第一能源 (FE) 2014 Q2 法說會逐字稿

Greetings and welcome to the FirstEnergy Corp's second-quarter earnings call.

(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. Thank you. Please begin.

Thank you, Loretta, good afternoon. Welcome to FirstEnergy's second-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 certain expectations that are subject to risks and uncertainties. Any 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 reports of the financial community, which was released earlier today and is also available on our website under the earnings information link. Today, we will be referring to operating earnings, operating earnings per share, operating earnings per share by segment, and EBITDA, which are non-GAAP financial measures.

Reconciliations between GAAP and non-GAAP financial measures are contained in the consolidated report as well as on the investor information section on our website at www.firstenergycorp.com\ir. We also posted an updated FactBook to our website earlier today.

Participating in today's call are Tony Alexander, President and Chief Executive Officer; Leila Vespoli, Executive Vice President of Markets and Chief Legal Officer; Jim Pearson, Senior Vice President and Chief Financial Officer; Donny Schneider, President of FirstEnergy Solutions; John 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.

Thanks, Meghan. Good afternoon, everyone, and thanks for joining us. Since our last earnings call, we have made significant progress on the plans we have outlined to execute our regulated growth strategy, implement additional cost reductions, and further reduce risk in our competitive business.

We have several positive developments to discuss today, including the two rate filings in our distribution business that were announced yesterday, and a shift in our competitive sales strategy, as well as progress report on the transmission growth initiatives that are well under way. We have a lot of ground to cover today, so let's get started.

I'll begin by taking a few minutes to discuss key developments in our transmission business. As you know, our Energizing the Future transmission expansion program is designed to modernize our grid, reinforce the current system in light of expected plant deactivations, and handle load growth primarily rated to shale gas development.

This year alone, we are on course to complete $1.3 billion in investments, spanning more than 1,300 projects. These include replacing equipment with advanced technology, reinforcing substation facilities with advanced surveillance and security technologies, and rebuilding 234 miles of transmission line.

In addition to these projects, we are on track to build a new 138 kV substation near Clarksburg, West Virginia and an 18-mile connecting project to support load growth in that area. We have also completed more than one-third of the nearly 100 projects associated with plant deactivations. These include the Eastlake 4 and 5 synchronous condensers, a new 345 to 138 kV substation and 55- and 59-mile 345 line in northwest Ohio.

Currently, we have nearly 1,500 workers engaged to support the engineering, procurement and construction of these Energizing the Future initiatives. Our management processes are in place to sustain the growth targets we've previously identified, as well as our current and planned construction efforts.

On the distribution side of the business, while Leila will fill in the details, we filed applications for all of our Pennsylvania utilities, seeking an increase in annual revenues of approximately $416 million. This increase would place our average rates for distribution service in Pennsylvania, about on par with the average rates charged by other major Pennsylvania utilities.

We also filed a new electric security plan for our Ohio utilities, which we're calling Powering Ohio's Progress. The filing proposes the continuation of many of the terms of the current ESP, but also includes an economic stability program that will help protect customers from retail volatility and price increases that result from rising energy and capacity prices in future years.

This program would also help ensure the continued investment in, and operation of, significant baseload assets located primarily in Ohio. These plants provide fuel diversity as well as substantial employment, tax and economic benefits. We now have pending applications in New Jersey, West Virginia, Pennsylvania and Ohio, which is consistent with our focus on regulated operations and should better position these Companies to address the ongoing challenges of upgrading, modernizing and maintaining adequate and reliable electric service.

Let's move to a discussion about competitive markets, which we believe are clearly in transition, and how we are proactively responding by adapting our operations to create value. While we have experienced a relatively stable and predictable wholesale market for the past several years, we believe that a fundamental change in markets is under way, as available generation is being reduced due to environmental rules and competitive market to rely more heavily on natural gas and other less reliable resources.

We saw the first evidence of this last year during hotter weather in September at the beginning of the planned outage season. Then this past winter's polar vortex highlighted again the issues the markets will likely face as the fleet of assets used to provide essential electric service is fundamentally changed.

When you couple those changes with a market construct that is eroding the price stability necessary to offer retail customers predictable prices, the risk associated with serving retail loads will rise. As a result, we are taking action to better position the Company's competitive operations and generation fleet going forward. This is consistent with our expectations that wholesale energy prices generally will be more volatile and the current forwards do not fully reflect the change in market fundamentals.

While Leila will describe our competitive strategy in more detail, key actions include reducing our exposure to weather sensitive retail loads and maintaining a more open position to take advantage of market upsides and to provide our own reserve margins, since the wholesale markets can no longer be relied upon to assure reasonable pricing. We are in a good position to do this, since our current retail book naturally opens as contracts expire and is also aligned with the reduction in available capacity, as a result of environmental shutdowns.

More specifically, we intend to exit the medium commercial and industrial, or MCI, and mass market retail channels, as existing contracts expire. But we will continue to serve strategic large industrial and commercial customers, as well as our governmental aggregation and POLR channels as appropriate.

Our generation and hedging strategy, including maintaining an open position of 10 to 20 terawatt hours annually is focused on reducing overall risk in our competitive operations, while maximizing margins, EBITDA and creating value. With respect to our generating assets, we have an exceptional fleet with the size and scope that provides flexibility to adapt to current and expected market conditions and environmental mandates.

I'll take a few minutes now to discuss these issues and opportunities within our fleet. With regard to the EPA's proposal issued in June, for regulating CO2 emissions from existing electric generating units, we continue to analyze and review the proposal with particular interest in the treatment of nuclear units.

The current proposal allows only 6% of existing nuclear generation to be counted towards the reduction targets. However, I can assure you that the EPA will be receiving significant comments on this point.

We will continue to monitor new details that emerge as the regulatory process evolves, particularly with regard to how our state regulators design their implementation plans. At this point, it's too soon to say what, if any, changes would be required at our coal-fired plants.

However, we are already on track to achieve a 25% reduction below 2005 levels in CO2 emissions by 2015, as a result of the plant retirements and investments in plant efficiencies we've already made. So, how these rules ultimately are implemented and whether they are focused on CO2 emissions or driving other aspects of energy policy, will largely determine what, if anything, we will need to do.

With respect to other environmental mandates, we have negotiated with PJM, to continue operating Eastlake units 1 through 3 and Lakeshore 18, following the expiration of reliability must-run or RMR agreement in September. We will now be in a position to operate these units until April 15, 2015, when the mercury and air toxic standards rule imposes stringent emission reductions.

During the post-RMR period, these units will be at operated based on market conditions and we will be responsible for all costs and receive all revenues. Having these units available through the winter should help to provide an additional hedge against extreme weather events next year.

We have also taken yet another look at how we can reduce our costs for mass compliance. Through our performance testing, equipment assessment inspections, we have identified several additional opportunities for cost control.

We now expect our total spend for mass compliance to be approximately $370 million, which is down from our most recent estimate of $465 million. The spending is about evenly split between competitive and regulated units.

Turning to other generation matters, the PJM capacity auction for 2017-2018, which was held in May, produced stronger results than last year. However, the prices were still not where they need to be to sufficiently support the type of generation resources needed to assure reliable and diverse supply or a central electric service.

More specifically as to our Company, our 2,400 megawatt Bruce Mansfield plant, which is the largest supercritical baseload coal-fired plant in Pennsylvania, is fully equipped with scrubbers, SCRs and cooling towers and is critical to providing reliable electric service in ATSI, did not clear in the most recent auction and only partially cleared in last year's auction. As a result, while we will continue to operate and maintain the Mansfield plant, we have decided to minimize capital expenditures at this site until we get the results from the incremental auction in September of this year, and perhaps, until after the PJM auction in 2015 for the 2018/2019 period.

It will take approximately two years to complete the new water treatment upgrades that are necessary for continued operation after the Little Blue Run coal ash facility closes on December 31, 2016. If market conditions are unfavorable, we are prepared to delay these projects, pushing out the timing of the capital expenditures and possibly impacting the nature and timing of the outage.

We will continue to provide updates on Mansfield. However, at this point, our current assumptions include the cost associated with the incremental upgrades in the 2015 to 2017 period of approximately $200 million.

If the project is delayed, these costs will move to later periods. I'd note that we do not anticipate a material impact on EBITDA as a result of these potential actions.

Finally, at Beaver Valley, we are moving the unit 2 reactor head and steam generator replacement outage to 2020, from 2017. This change, which will not impact the safe operation of the plant, is possible given the condition of the facility. Our actions with respect to MAT spending and delaying capital spending at Beaver Valley are a continuation of our cost control measures.

The total capital savings from the MAT spending reduction, the deferral at Beaver Valley and other fleet-wide capital reductions is approximately $425 million over the next several years. We believe these actions will not only put us in a position to be cash-flow positive at our competitive business during the 2015 through 2018 periods, but also put our competitive business in a much stronger position to face current market conditions.

This morning, we reaffirmed our full-year 2014 operating earnings guidance of $2.40 to $2.60 per share, reflecting our expectations for the remainder of the year. We also provided incremental disclosures for our competitive operations in our FactBook, including the amount of capacity clearing in the annual PJM auctions, as well as other details to support your efforts to model this part of our business. We anticipate that this additional transparency will support proper valuation of our competitive operations going forward.

Finally, on the topic of proper valuations, we recognize that the market is deciding a discount that is likely due to a number of factors, some of which are within our control and some not. As we begin to get more clarity on external drivers such as the ongoing rate case in New Jersey, for example, and communicate our strategy as we transform the Company, we anticipate this will provide better visibility into our growth prospects for the future, particularly those related to our regulated utility and transmission operations. Thank you for your support and I'll turn the call over to Leila.

Thanks, Tony, and good afternoon, everyone. Let's start with a deeper dive into our competitive generation strategy. The strategy we are laying out today is straightforward. We will pursue the effect of hedging of the majority of our generation resources with reduced risk at the highest possible margins possible, while leaving a portion of generation available to capture market opportunities.

We have already taken action to mitigate risk and create length in our portfolio by purchasing additional power and options during peak periods, as well as by buying outage insurance this summer, all of which we spoke about at our last earnings call. Since then, we have allowed some attrition of our customer base and returned selective customers to POLR service.

Going forward, we intend to serve all existing customers through their contract term. But as Tony outlined, we will eliminate our selling and renewal efforts in MCI and mass-market channels, and to certain LCI customers.

We plan to maintain our sales efforts and government aggregation, primarily in Ohio through a POLR load, and focus on selective, strategic sales to LCI customers. Looking at each of those channels, we intend to continue sales to government aggregation communities, primarily when contract prices move with the market as a percent off the price to compare. These sales also have relatively low acquisition costs and margins are generally attractive.

With the POLR channel, we have virtually no acquisition costs. We have the flexibility to make decisions at the time of each option as to the value of the load.

We also plan to continue selling to strategic large commercial and industrial customers, where we have a significant relationship, or where the customer has a very high load factor that is not weather-sensitive. Basically, these customers represent a wholesale type load that include a modest retail margin.

This menu of options provides us with considerable flexibility as we look to establish our hedging strategy. And we are in a strong position, given the hedges we already have in place, for both 2015 and 2016, with about 54 terawatt hours and 28 terawatt hours committed, respectively.

These include our currently-committed direct LCI, MCI and mass market sales book, which tapers off through 2018, but with a significant drop starting in mid-2015. As well as the POLR and government aggregation sale, a portion of which extends through 2019.

We expect that our level of sales to large commercial and industrial customers, POLR and government aggregation, would sell in at about 10 to 45 terawatt hours annually. Given our current commitment, we expect to be in that range beginning in June 2015 and for the subsequent 12-month period.

In addition, we expect to use wholesale sales to hedge our generation and potentially utility purchase power agreement. We view all these options as a hedging tool chest with considerable flexibility to adjust as market conditions dictate.

The charges associated with our decision to exit certain channels were $0.07 per share in the second quarter, with expected ongoing savings of about $90 million annually. Going forward, we may cover a portion of our sales commitments with purchased power in various amounts, based on the season, operational plan and other considerations in amounts to be determined as appropriate. But, we expect purchase power to be minimal going forward.

Our competitive generation fleet can generally produce between 75 and 80 terawatt hours per year, with up to 5 terawatt hours of additional generation available from wind, solar and our OVEC entitlement. Our updated EBITDA estimate for 2015 is in the range of $900 million to $1 billion, and assumes the market-forward power prices of just under $40 a megawatt hours as of mid July.

In our FactBook, which is available on our website, you will see that we have split our closed and open position, which will enable updating the open position at a mark-to-market basis going forward each quarter. In addition, we are also providing sensitivities with a $1 a megawatt change in market prices, changing 2015 EBITDA by roughly $28 million.

I'd also like to note that we expect to provide at least 2016 EBITDA guidance at the annually EEI conference, in order to provide longer-term transparency with respect to our competitive operation. As we transform our competitive operations, we will focus on leveraging market opportunities as they present themselves, with a diligent focus on risk management.

As you can see, our FES team has done a great deal of work over the past quarter to reevaluate sales targets and identify opportunities for cost control. So that we can best position our competitive business going forward.

At the same time, our regulatory team has also had a productive quarter. I'll switch gears now to provide an update on current regulatory issues and the filings we made yesterday.

Our Ohio ESP filing will provide electric service to our utility customers for a three-year term from June 1, 2016 through May 31, 2019. We have named this plan Powering Ohio's Progress, as it provides numerous methods that support reliable electric service, help safeguard customers from volatility and retail price increases and encourages growth and development of the state's economy.

A highlight of the plan is the economic stability program, which provides for a rider to cover the costs associated with the proposed purchase power agreement between Ohio utilities and FirstEnergy Solutions. The proposed PPA would dedicate the output of Davis-Besse, Sammis and a portion of OVEC for approximately 3,200 megawatts, or an average of approximately 23 terawatt hours annually, beginning in June, 2016 and running through May, 2031.

As designed, the utilities would sell this power into the market and net any revenues associated with these plants against costs, thereby serving as a type of rate stabilization mechanism, protecting against volatility and retail price increases. Importantly, the economic stability program will not impact the Ohio utilities competitive bid process and retail customers will still be able to choose an alternative retail supplier for power supply.

Under Powering Ohio's Progress, base distribution rates would remain frozen throughout the term. A typical residential customer using 750 kilowatt hours of electricity per month could expect to pay an average of $3.50 more per month during the first full year of the economic stability program. As I've described, customers would receive a credit on their electric bill if market revenues exceed costs as projected over time.

The current ESP is widely considered a success in terms of its ability to produce competitively-priced electricity for customers, to remain with our utilities for generation source, as well as to create a level playing field among suppliers competing to serve retail customers who choose to shop. It was broadly supported by diverse groups representing various customers and other interested parties.

Powering Ohio's Progress builds on that successful platform. It will not change the amount of power procured through the auction process or otherwise detract from the competitive retail markets in our region. Our Ohio utilities would continue to utilize competitively-bid auctions to procure generation supply for our customers who don't choose an alternative retail supplier.

In addition, Powering Ohio's Progress delivers significant benefits to the State of Ohio by retaining local jobs, protecting local tax revenue, and promoting economic development. It benefits Ohio utility customers through the safeguards from volatility and potential retail price increases. It benefits FES by providing a cost-based source of revenue for approximately 25% of its generation output.

We have requested a decision respecting our plan by April 8, 2015, which we believe is adequate time for all interested parties to evaluate the proposal. This timeline also fits with our competitive generation hedging strategy, in that it provides adequate time to redirect these megawatt hours to other available hedging opportunities, should Ohio decline this opportunity, and provides adequate time for the POLR auction for supplies starting June 1, 2016.

In Pennsylvania, our four operating Companies are seeking to increase base rates to ensure continued service reliability improvements for the 2 million customers they serve. Our Pennsylvania utilities have maintained stable rates for many years through strict cost control measures and careful planning. The last base distribution rate increase for all four Companies was more than 20 years ago.

If the proposed rate plans are adopted, customers will benefit directly through continued service reliability enhancement through the local distribution networks that deliver electricity to homes and businesses in our communities. These enhancements build on our Energizing the Future transmission initiative, which includes support for smart technologies and can help reduce frequency and duration of power outages.

The filing requests approval to increase operating revenues by approximately $152 million in net Met Ed, $120 million at Penelec, $28 million at Penn Power, and $116 million at West Penn Power based upon fully projected test years for the 12 months ended April 30, 2015. As a result, the rate case request would increase average monthly customer bills by approximately 11.5% at Met-Ed, 8.6% at Penelec, 8.7% at Penn Power and 8.4% at West Penn Power, which in all cases is substantially below the rate of inflation since the last case for each Company.

We expect a decision on the Pennsylvania rate cases in the April 2015 timeframe. We have provided more detailed summaries of both our Ohio and Pennsylvania filings in a letter to the investment community we issued yesterday after market close.

With respect to other regulatory activity, in New Jersey the administrative law judge closed the record on our base rate case as of June 30. And we expect his recommendation later this quarter, and anticipate DPU action on our case in the fall.

In Pennsylvania, on June 5, the PUC approved the amended smart meter deployment plan for our Pennsylvania Companies, allowing us to move forward with building the entire Penn Power smart meter system of 170,000 meters by the end of next year. We began installation last month.

Finally, on May 23, the US Court of Appeals for the District of Columbia ruled that FERC's requirement that RTOs pay LMP to demand response that participates in wholesale energy markets encroaches on the state's exclusive jurisdiction to regulate retail markets. The court's decision was based on its finding that demand response is a retail product and therefore FERC does not have jurisdiction to regulate it in wholesale energy markets. The court's action in the case takes an important step toward allowing wholesale energy markets to begin functioning properly.

On the same day as the court's decision, and before the May 2014 capacity auction results were announced, we filed a complaint at FERC, citing the court's decision, asking FERC to pull demand response resources out of the May 2014 PJM capacity auction. The PJM capacity auction is a wholesale market, so the inclusion of demand response resources is inappropriate in light of the court's decision.

Eliminating demand response as a compensated capacity resource would provide much-needed uplift for essential physical generation and better allow the PJM capacity auction to work as originally intended. In fact, in an analysis published last month, the PJM Market Monitor found that removing demand response from the May 2014 capacity auction would increase the clearing price in RTO from $120 hours a megawatt day to $282 a megawatt day.

I would like to thank you for your time. Clearly it has been a very active and constructive quarter on both the competitive and regulatory fronts. We will continue working to position our competitive business for the future, while ensuring the best possible regulatory environment for our Company. Now I'll turn the call over to Jim for a review of the quarter.

Thanks, Leila. As I discuss our financial results, it may be helpful for you to refer to the consolidated report which was issued this morning and is available on our website.

Our second quarter operating earnings of $0.49 per share were in line with our expectations. These results compare to second-quarter 2013 operating earnings of $0.59 per share.

While I will walk through the drivers for each of our business units in a minute, the major drivers included lower commodity margin at our competitive business and higher operating expense in our distribution business. Primarily due to increased maintenance and vegetation management cost.

On a GAAP basis, second-quarter earnings were $0.16 per basic share, compared to a loss of $0.39 per basic share in the second quarter of 2013. The special items that make up the $0.33 difference between GAAP and operating earnings can be found on page 2 of the consolidated report.

Let's turn to a review of the key drivers of operating earnings across each of our business segments, starting with distribution. During the second quarter, operating earnings for our distribution business with $0.39 per share, which compares to $0.45 per share in the second quarter of 2013.

The decrease is largely due to our enhanced focus on maintenance and vegetation management work in the second quarter of this year. These activities, together with a 56-day outage at Fort Martin unit 1 resulted in a $0.05 per share increase in operating expenses compared to the same period in 2013.

Distribution operating earnings were also impacted by higher depreciation, pension expense and interest expense, compared to the second quarter of 2013. The Harrison/Pleasants asset transfer increased earnings by $0.01 per share and a lower effective tax rate resulting from changes in state apportionment factors increased earnings by $0.02 per share.

Looking now distribution deliveries. While operating earnings associated with deliveries were flat, the overall trend remains positive, particularly regarding the continued steady improvement in our commercial and industrial sectors. Total distribution deliveries increased by 175,000 megawatt hours, or less than 1% compared to the second quarter of 2013.

Now looking at the mix of sales, mile temperatures resulted in a 2% decrease in deliveries to residential customers. Heating degree days were 6% lower than 2013 and 10% below normal, while cooling degree days were 7% below 2013 and 3% above normal. Adjusted for the impact of weather, residential sales decreased about 1%.

Sales to commercial customers increased 1% overall, and were up nearly 2% on a weather-adjusted basis. Sales to industrial customers were 2% higher than the second quarter of 2013, driven again, by shale activity as well as increased production from the steel and automotive sectors.

As we have discussed over the past several quarters, the overall trends, particularly for commercial and industrial deliveries, remains solid. In fact, over the past 12 months, while weather-adjusted residential sales have been essentially flat, commercial deliveries have increased 2% and sales to industrial customers are up nearly 3%, reflecting four consecutive quarterly increases in each of those segments.

The industrial pipeline remains promising, particularly with respect to shale-related activity. We remain cautiously optimistic that growth in this sector will continue to accelerate over the next several years.

Moving now to our transmission business. Operating earnings were $0.15 per share, which is a 25% increase compared to $0.12 per share in the second quarter of 2013. The increase was driven by higher transmission revenues resulting from revenue requirement increases at ATSI and TrAILCo, following their annual rate filings that were effective in June as well as higher capitalized financing cost.

Let's now turn to our competitive business. Operating earnings were $0.03 per share for the quarter, which compares to $0.11 per share in the second quarter of 2013. Operating earnings were impacted by lower commodity margin, higher investment income and lower operating and maintenance cost.

Commodity margin decreased operating earnings by $0.14 per share, driven primarily by lower energy prices at the time the sales were committed and lower contact and wholesale sales volumes. While unit prices benefited from higher capacity rates, they also reflect the adverse impact of generally lower energy prices.

You will recall that market power prices fell significantly beginning in the fourth quarter of 2011. Prior to the drop in prices, our 2014 sales book was 30% committed, while 2013 committed sales were 60% committed. Therefore, more of our 2014 sales were committed at lower energy prices as compared to 2013.

Our overall retail customer count decreased by 100,000 to 2.6 million since June 30, 2013 and total channel sales decreased 1.6 million megawatt hours, or 6%. We were already taking steps to be more selective in our sales to large- and medium-sized commercial and industrial customers during the second quarter, and this strategy resulted in a 16% decrease in those channels compared to the same period in 2013. Our total customer count in the LCI, MCI and mass-market channels will continue to decrease as we implement the strategy Leila and Tony discussed earlier.

Total generating output from ongoing units decreased 1 million megawatt hours. This was driven by outages and de-rates at our supercritical coal units during the quarter, which offset higher generation at our nuclear fleet, primarily due to fewer forced outage days compared to the second quarter of 2013.

Fuel and purchased power costs were lower in the quarter and commodity margin also benefited from higher PJM capacity revenues, net financial sales and purchases and lower MISO and PJM transmission expense. Additionally, O&M costs increased earnings by $0.03 per share, primarily related to lower retail and marketing-related expenses, partially offset by higher outage costs at our nuclear and fossil plants.

Overall, we remain pleased with the continued solid performance of our transmission and distribution businesses during the second quarter and first half of the year. We believe the strategies we have put in place in all three of our businesses will lead to strong, stable returns going forward.

As always, we will continue focus on our core businesses with the commitment to operational excellence, financial discipline and predictable and sustainable growth opportunities. Now, I will open up the call to your questions.

(Operator Instructions)

Jonathan Arnold, Deutsche Bank.

On the transition of the portfolio, the retail portfolio, can you give us a sense of how quickly you think you will arrive at the optimal shape? Obviously, the sales ratchet down, but you're saying you want to basically be out of MCI and mass-market. When does FirstEnergy, new FirstEnergy retail book, when do we see that first?

Jonathan, this is Donny. You probably haven't had a chance to look at the FactBook yet, but when you get a chance, if you look at slide 102, it will show you by channel, as those sales term out.

Okay. There is a slide in there. I haven't seen that, you're right. There's a slide in their which will answer my question?

Yes. It's a good slide. It will show channel by channel, so you will be able to see the MCI, the LCI, et cetera. Generally speaking, we'll probably had our target volumes about first quarter or second quarter of 2016.

Okay. Is it correct that you, given what you've said, that going into this coming winter, that you are still probably short in the same manner you were going into last winter, but you've purchased protection? Do I understand that correctly?

No, not at all, Jonathan. Again, I apologize that you haven't had a chance to look at the FactBook, but you'll see a real good slide on slide 101 that shows our length. We're actually about 500 megawatts long going into the winter, and that excludes our peaking capacity.

So, the simple cycle CTs and the oil CTs would lay on top of the 500 that we're already long. So we are in pretty good shape for the winter.

I see. That's a monthly look rather than an aggregate annual look.

Yes. That's month by month and it reflects any outages or whatnot that are planned.

Very helpful. On a slightly different topic, I think I heard the number correctly, that you thought you would have in aggregate, $425 million capital savings over the next several years?

Yes. That's basically 2015 through 2018.

Okay. Is that savings, the money you're just not going to spend because you found ways not to spend it? Or is some of it savings, some of it deferral?

Some of it, obviously, is deferral. Especially, that related to the Beaver Valley steam generator and replacement project. That will move into probably a little in 2018, more in 2019 and 2020, when the project is fully undertaken.

The MATS savings are, in fact, real. They're not moved around. Much of it depends on what the nature of the other capital investments are. Some will be, as you call them, permanent. Some will be moved, depending on when outages are scheduled.

How would the $425 million break down between permanent and deferrals? Roughly.

One of the largest portions of the $425 million would be the Beaver Valley movement. I think that was about $270 million of the $425 million.

Great. Thank you, Tony. If I could, just one final thing. Did I hear you right? You said you were expected to give at least 2016 EBITDA guidance at EEI? Is the implication of that you might go out further?

I think that's the only way you can think about it.

I just want to make sure I heard that right.

I'm trying to give you at least 2016.

Okay. Can you give us any sense, at all, of what -- I think you talked about what the implication for a residential customer would be of the ESP of $3.54 a month, which, I guess, one could calculate a net revenue uplift. Then, there's obviously commercial and industrial, as well. How does the ESP change your look? Can you give us any aggregate sense of that?

I do not have that readily handy. It would be up kilowatt-hour charge, so over an average customer's usage. I can get that, but I don't have that readily handy. No, I'm sorry, Jonathan.

All right. Sorry for too many questions.

Paul Fremont, Jefferies.

I was hoping that we could get you to elaborate a little bit on the sale of the generation from FES to the regulated Companies. For instance, when we think about the revenue requirement, should we tie that to a book value number for those assets? What would be the book value?

The way to think about it, if you go back in time, a regulated rate of return on rate base and O&M. So, how one would have traditionally done it in Ohio. That, then, is compared to what the market produces. The net difference is either a credit or charge to customers. That information is contained in the filing, although, I believe under confidentiality.

Do have a book value number for those megawatts?

No. Again, if you think about it in terms of evidence in the case, it is evidenced in the case, but it is under a confidentiality agreement.

Okay. In terms of the customers that are opting for this, do you need enough customers to sign up for all of the generation output of these units, in order for all of this to qualify? Or would this amount of generation be dedicated irrespective of the customer sign-up?

Okay. It is a non-bypassable charge. If you think of it, what's actually happening is the FES side of the house is selling all the output from these three plants to the utilities. The utilities are taking the output and selling it into the marketplace.

They are paying the competitive side of the house, the cost base, the traditional rate base kind of return. And they are taking the money they get from the marketplace, again, netting it against what they pay FES side of the house. It would either be a charge or credit to customers.

The power itself is not actually going to serve customers directly. It is acting as a rate-stabilization mechanism. Over the 15-year term, it is predicted to produce savings for customers, $2 billion, or $800 million net present value.

Over the term, 15-year term, it will be a huge savings to customers. If you think about it from a competitive standpoint, to something in Ohio, Ohio looks to be a competitive state. It does not at all harm competition in Ohio, because the Ohio POLR auctions will go forward just as they had in the past.

They will procure exactly the same amount of power and suppliers can compete for customers in the same exact way they've competed for them in the past. Again, I don't believe it is going to affect competition or ability of suppliers to compete, either retail or at the wholesale POLR level. But it is giving customers $2 billion and stability going forward.

Can you remind us who are the key parties that you would look to, if you were to try and settle in Ohio? Who are the key parties that you would need in a settlement?

In the past, we have been very successful in getting quite diverse support around our settlements. Industrial customers are generally the most knowledgeable about markets and have been the ones in the past who have been interested in this kind of thing. So, we'd be looking to them.

Staff, in the past, had something -- I wouldn't say it's entirely similar to what we were putting on the table, with respect to AEP. I think is very significant differences. What we have in our Powering Ohio's Progress and in particular the economic stability program that is very different from that which is in the AEP case.

For one thing, the Powering Ohio's Progress deals with the economic vitality of the state. The jobs, the taxes in Ohio, these were plants originally built to serve Ohio customers.

If market revenues didn't prove to be sufficient to keep these plants around, the transmission that would be needed to compensate for that would, essentially, be allocated to the active load. So, it's something that needs to be thought of in terms of the overall dynamic.

So, I think -- while I mentioned the staff and they might have had some concerns about remotely similar kind of agreement in the past, I think we bring something different here. I would look to them as a settling party.

Retail suppliers and other entities, and again, since I don't believe this affects some, I would be hopeful we could positive discussion with them. Obviously, the Office of Consumers Council.

Okay. My last question is, can you update us on the status of the nuclear sale and lease-backs? Are you including in your capital requirements, a potential buyout of the nuclear leases when they come due?

Paul, this is Jim. We've reached agreement with a majority of our lessors. I think we only have 50 megawatts that we have not reached an agreement on.

We have bought back a significant portion of that already. So I think we have only about 150 megawatts left to repurchase.

So, we do have some anticipated capital outflow in the 2016-2017 timeframe for those outstanding megawatts.

Back thank you very much.

Hugh Wynne, Sanford Bernstein.

I was wondering if you might take us through the drop in guidance for GAAP earnings? And the increase in excluded items from the operating earnings.

Hugh, this is Jim. For our GAAP earnings, it changed by about $0.34. It was made up of first plant deactivation, that was $0.12. That mostly is a contract termination, a fuel contract termination.

Our retail repositioning, that's about $0.11, which you saw some of that already incurred this quarter. $0.10 on mark-to-market, which is just those positions expiring at this point. And then we had $0.01 for trust impairment. So, that's what made up the change in our GAAP earnings of $0.34.

Could you explain perhaps, the plant activation. I didn't quite catch that. You had a fuel contract that terminated and that caused you to deactivate a plant?

No, I'm sorry. That was just the termination of a fuel contract. It kind of relates to not needing as much of our fuel that we had under contract.

Understood, because of prior deactivations, you no longer needed the supply.

That's correct.

Right, okay. I also would like, if you wouldn't mind, just a quick clarification of the comments around the Mansfield plant. I got a little bit confused there. I understood that the plant will continue to operate, but, that you will minimize CapEx.

And in particular, you're going to defer a water treatment upgrade. But, it's not one of these do or die CapEx projects that would be required for continued operation. Or, did I get that wrong?

Hugh, this is Tony. Let me walk you through that. With respect to Mansfield, we are going to continue making the MATS spend that's required for continued operation of that plant. That's part of the game plan.

At Mansfield, however, Mansfield needs a new water treatment facility. It's about a $200 million facility. It will take about two years to construct that.

Because the Mansfield ash disposal site closes on December 31, 2016, essentially, that construction project must start no later than January 1 of 2015, in order to assure us that we'll have it available for continued operation of the plant beyond January 1 of 2017. So, if we delay that expenditure, it will require us to time differently how we take the Mansfield unit down and when we take it down, to accomplish what needs to be done from a water treatment standpoint.

Okay. But you would still be able to operate --

Did that help you?

Yes, I believe it does.

We can not operate after December 31, 2016.

Can not operate without the --

We can not operate without the water treatment facilities.

Got it, great. Thank you very much. That's it.

Paul Patterson, Glenrock Associates.

Really quickly on the hedged change. It sounds like there was a $90 million benefit that you guys saw annually from that. Could you elaborate a little bit more about what that is? Is that income? Did I get it right?

Paul, yes, you got that right. That would be income.

Is that pretax, or after-tax?

Those are expenses. What we're really looking at, Paul, that would be reductions in agents' fees, personnel, overall operating costs, because you are not running a retail operation any longer to the same extent that we are today.

When would that start to show up?

Probably in the latter part of this year, as we wind down the operations. It will smooth out over time. We'll see some of it this year, most of it next year.

Is there any decrease in margin because you guys are taking less risk? It looks like you're derisking the hedging. Is that correct? Is there any other offset that we should think about that? I will follow-up you guys afterwards.

The second one that I really have for you guys is, as you know, there is this thing called the Edgar Principal, when we have to deal with affiliated transactions. I know you guys know a lot more about it than I do.

Does it apply to you, do think, in this case, in the Power Ohio case? If not, why not? If so, how do you solve for it?

We have market based rate authority and we believe that the PPA is covered under that.

But, as a result, its long-term contract would be seen as a market transaction? Is that what you mean? I'm sorry.

That is correct. We would not need to be filing at FERC, so we would not have that review process occur.

Okay. FERC would not be reviewing this under Edgar?

Right.

Okay. Finally, there was $140 million decrease in FFO, it seems, for 2014. We saw a decrease in the first quarter, as well. Any trend there? Or, is that just noise, or what have you?

Paul, this is Jim. That decrease in FFO, that was attributable to that fuel supply contract I talked about, that we terminated. The other portion was associated with the expenditures for our retail repositioning.

Okay. Thanks so much.

Operator, we'll take one more question.

Gregg Orrill, Barclays.

Thank you for all the information. On slide 106, --

Okay, Gregg. (laughter) Now, we will all be flipping pages there.

Within the hedged EBITDA, the capacity expense is $150 million higher than the revenue. How much of that is offset in 2016, if it's possible to say?

Greg, this is Donny. I think the best way to think about capacity revenue and capacity expense as its laid out here, is you really have to think about them as completely separate transactions, almost. The capacity revenue that we get is a result of bidding our units into the be BRAs and into the incremental options.

We would get that capacity revenue regardless of what we're doing on the retail side. The capacity expense, on the other hand, is tied directly to what we do on the retail side. The revenue that offsets that capacity expense is built into our retail rates.

Thank you.

Okay, Greg, thank you. I'd like to thank everyone for joining us on the call today. If we didn't get to you in Q&A, please call our IR department and we'd be happy to get back with you.

As you heard today, we're making substantial progress towards our long-term regulated growth strategy. In our transmission business, our Energizing the Future transmission investment initiative is well under way and we are on track to complete the investments we have identified this year, while laying the groundwork for future construction efforts.

In our distribution business, we now have active rate cases in four states, including our proposed plan in Ohio that would help protect customers in the state from potential market volatility and retail price increases. At the same time, in our competitive business, we are taking further steps designed to reduce overall risk, while retaining the flexibility to capture future market opportunities. We intend to continue to reduce our overall cost structure over the next several years.

We believe the positive developments we discussed today, together with our strong commitment to success, will help us provide long-term value and predictable, sustainable growth to our investors. Again, we appreciate your continued support. Thanks for joining in today.

Thanks, everyone.

Thank you.

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