第一能源 (FE) 2013 Q2 法說會逐字稿

Greetings and welcome to the FirstEnergy Corp. second-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, Investor Relations for FirstEnergy Corp. Thank you, ma'am, you may begin.

Thank you, Brenda. 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 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 release link. Reconciliations to GAAP for the non-GAAP earnings measures we will be referring to today are also contained in that report, as well as on Investor Information section on our website at www.FirstEnergyCorp.com\IR.

Participating in today's call are Tony Alexander, President and Chief Executive Officer; Jim Pearson, Senior Vice President and Chief Financial Officer; Donnie 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.

Good afternoon, everyone. I'm glad you are with us. Today, Jim and I will provide an overview of second-quarter results, an update on operational and regulatory developments, and a review of the progress we are making on the financial plan we outlined earlier this year. I will also take this opportunity to clarify several topics that seem to be on our investors' minds which I believe have put undue pressure on our recent stock price.

We will begin with a look at our financial results. Today we announced solid second-quarter non-GAAP earnings of $0.59 per share. These results are in line with our expectations and we are also reaffirming our 2013 non-GAAP earnings guidance range of $2.85 to $3.15 per share.

While I am pleased with our second-quarter performance and our outlook for the remainder of the year, the PJM capacity auction results for the 2016 to 2017 period were disappointing. As in the past, we are not disclosing the number of megawatts from our competitive business that clears the auction. However, as has been the case in other recent auctions, not all of our generating units cleared.

Respecting the PJM auction, I believe that there are significant and fundamental flaws in the process. These flaws will not only impede investments in competitive generation resources and the development of a robust competitive market, but will also ultimately impact reliability. We will continue to work with PJM and others to address these flaws, and in some cases, loopholes that encourage gaming the system.

In the meantime, however, and in the wake of these auction results, we are taking additional aggressive steps to further reduce our costs and improve operational performance. We have thoroughly evaluated the economics of each of our plants as a result of the auction and current and future environmental regulations, most significantly the Mercury and Air Toxics Standards, or MATS.

As you may recall, in 2012, shortly after MATS rules were finalized, we announced plans to deactivate units at nine of our older coal-fired generating facilities. As a result of our recent analysis, we announced plans to further trim our fleet and deactivate two additional power plants by early October. These are the 370 megawatt Mitchell powerstation in Courtney, Pennsylvania, and the Hatfield's Ferry powerstation in Masontown, Pennsylvania, which is a 1710 megawatt facility. These deactivations are subject to PJM review for any reliability impacts.

The Hatfield's station is a large supercritical and scrub facility, and while the Mitchell station is older, it is equipped with scrubbers. However, neither of these plants cleared in the 2016/2017 capacity auction and some of the individual units also did not clear in the three prior auctions.

Our analysis, among other things, considered that together Hatfield and Mitchell represent approximately 10% of our total generating capacity with about 30% of our estimated cost to comply with MATS regulations. As a result of these closures, our MATS compliance costs are expected to decrease from around $925 million to approximately $650 million. And we continue to look for ways to refine and perhaps further reduce our expected MATS compliance costs.

The total reduction in capital over five years at these facilities, including $275 million for MATS, is approximately $500 million. From an earnings perspective, the closure of these facilities will be accretive by several cents annually going forward.

In addition to these decisions, we have also canceled or delayed certain investments in other generating facilities which are expected to further reduce the capital needs in our competitive generation fleet by about $375 million over that same period. In total, this $875 million reduction in capital over the next several years is a vital component of our overall effort to manage cash effectively during this timeframe.

We have also identified and are implementing additional cost opportunities across our organization. These actions include reductions to medical and other benefits and additional organizational changes, including a reduction in staffing and corporate support and the elimination of certain open positions throughout the organization. Combined, these actions are expected to reduce costs by a total of $150 million to $200 million annually beginning in 2014, with some impact in 2013 as the changes are implemented.

These savings will run through both expenses and capital and we will have a better sense for the allocation as the savings are implemented. We also announced that we will be moving to a cash balance pension plan for employees hired on or after January 1, 2014. While this will not impact current pension obligations, it should change our pension responsibilities over time.

While many of the changes in our operations will have an impact on our competitive business, they do not change our strategy. We have had and plan to continue our asset-backed retail sales strategy in which our objective is to sell up to 25% more than we can produce. This allows us to increase the utilization of our generating fleet throughout the year and take greater advantage of retail sales during otherwise low load periods.

Since our competitive production capability, however, is expected to be lower as a result of the plant retirements and perhaps further reduced the Harrison and hydro transactions, we would expect that our future retail sales targets, consistent with our strategy, would also be less. Even so, from an actual sales standpoint, our total retail sales may only be slightly less than current levels. And more importantly, given our current book of business, we are in a position to be far more selective in our channel and customer activity.

Our strategy is about both volume and margin. For example, we have already booked more than 75 million megawatt hours of channel sales for 2014 at prices above this year's and through the remainder of this year we anticipate locking in additional direct and POLR sales as auctions are conducted. We are also seeing improved margin in our recent contracts and overall margin improvement by not pursuing renewal of some customer load.

So while the reduction in our competitive generation fleet will impact our production capability, we do not expect it to have an appreciable effect on our retail sales plans. I remain confident in our strategy and in the manner in which we are executing to deliver higher value to our shareholders.

Let me now move to a brief regulatory update as Leila is unavailable to join us today.

First, respecting the Harrison proceedings in West Virginia, we received FERC approvals for the proposed financing and transfers related to the transaction and the West Virginia Public Service Commission hearings from the asset transfer were completed in late May. Briefs and reply briefs were filed by the parties in July, and with the conclusion of the regulatory proceeding, the commission may issue an order at any time.

We are, however, currently in active settlement discussions with all parties in this case and we are very hopeful that we can reach a resolution through this process. I continue to believe that this transaction provides positive benefits to our Mon Power customers and the state of West Virginia, and over time it will help maintain our rates in West Virginia at levels that are some of the lowest in the region.

Regarding the New Jersey generic proceedings on major storm costs, on May 31 Florida public utilities clarified that the prudence of the 2011 major storm costs would be reviewed in the generic proceeding with the goal of maintaining the schedule established for the base rate case where recovery of such costs would be addressed. The Board further indicated that it would review the prudence of our 2012 major storm costs in the generic proceeding and recovery of such costs would be considered through a phase two in the existing base rate case or through another appropriate method to be determined at the conclusion of the generic proceeding. On June 21, we filed a detailed report of 2011 and 2012 major storm costs in this docket.

In the pending JCP&L base rate case, we will file rebuttal testimony this week refuting the testimony put forth by the rate counsel and other interveners. Hearings on the base rate case are scheduled for mid-September through mid-November. We expect resolution in that case by the first or second quarter of 2014.

It is important to note, however, that JCP&L has the lowest distribution rates in New Jersey and in some cases by a significant margin, despite having one of the more difficult areas to serve since it is exposed to some of the greatest tree density in the state as well as 74 miles of coastline.

Now turning to Ohio. In Ohio, as we mentioned during our last earnings call, the state senate introduced legislation, Senate Bill 58, aimed at amending the current energy efficiency law that was originally passed in 2008 under Senate Bill 221. In June, the Senate Public Utilities Committee conducted a series of public hearings to determine whether these costly mandates are serving Ohio's best interests and to gather stakeholder input on what changes are necessary.

We were very pleased to see Ohio business owners personally attend these hearings to express their concerns with the current law. We expect that Senate Bill 58 will be revisited when the House and Senate reconvene in the fall. In the meantime, we remain actively involved in this process with Ohio's other electric utilities and other key stakeholders to determine what measures will most effectively reduce the cost burden of these standards in future years.

Also in Ohio, the PUCO scheduled a series of workshops throughout the remainder of this year as part of a retail market investigation that the commission launched late last year. FirstEnergy is fully participating in these workshops and we are sharing our thoughts on ways to create additional opportunities for suppliers to effectively compete.

We have a lot on our regulatory plate, but with 10 operating utilities in five states it will probably not be unusual. We have good regulatory relations and we are working with capable commissions to address all of these matters and other matters that will arise over time.

Now let's turn to our 2013 financing plan. While Jim will provide additional details on our overall plan, I wanted to note that we continue to make significant progress. We recently became the first utility in Ohio to successfully take advantage of the new securitization act, which allowed us to redeem certain debt at our Ohio utilities. We also announced additional early debt redemptions at our Ohio utilities, which in combination with the securitization will put each of those companies in a very solid credit position.

And with an equity infusion from FE directly to FES, along with the retirement of debt at FES, we have substantially improved the credit metrics of that entity as well. Further, we recently completed the extension of our credit facilities through May of 2018 and we exercised the $500 million accordion option at the FE credit facility, which should provide sufficient liquidity to the Company. Combined with the other actions we have taken since the beginning of the year, these are significant accomplishments in a very short period of time and place our subsidiaries in a much stronger financial position.

Progress also continues on our plan to sell up to 1,240 megawatts of our unregulated hydro generation assets. First round indicative bids were received earlier in the quarter and we are involving a handful of interested parties in the deep dive process. I expect that we will be in a position to take the next step in this process during the third quarter.

Through the combined actions we have taken across the Company to reduce cash expenditures, particularly the reduction in our generating fleet CapEx, our equity needs have been reduced. As a result, we plan to issue equity only through a dividend reinvestment program and various stock-related benefit plans beginning later this year. This is expected to provide approximately $100 million on an annual basis based on the current stock price and the anticipated participation levels.

Beyond this, we have no plans to issue additional equity at this time. This clarification of our plans should put to rest any further speculation regarding amount and timing of additional equity.

With respect to the dividend, as you know, our Board of Directors announced an unchanged quarterly dividend payment of $0.55 per share just three weeks ago. Our dividend continues to be supported by the strength of our combined regulated utility and transmission operations.

As we reshape our balance sheet, improve our liquidity, and reduce our capital and other operating costs, we will continue looking at opportunities for growth in our regulated businesses with a strong focus on those that will improve customer service and provide attractive near-term returns to the Company. For example, we are making solid progress on the transmission projects that we outlined earlier this year. Portions of the Black River substation in Ohio, as an example, is now in service and should be fully operational by September.

We are also on target with the construction of the major transmission line that will ultimately connect the Davis-Besse nuclear power station to a substation in Lorain County. In New Jersey, open houses were held in late June for our proposed Oceanview reinforcement project, which will build a new 230 kV transmission line to reduce -- to add redundancy to the system and meet the growing demand for electricity. We are still planning to invest about $700 million through 2016, utilizing ATSI and TrAILCo to address reliability issues related to coal unit deactivations within our footprint.

We are also evaluating a number of additional opportunities within our service area that would further expand our transmission investments. Given the size of our transmission system and service area, the transmission investment opportunities that we have identified are in excess of $7 billion. While it will take us some time to further define the projects and related timeframe, it is fairly clear that the opportunities within our footprint to grow our transmission business are substantial.

In our distribution business, we are looking at the potential for rate cases in certain jurisdictions. Mon Power would be one of those upon the successful completion of the proposed Harrison Pleasance transaction, but we are also actively reviewing the potential for rate cases in other jurisdictions to assure timely recovery of capital. Further, we are considering accelerated investments in smart meter technology where such programs are supported by regulatory policy, and we are looking for opportunities to expedite improvements in service reliability as is being supported in Ohio throughout our service area.

On the overall economic front, things are obviously not yet where we want them to be, but we continue to see progress and believe that the bottom is now behind us. Our sales have been relatively stable over the last three years and we are now seeing increasing housing starts as well as significant growth in shale-related segments. With continued growth and economic improvement we expect to again see higher distribution sales over time.

We continue to aggressively address all aspects of our business -- our generation fleet, our operations, our regulatory opportunities, and our financial initiatives. And by taking advantage of growth opportunities across our businesses and reducing expenses, we believe we can continue to provide value to our shareholders. Our strong second-quarter results, rigorous focus on cash management, and our willingness to make decisions illustrate our ability to deliver even during tough economic times.

Thank you for your support. Now I will hand the call over to Jim for a review of second-quarter results.

Thanks, Tony. As we walk through second-quarter results, you may want to refer to the consolidated report which was issued this morning and is available on our website.

As Tony mentioned, our strong results were solidly in line with our expectations. Non-GAAP earnings for the second quarter of 2013 were $0.59 per share compared to $0.60 per share in 2012. On a GAAP basis, this year's second-quarter results were a loss of $0.39 per share compared to earnings of $0.45 per share last year.

The full list of special items that make up the $0.98 per share difference between GAAP and non-GAAP second-quarter 2013 results can be found on page four of the consolidated report. Most significant of these is $0.85 per share related to plant deactivations. Other special items for the second quarter include trust securities impairment of $0.05 per share, debt redemption costs of $0.04 per share, regulatory charges of $0.02 per share, and a decrease of $0.02 per share related to merger accounting for commodity contracts.

Let's turn now to the results from our business units. We will begin with distribution deliveries, which added $0.02 per share due to a 3% increase in residential deliveries. Overall, distribution sales decreased by 325,000 megawatt hours, or 1%, compared to the second quarter of 2012, as the increase in residential sales was more than offset by a 3% decrease in commercial deliveries and a 2% decrease in industrial sales.

Typically, when we speak of the weather impact on residential distribution deliveries, we are looking at heating and cooling degree days. This quarter the discussion is a bit different because, while second-quarter temperatures were warmer than normal, they were significantly cooler than the 2012 period. However, the month of June was more humid in 2013 than in 2012, which contributed to higher residential usage.

In addition, you will recall that June 2012 sales were negatively impacted by the derecho that swept through parts of our Ohio, Pennsylvania, Maryland, and West Virginia territories on June 29 causing outages for more than 0.5 million customers.

Second-quarter industrial sales increased in the chemical and refinery class but declined in the steel and automotive, driven by the bankruptcy of RG Steel and the shutdown of the Ford Brookpark plant. Those events both occurred in May 2012, so we expect some improvement in our year-over-year comparison in the steel and automotive classes starting in the third quarter. Our full-year forecast for 2013 calls for an overall increase of 2% in industrial sales with most of the increase attributable to shale gas activities.

Moving now to other drivers of the second quarter. Reflecting our continued focus on cost control, lower O&M expenses increased earnings by $0.06 per share. On the generation side of our business, O&M benefited from fewer nuclear refueling outages compared to the prior year period and lower lease costs from the previously repurchased interest in the Beaver Valley Unit 2 and Bruce Mansfield plants.

On the distribution side, expenses were lower due to our greater focus on capital work during the quarter and cost savings initiatives that were implemented last year. Higher general taxes and a higher effective income tax rate decreased earnings by a total of $0.04 per share. And, finally, depreciation expenses decreased earnings by $0.03 per share.

I will turn next to commodity margin for our competitive business. Commodity margin increased earnings by $0.08 per share compared to the second quarter of 2012 when you exclude the $0.11 per share impact of lower PJM capacity revenues.

While challenged by low market prices, FES continued to strategically grow its retail business. The total number of retail customers increased by approximately 700,000 in the past 12 months to 2.7 million by the end of the second quarter of 2013. Total megawatt hour sales in our competitive operations increased 7% and increased earnings by $0.04 per share.

Looking now at each of our channels, governmental aggregation sales increased 31% in the quarter as a result of the continued successful expansion into Illinois. We achieved 35% growth in mass-market sales, largely as a result of our successful marketing campaigns in Pennsylvania and Ohio. Structured sales nearly doubled due to increased municipal, cooperative, and bilateral sales.

Direct sales to large and medium-sized commercial and industrial customers increased 1%. And, finally, consistent with the trend over the past year or so and our retail strategy, POLR sales continued to decrease as we realigned our portfolio.

Higher second-quarter retail sales also had the impact of increasing both our purchased power cost and our transmission expense. However, these expenses were more than offset by lower capacity expenses, higher wholesale sales, and the net benefit of financial hedges associated with our sales and generation portfolio. We also saw a lower average cost for fuel, which is in large part a result of the work we did late last year to restructure and terminate certain coal contracts, primarily at Harrison and Sammis. We expect this fuel variance to continue through the end of the year.

Total second-quarter ongoing generation output increased modestly by 870,000 megawatt hours as a result of higher capacity factors at our fossil fleet. Overall, we are pleased with the quarter's solid results, which demonstrate that even in very challenging times we can strike the right balance of achieving short-term performance while laying the foundation for what we believe is a strong long-term strategy.

For example, as we mentioned last quarter, we have slowed FirstEnergy Solutions' future hedging based on current market conditions. FES has already exceeded its retail sales targets for 2013 with projected sales of 107 million megawatt hours and an overall rate in line with the $53 per megawatt our guidance we provided for the year.

Going forward, we remain committed to implementing our plans for our competitive business, but we have adopted an even greater focus on higher-margin sales opportunities and selected customer retention. We continue to believe that our competitive retail strategy is the right approach for the long-term and with continued, careful execution we will help ensure we are in a very strong position as market conditions recover.

I will turn now to an update on our financial plan for the year. As you will recall, in February we laid out a plan that is structured to improve the balance sheet, particularly at our competitive operations and enhanced liquidity. As Tony said, we have made a significant amount of progress during the first half of the year. I will walk you through the most recent accomplishments.

Tony mentioned that in June our utilities became the first in the state to successfully take advantage of the new securitization act, which allows us to finance deferred costs using AAA-rated long-term securitization financing. This transaction allowed us to redeem $410 million of debt at the Ohio utilities.

In addition to securitization, we plan to further reduce debt on our three Ohio utilities during the third quarter and have issued notices to redeem an additional $660 million of debt. As these plans are implemented, we will have achieved our goal of significantly improving the credit metrics of each of our Ohio utilities.

As we discussed on the first-quarter call, through early May we had already taken action that resulted in the reduction of about $1.5 billion in long-term debt at our competitive businesses. Subsequently, FE Corp contributed $1.5 billion of equity to FES, which used the funds to repay outstanding debt. These actions have put the credit metrics for competitive operations on more solid ground.

During the second quarter, we also completed the extension of our credit facilities through May 2018, and as Tony mentioned, we exercised the $500 million option on our revolver, bringing the total size of the facilities to $6 billion. Overall, we've made very solid progress on the financial plan we laid out for this year and are reaffirming 2013 non-GAAP earnings guidance.

Looking at the bigger picture, we are working through the challenging economic landscape by taking proactive steps to reduce capital and expenses without restricting our ability to create and take advantage of opportunities across all of our businesses. As Tony mentioned, we have made significant capital reductions of $875 million on the competitive side of the business with a continued focus on further refining both our MATS and other capital spend.

We have an intense focus on cost with $150 million to $200 million in further reductions already identified across the Company through medical and benefit changes, staffing reductions, and changes to pension funding. We are redeploying capital into regulated areas of our business that provide reliable return, such as the investments in our transmission business and about potential rate cases and growth opportunities in distribution.

In our retail business, which has a strong book already in place for 2014, we plan to continue to be more selective in our channel and customer activity going forward. Finally, we will continue working to strengthen our balance sheet through our equity program and continued implementation of our financial plan.

As both Tony and I have outlined, we have taken significant steps to reduce costs, redeploy capital toward predictable and reliable return opportunities, and move retail megawatt hours into higher-margin channels. The end result will be a stronger FirstEnergy, well-positioned to address challenges and deliver positive results for shareholders.

Now I will open the call to your questions.

(Operator Instructions) Dan Eggers, Credit Suisse.

Good afternoon, guys. I want to dig a little bit more into the $150 million to $200 million of savings and, Tony, I appreciate it's still a bit early in the process. But can you maybe help bucket out what fits into kind of capital savings relative to O&M savings, given all the efforts you guys have done in the last couple of years already to bring costs down and capital out of the business?

Dan, this is Tony. When you think about it, it's all -- it starts off all as an expense reduction, but a big part of our expenses end up being capitalized because it's all people-related. So it's going to really turn out to be a function of whether or not -- the workload and how it gets allocated is just going to be a question of whether or not that $150 million is going to be allocated to expense, because that's where the individual would have or is working on, or whether it will be moved over to capital because of that same rationale.

This isn't capital in the sense that we are delaying projects or eliminating projects. These are real cash savings that will then get allocated depending on where our people are working and what projects we are working on during the timeframe.

How much headcount reduction goes into this then? Because it's a lot of efficiency gains relative to your cost base.

I would say, Dan, we said that there would be about 250 positions that would be eliminated. Some were not filled and that was in addition to the 380 positions that were associated with the deactivation of those plants. I think the bigger cost item will be the elimination of some of our benefit cost. It's a bigger cost reduction than just the staffing in itself, Dan, so I would say that would be the more significant component of the cost reduction.

And this doesn't -- this is separate from the money you're saving from Hatfield and Mitchell closing, right?

That's right, that's right. You know, what I would say the O&M savings associated with Mitchell and Hatfield that would align with the several cent incremental earnings per share.

Okay, I got it. Then I guess just maybe one more question on this is that if you think about from an O&M inflation perspective, net of these benefits, what should we think about from a 2013 baseline will be the O&M inflation for FirstEnergy on a consolidated basis?

I guess, Dan, we are going to wait and give you that next year when we give -- or later this year when we give you 2014 guidance. Obviously, we are looking at all of our costs, not just the ones that we've dealt with here. But fundamentally each and every time we go about developing what our game plan is for the upcoming year, we will scrub all the numbers and determine where best to spend our available cash.

Okay, thank you.

Brian Chin, Bank of America.

Good afternoon. Question; you have in the release a reference to net MISO and PJM transmission costs. What is that? And can you talk about whether transmission rights and underfunding, is that the issue that you are referring to in that, similar to one of your peers earlier this earnings season?

Brian, this is Donnie. Let me talk about the FTRs first, because that seems to be a hot issue.

Like many of the other PJM market participants, we also have experienced FTR underfunding. However, as we went into this year we had adjusted our hedging strategy to be less dependent on FTRs. So versus our expectations, the impact has been very minor.

If you think about what's going on there, what's driving this underfunding, there's a whole myriad of issues. There's the seams issues between MISO and PJM. There's the difference between what you would anticipate from an infrastructure perspective when the FPRs are allocated versus what actually occurs with outages and that sort of thing. And then, obviously, differences between how the day ahead and real-time congestion is settled.

I think we also released that we, in fact, filed a complaint with FERC back in 2011 to try and address these issues and that case is still pending.

We are seeing funding coming in; about 75% to 85% of what we feel we are entitled to, so we believe we are being shorted somewhere in the neighborhood of 15% to 25%. So while versus expectations it's a very minor impact to us, on a year-to-date basis we believe our revenue was off about $6.5 million, about $0.01.

Okay. And so that's not the MISO PJM transmission issue, it's a separate issue. Understood.

That is correct.

Then with regards to the cost cuts, just jumping back on Dan's earlier question, is there a breakdown you can give of to what extent those cost cuts are related to deregulated operations versus regulated operations?

Right now we don't have that breakdown, Brian. As Tony said, we are going to incorporate that into our 2014 plans and we will probably be able to give a little more clarity then.

Okay, thank you.

Julien Dumoulin-Smith, UBS.

Good afternoon. A quick question. It seems as if there has been a little bit of a change in tactic with regards to regulated rate-based growth and positioning of the Company. Could you perhaps confirm that and perhaps speak to what a new rate base growth trajectory could be prospectively given some of the spending emissions you guys spoke about on the distribution side?

Julien, I would necessarily describe it as difference. We have always invested heavily in our regulated operations. The fact is, however, that as you look to the future that there are probably stronger returns available and more predictable returns available from shifting investments towards transmission and other items as opposed to investing in generation assets. That is kind of a decision we make all the time in the business.

The growth opportunities in transmission and distribution, we are looking very closely at -- tried to give you a sense for the type of opportunities that are in the transmission business. I wouldn't necessarily say there are the same types of opportunities in the one-off opportunities, if you will, in the distribution business, but they are significant in the distribution business if, in fact, we start to perhaps accelerate smart meter technology throughout the system.

The timing is going to be dependent in large measure on when we believe it's time to begin to expand rate base in those areas and take advantage of those growth opportunities.

Okay. So still not stick quite clear yet, but stay tuned.

Perhaps looking at the back of the unregulated side, the latest RPM auction, while you guys didn't want to disclose how many megawatts cleared, kind of indicatively, if you would, in the latest auction relative to the last how significant was the change in cleared capacity? Do you get what I'm asking? If you can provide anything.

Nice try. That's pretty good, though, since you didn't know the first one or the second one, I don't really know how to answer that. Question loud and clear, though. You guys are getting better at this.

It takes time, right? All right, I will leave it there then.

Jonathan Arnold, Deutsche Bank.

Good afternoon. Tony, you made it -- you sounded more enthusiastic about the economy than you have in a while even though the numbers, sort of sales numbers were not -- we were not seeing it in the numbers. Can you just give us some more insight into what you are seeing in the customer base and what is the basis for your commentary on the prepared remarks?

I think what we are seeing basically, Jonathan, is we think the bottom is behind us now. Most of the plants that we think were particularly exposed, for example, the Ford Brook Park plant we talked about and that one steel operation. They were closed in 2012 and we are starting to see that the other items are up significantly. Some of the other steel mills that we have are up.

So once you get kind of through this period that we think now is bottomed out -- we are seeing really strong growth in shale areas, in steel-related, particularly item -- particularly steel mills that are operating in the pipe-related types of activity. Like I said, housing starts are up. It's a slow start, but it's far more positive what we've seen in the past and we are starting to see some activity across each segment of the business.

You mentioned the accordion facility at the parent, that you've upsized that line $500 million. Does that have cost implications?

No, it really doesn't have any cost implications other than you get always a charge for your unused capacity, so you get very minor incremental cost associated with it.

Not something we are going to notice, then?

Say that again, Jonathan.

Not something we are going to notice?

No, you will not notice it, no.

Paul Patterson, Glenrock Associates.

Good afternoon. I was wondering just -- sorry to be a little slow here, but Brian I think was asking this. What is the PJM MISO transmission cost? What is causing that? Because it was also something that hit you guys in the first quarter as well.

This is Donnie. The biggest driver there is just increased sales. We have to pay network transmission to deliver our product in many cases, and so that's the biggest driver. But we will net some other things against that.

Okay. Then the net financial sales and purchase, what was that, the $0.02 there?

That is basically -- when you look at that we are hedging -- that's one of the instruments we used to hedge the congestion. So we will do a financial sale and a financial buy to hedge the congestion and that's the net of the two.

Okay. Then just in terms of the nuclear expense with the steam generators and everything, just is there any flexibility on that? You did mention that you were thinking of potentially augmenting the CapEx going forward. I was just wondering, given market conditions and everything, whether there's been any change or any thought process on that if there is any flexibility on that.

Those steam generators, you are probably referring to the Davis-Besse that we are planning in 2014 and then we also have Beaver Valley 2 that's in 2017. Although you could move that, it's very unlikely that we would because you have a pretty laid out schedule right there that you've got to kind of meet, and then you've also got to plan what your outages are. So I think it would be very unlikely that we would be making any modification to that construction schedule.

Okay, great. Just finally with respect to the cost savings and stuff, you mentioned a lot of the benefit side and what have you. And I do see that the retirement benefit, sort of non-cash impact on the cash flow statement, has sort of increased. Is that the kind of thing that we should be thinking about?

Should we be thinking about this as being one of those things that over the long-term provides savings, but in the near-term is sort of accelerated in terms of the non-cash accounting benefit because of the OPEB and pension liability or lower?

No, I think the ones we're talking that today, while there could be some impacts there, the ones we are talking about today are fundamental changes in plans, single administrator as an example; changing in plans that have higher deductibles. Things of that nature are driving the real change in the cost savings.

So it will have a direct cash impact pretty quickly, it would sound like, starting in 2014?

That's what we are expecting, yes.

Okay, thanks a lot.

Steven Fleishman, Wolfe Research.

Good afternoon. A couple questions. Just on the equity issuance through the DRIP programs; is that just a 2013 or do you tend to continue new equity through DRIP after 2013?

At this point, we would expect that this would continue throughout next year. As we said, it would be about $100 million on an annual basis. So you won't see $100 million this year. Probably won't really get implemented until probably by the fourth quarter this year, but we would expect that to continue into next year.

Okay, so from a model standpoint, like just assume $100 million per year, really starting in 2014?

That's correct.

Then on retail margins, it sounded like if I heard it, you said that maybe you are actually seeing improving retail margins. Because it seems like most other people keep complaining that retail margins are declining. So maybe you could just give some color -- just clarify what you are seeing on retail margins, and maybe is it that you are targeting this different customer base, or why do you think it might be very different than what we are hearing from others?

Steve, this is Donnie. I think it is the way we are pushing into the different channels. I think over the last several years, we have talked about our multichannel approach, and some of those channels are harder. Retail sales, residential retail sales is much harder than selling to a big C&I customer. Generally, you get stronger margins there. You have to be very careful about your cost of acquisition.

But if you think about, for example, our $0.07 for seven years. In today's market, those contracts are paying very nice margins to us. In general, I think right now we have sold about 75 terawatt hours forward for 2014, and we are seeing an aggregate rate about $1 better than what we are delivering this year. I think this year we are right about that $53 a megawatt hour. Next year what we've got booked so far will produce something right around $54 a megawatt hour.

Okay. Then my last question is just on the -- you mentioned the Hatfield shutdown, and Mitchell is about a 10% reduction in megawatt hours, but obviously a lot of cash flow benefits from that. The other savings, the generation in terms of cash flow, is there any additional impact on megawatt hour production, or should we assume about that 10% reduction just for those plants?

I would assume it's probably about 9.5 million to 10 million megawatt hours that would be associated with the Hatfield and Mitchell, so that's what I would assume for that.

But the other cash flow savings that you mentioned don't have any associated reduction in megawatt hours?

No, no, that's correct.

Great, thank you.

Stephen Byrd, Morgan Stanley.

Good afternoon. I wanted to just talk about the credit position and the equity needs. Regarding Harrison and the asset transfer, if that were to not be approved how would that impact your thinking about equity requirements?

I don't think that it would change our thought process on equity at all.

We have laid out our game plan for equity. Those will not affect our decision-making.

Okay, so failure to get that transferred of Harrison wouldn't impact that? Okay.

No.

Okay. Then just switching over to transmission, you had mentioned a lot of potential growth. As you think about the financing and structuring of that, do you think much about different options in terms of how to finance that? Some folks of thought about a pure-play transmission approach. Or is it something we should just assume would very likely just continue to be funded sort of organically within FirstEnergy?

My sense is that we will look at a number of different opportunities and determine what's in our best interest and our shareholders' best interests going forward.

Okay. So that is something that you do think about in a variety of options there. It's not set in stone that it would always be simply funded within FirstEnergy?

I think that's a fair statement, yes.

Thank you very much.

Ashar Khan, Visium.

Good afternoon. Tony, I just wanted to recap what I heard, so I apologize; I might be repeating some things. One thing you said is that generation transaction would be at least a couple of pennies or more accretive to EPS starting next year, 2014.

I think some of the other things that came out is that there is $875 million of reduction in CapEx over this time horizon on MATS. And if I can get what that is over, what period. Is it three years, five years? I forget what the timeframe of that is.

Thirdly, you mentioned about $150 million to $200 million of lower cost reductions. These are additional stuff. And if I am right, you mentioned that a lot of them would be related to retirement benefits and if I am hearing that's lower deductible and everything, if I'm right those would mean lower, I guess, pension or retirement costs. If I understand rightly what was described in the Q&A.

If I can get a little bit of a clarifications on what I said; if they are on the right track or not on the right track.

Okay, let me deal of the first one since I only said it's accretive. I think Jimmy said it's, what, a couple cents?

Yes.

So I think the couple cents is what you ought to be thinking about. The $875 million reduction in capital, I think is -- what was that five years? So over that five-year timeframe with the bulk of that coming in the earlier years, the time when the MATS expenditures would be coming through.

And with respect to the $150 million to $200 million, I think you are a little confused. The bulk of these expenditures or bulk of these savings relate to current employees. Somebody raised the question with respect to retirees, but the fact of the matter is the medical plan benefit changes and the other change that we are contemplating in benefits and otherwise are really related to the current benefit package we offer employees.

Okay, fair enough. Then if I heard, we might get 2014 outlook this year at EEI, or is that what we should look forward to?

We will give it to you when we are ready.

Operator, we'll take one more question.

Angie Storozynski, Macquarie.

Thank you, I have two quick questions. One is the $54 per megawatt hour margin for the retail business for 2014, is that really comparable to the margins from this year given that there is a change in mix, for instance, between retail and C&I sales?

Yes, I think it's very comparable. If you think about what the markets have done as we have booked those sales, the wholesale markets have dropped off fairly steadily over the last several years and to be able to deliver a higher aggregate rate I think is significant.

No, I'm actually more asking about if there is like a significantly higher SG&A expense associated with those sales compared to the sales that are being executed this year.

No, generally I think, Angie, what you would see is our SG&A expenses have come down. I would especially point to fuel, for example, has come down significantly based on the work you did last year.

Okay. Secondly, I know that you are still in the midst of the hydro asset sales process, but can you at least give us a sense of at this stage your expectations for the outcome of that sale as similar to expectations that you had earlier in the year?

I think at this point, Angie, we had the first round of indicative bids. We had a lot of interest in the hydro assets. We're in the process now of narrowing that down and we are continuing to evaluate that, so I don't think there's any change at this point.

Okay, thank you.

Thanks, everybody. Thanks for participating in the call and your continued interest in FirstEnergy. Thanks.

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