the opening.

If I understand it correctly, it primarily resulted because it was left in a more temporary position with framing still in place on the backside because we knew we were going to cut it again in a year. What happened is that it didn't completely settle into all areas and so there were some gaps. We think it's fixable, fairly straightforward, inside the scope of the timeframe of this outage.

Thank you.

Paul Fremont, Jefferies.

Just a couple of points of clarification on the JCP&L case. If the 2012 costs are not included in the GRC, would they be included in whatever the NJBPU you decision is in the generic proceeding or would you have to wait for a whole new rate case to include those costs?

The answer is, it's unknown. That BPU left open the possibility of another mechanism for recovery unspecified in nature. Obviously, we would prefer something that gives us more immediate recovery, even if it's not included within the current base rate case that's in front of the BPU right now. But as kind of an outside look in to think about, if they weren't included, if things didn't go our way, we would be filing another rate case, basically on the heels of this decision, and we would get those costs included in that case.

Okay. Of the $736 million of cost that you identified, how much of that would essentially represent an increase in the rate base of the Company?

The $736 million is all rate-based.

Right. But I guess some of it is going to be recovery and O&M and I assume that's probably --

Paul, let us get that number for you. I think the rate based number's in the $400 million range.

It's $407 million in capital and $329 million in deferred.

You got that?

Sorry about the.

Okay. So essentially it's $407 million of increased rate base.

Yes. That would be the capital piece. That's right, Paul.

Okay. And you would be able to earn a full weighted average cost of capital return on that $407 million, right?

We should. Yes.

Okay. Thank you very much.

I'd like to thank everybody for joining us today. We appreciate your continued support and we remain committed to providing long-term value and sustainable growth. Goodbye now.

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