Meghan Beringer - Director, Investor Relations Tony Alexander - President and CEO Chuck Jones - Executive Vice President and President, FirstEnergy Utilities Leila Vespoli - Executive Vice President, Markets and CLO Jim Pearson - Senior Vice President and CFO Donny Schneider - President, FirstEnergy Solutions Jon Taylor - Vice President, Controller and CAO Steve Staub - Vice President and Treasurer Irene Prezelj - Vice President, Investor Relations.

Dan Eggers - Credit Suisse Paul Fremont - Jefferies Jonathan Arnold - Deutsche Bank Stephen Byrd - Morgan Stanley Angie Storozynski - Macquarie Capital Paul Patterson - Glenrock Associates.

Greetings. And welcome to the FirstEnergy Corp.’s Third Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. (Operator instructions) As a reminder, this conference is being recorded. I would now like to turn the conference over to Ms.

Meghan Beringer, Director of Investor Relations. Thank you, Ms. Beringer. You may begin..

Thank you, Manny, and good afternoon. Welcome to FirstEnergy’s third quarter earnings call. First, please be reminded that during this conference call, we will make various forward-looking statements within the meaning of the Safe Harbor 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 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 segments and adjusted EBITDA, which are non-GAAP financial measures. Reconciliations between GAAP and non-GAAP financial measures are contained in the consolidated report.

The updated fact book, as well as on the Investor Information section on our website at www.firstenergycorp.com/ir.

Participating in today’s call are Tony Alexander, President and Chief Executive Officer; Chuck Jones, Executive Vice President and President, FirstEnergy Utilities; Leila Vespoli, Executive Vice President, Markets and Chief Legal Officer; Jim Pearson, Senior Vice President and Chief Financial Officer; Donny Schneider, President of FirstEnergy Solutions; Jon Taylor, Vice President, Controller and Chief Accounting Officer; Steve Staub, Vice President and Treasurer; and Irene Prezelj, Vice President, Investor Relations.

Now I will turn the call over to Tony Alexander..

Thanks, Meghan, and welcome, everyone. Thank you for joining us. Today, we will provide an update on the important initiatives that are shaping our company's future. Since our last earnings call in August, we have continued to build positive momentum in our regulated businesses and limit risk at our competitive operations.

And at the same time, we are starting to see real progress as a result of our efforts to advocate for a competitive market that supports price stability and reliability. I will start with the review of development across our business, including some of the early and encouraging signs of reforms in the regional competitive markets.

Then Chuck will join us with an update on the distribution business and our transmission investments. Leila will then discuss the status of the rate cases at our utilities, the ATSI filing that we made last week and other regulatory matters, as well as an update on the changes we have put in place in our competitive business.

Finally, Jim will review our third quarter and year-to-date financial results. Okay. Let's get started. I'll start with a look back at events that have shaped this year so for. We believe 2014 will be remembered as a pivotal period for both our company and for the competitive environment in our region.

The stage was set with the unusually warm temperatures in our region in September 2013, which strained the regional grid. With the start of the next year the same region was impacted by the polar vortex and subsequent severe weather events throughout the winter.

These episodes of increased demand, revealed weaknesses in the regions power supply and resulted in nearly 100 emergency actions, interruptions of service to customers and severe spikes in wholesale power prices.

We reacted quickly to the deterioration in market conditions, reassessing our sales strategy and setting a new course for our competitive business, based on the new market dynamics.

As you know we took a series of significant steps, reduced our exposure to weather sensitive retail loads and to maintain a more open position to take advantage of market upside opportunities. At the same time, we have been working to support changes that can help prevent similar or even more disastrous stress on the electric grid in the future.

And it is becoming evident that the weather events are serving as a catalyst for a number of very important reforms that will not -- that we not only endorse, but view as critical to stabilizing the wholesale markets in this region. One such reform is PJM’s capacity performance proposal.

This is a positive step and truly recognizing the role of baseload generation with firm fuel, the grid stability and reliability. As Leila will explain, work on this proposal is continuing, but our belief is that this could have a very positive effect on the company and the grid. The future role of demand response also continues to be in play in PJM.

The full panel of the DC Circuit recently declined to rehear the ruling that FERC does not have jurisdiction to regulate demand response in wholesale markets. As I'm sure you all know, FERC has signaled its intent to appeal that ruling to the United States Supreme Court. Again, Leila will discuss the demand response issue.

However, a favorable resolution of this issue will be positive to the company, the markets and the grid. The increase focus around market reform issues seems to signify the start of a meaningful shift in the competitive business environment after years of very challenging conditions.

We remained optimistic that this is only the beginning and we will continue to advocate for a workable solution that can ensure adequate revenues, revenues for operators of baseload generation, while also recognizing that fuel diversity and maintaining the right mix of assets are essential to reliability of our region's electric system.

Turning now to other developments across our company, starting with generation. Last week, we reached an agreement in principle to purchase the remaining lesser equity interest in the nuclear sale leaseback of Perry Unit 1 representing approximately 55 megawatts.

Consistent with our strategy to take these future obligations off the table, upon the completion of this purchase, we will have either purchased or have binding agreements for the purchase of all the ownership interest in connection with the nuclear sale leasebacks at Perry and Beaver Valley.

In August, we told you that we decided to minimize capital expenditures at our 2,400 megawatt Bruce Mansfield plant, while we evaluate the strength of competitive markets. Although, the results from the September 2016, 2017 incremental auction were stronger, Mansfield did not clear.

While we continued to operate and maintain the plant, we will consider the impact of the market reforms currently being considered, as well as the results of the May 2015 PJM auction for the 2018, ’19 period in our decision about the timing of the dewatering facility. That is required to continue the plants operation after December 31, 2016.

As we look towards colder weather, we believe our baseload coal-fired and nuclear units are well prepared to meet the demands of this winter. These units have on-site fuel supplies that are not generally affected by extreme weather. And thus play a critical role in providing reliable and affordable electricity to the grid year-round.

During the summer and fall months, we also performed a series of maintenance activities to prepare our baseload generating stations to meet the demands of the winter.

We have set up heating elements that provide additional warmth to piping, added antifreeze to some equipment, installed storm barriers to protect from winter weather, provided temporary heaters in areas most susceptible to cold and increase fuel supplies at our coal-fired facilities.

In addition, we will stay in close contact with PJM throughout the winter to avoid scheduling plant maintenance during periods of expected high electricity use. This work should help prepare our fleet for potential demand spikes this winter.

Leila will provide an update on other initiatives within our competitive energy services segment, as well as introduce 2016 adjusted EBITDA guidance for the business later in the call. With respect to our distribution business, we are very engaged on the regulatory front.

We just reached the settlement in our West Virginia rate case and have several other active rate filings as well as all our fourth ESP in Ohio, all of which are moving through the regulatory process. We expect outcomes in all of these cases by May of next year.

As these proceedings are completed, we will be able to provide much more transparency with respect to our expectations in the distribution business and the timely recovery of our investments going forward.

In our transmission business, we continue to make excellent progress with our Energizing the Future initiative which Chuck will describe in more detail. We also filed with FERC last week to change the structure of ATSI’s formula rate.

The proposed change requests moving from an historic test year to a forward-looking test year, which will provide a better match of our cost as we continue our investments in this initiative. This morning, we reported third quarter operating earnings of $0.89 per share, in line with our expectations.

We also reaffirmed our 2014 operating earnings guidance range of $2.40 and $2.60 per share. Jim will provide more detail on that guidance as the mix of operating earnings among our reporting segments has changed slightly.

At EEI conference next week, we plan to share more detailed information about the 2015 drivers in our regulated businesses and better frame future opportunities in our transmission business.

Looking ahead, we will provide additional updates as we begin to get more clarity around other external drivers, such as ATSI filing and any further developments in the competitive markets than once we begin to receive result from a rate cases likely in the springtime frame.

We’ll be able to provide not only full 2015 guidance but significantly more detail and greater clarity into the financial and operational expectations across the company. It has been a busy and productive period and we are on track with a solid plan to build and strengthen our company.

We have put into play critical elements that are needed to provide long-term value and stable predictable growth. We remain committed to driving change, both within the company and in our industry to better position FirstEnergy for the future. Thank you for your support.

And I’ll turn the call over to Chuck Jones for an update on our regulated businesses. Chuck..

Thanks, Tony. I'm pleased to join the call today. I'll start with a brief look at our distribution business and then move to an update on our Energizing the Future transmission expansion program.

We remain encouraged by the steady growth and stable load in the commercial and industrial sectors of our distribution business, both of which continue to benefit from the modest economic recovery and increased economic investment primarily related to shale gas.

While weather was significantly mild compared to the third quarter of 2013, our distribution business continued to produce solid results. More important, as you have heard over the past several earnings calls, the overall trends for commercial and industrial deliveries remain very solid.

In fact, adjusted for weather, we have now seen five consecutive quarters of growth in both the commercial and industrial segments. The industrial pipeline remains promising.

Among this region's traditional industrial base, including steel, automotive, electrical equipment and petroleum sectors nearly all of our key customers are expanding and clearly shale related activity remains a bright spot. Signs point to continued and accelerated growth in this sector.

In addition to its considerable impact on our distribution business, the shale industry is also driving growth in our transmission segment.

Approximately $250 million of the regulated transmission investments we have identified for 2015 at TrAILCo are designed to meet rising electric demand, driven by the shale gas industry across our regulated service territories.

This infrastructure, including high-voltage substations and transmission line is coming online to accommodate new shale gas processing facilities pipeline compressor stations and other energy intensive operations in Ohio, Pennsylvania and West Virginia.

These midstream projects alone account for 1100 megawatt of anticipated electric load growth in 2015 through 2020. The rapid growth in the shale gas industry is transforming communities and creating new jobs and economic opportunities throughout our service territory.

The investments we're making in transmission infrastructure will benefit customers throughout the Marcellus and Utica shale regions by boosting electric service reliability across the system. New electric infrastructure will directly support the build out of the shale gas industry and the resulting economic activity across the region.

By upgrading our local power infrastructure, we can help communities attract other energy intensive industries while ensuring the highest levels of service reliability for every electric customer.

But the shale industry is just one driver of the $4.2 billion in investment opportunities we are planning from 2014 through 2017 across our transmission footprint. In 2014, we are on track to complete $1.3 billion in investments, expanding 1100 projects this year.

This year's initiatives include approximately 100 projects associated with generating plant deactivations, which we have discussed in the past. We continue to make steady progress with projects designed to enhance service reliability for our customers.

For example, in Toledo, Ohio, we are constructing a new 48 mile 345,000 volt transmission line using existing transmission towers and building a new substation.

This $32 million project which is on track for completion by June of 2015 is designed to enhance service reliability in our Toledo Edison Service area and to accommodate future electric load growth.

In our Mon Power service territory, we are on track to complete a large expansion project this year that will support the electric demands of the areas rapidly expanding Marcellus Shale Gas industry, including 280 megawatts of incremental load that is expected to come on line in December.

The $50 million project includes installation of the new substation, with state-of-the-art voltage support as well as sectionalizing equipment on an existing 41-mile, 138,000-volt transmission line, will enhanced service reliability for Mon Power customers along the Route 50 corridor in Doddridge, Harrison and Ritchie counties.

These are just two examples of the hundreds of projects that are already completed or underway. We expect the transmission business to be our primary growth platform, not only through the previously announced $4.2 billion investments through 2017, but as we continue to implement our “Energizing the Future” initiative for many years thereafter.

In fact, only $1.6 billion of the initial $7 billion “Energizing the Future” investments is being undertaken in this period. The vast majority of the current estimate is for RTEP projects related to generating plant shutdowns and to meet the increasing demands within the service area.

We will layout additional details regarding future transmission investment opportunities at EEI next week. Thank you. I will now hand the call over to Leila..

Thanks, Chuck and good afternoon, everyone. I'll begin with a brief update on our competitive business and then I will look at the status of our distribution rate cases and other regulatory matters. The transformation of our competitive business is well underway.

As we announced in August, we are pursuing the effective hedging of the majority of our generation resources with reduced risk and at the highest margins possible, while leaving a portion of our generation available to capture market opportunities.

The actions we have taken put our competitive business in a stable position, from which we can gauge market conditions and participate when and where the opportunities are most promising.

Consistent with our strategy, we continue to allow attrition of our MCI and mass market customer base as contract terms expire, as well as weather sensitive LCI loads. Overall, contracts sales volume decreased by 4.5 million megawatt hours, compared to the third quarter 2013.

At the same time, we are maintaining targeted sales levels to government aggregation customers in Ohio and participating in POLR auctions where we see value. During the past month, POLR auctions were conducted in both Pennsylvania and Ohio that will ultimately determine retail generation service rates for these small service customers.

Both auctions produced results that appear to reflect an increased risk premium, which we believe is associated with volatility and uncertainty in PJM. In Pennsylvania, the auctions were for 12 months and 24 months, residential and commercial products for delivery beginning June 1, 2015.

Auction clearing prices for residential products range from between $70.09 to $85.15 per megawatt hour, while clearing prices for commercial products range from between $74.46 to $89.65 per megawatt hour. HPS won nine tranches in that auction.

In Ohio, HPS won four tranches in the 10th wholesale auction, which produced an average clearing price of $73.82 per megawatt hours. These results will be blended with previous auctions and one upcoming auction in January 2015, to establish retail generation rates from June 1, 2015 through May 31, 2016.

For 2015, our committed sales are about 59-kilowatt hours. After 2016, committed sales are at 33 kilowatt hours, reflecting the currently committed sales growth of LCI, MCI and mass market, as well as the POLR and government aggregation sales.

We remain on track to transition to a target portfolio of retail sales in LCI and government aggregation, as well as POLR sales in the range of 10 to 45 kilowatt hours annually. Let’s look now at financial expectations.

For 2015, we are reaffirming our adjusted EBITDA guidance range for the Competitive Energy Services segment of $900 million to $1 billion. Given the slight increase in market prices versus mid-July, we are comfortably in the upper end of that range at this time.

Last quarter, we told you that we expect our competitive business to be cash flow positive of the period 2015 through 2018 and we continue to support that expectation. This conservative forecast does not take into account the numerous uplift opportunities such as incremental auctions, the removal of demand response and other possible catalysts.

We will revise our outlook if needed, as these issues are resolved. Today, we are introducing adjusted EBITDA guidance for 2016 in the range of $850 million to $950 million.

The reduction compared to 2015 is driven primarily by seven-month of high capacity prices in 2015 versus five months in 2016, and the amount of generation that clear 2015, ’16 auction versus the ’16, ‘17 auction.

The 2016 adjusted EBITDA guidance estimate also includes an additional 500 megawatts of capacity that cleared in the incremental auction for the 2016-17, PJM planning year held in September. That leaves about 2,700 megawatts still available to participate in the July incremental auction for the ’16, ’17 periods.

I will note that adjusted EBITDA guidance, we are providing for both 2015 and 2016 does not reflect any of the changes that are being considered in the capacity markets or any estimates of future incremental auctions applicable to those periods.

All of which could provide significant uplift, as the value of baseload generation is recognized in the market. We have put together in place a solid strategy to position our competitive business going forward. And I believe we are in a sound position to take advantage of market upsides. Let’s shift now to a review of regulatory development.

As Tony mentioned, PJM recently provided in more detail around his capacity performance proposals. Key elements of the proposal include classified supply resources into two groups -- capacity performance resources and base resources.

Liming the amount of base capacity resources, that will be procured in the base residual auction, allowing units to satisfy the capacity performance criteria to offer into the RPM auction as the net cost of new entry and imposing significant penalties in the event of non-performance during peak usage periods.

We do have some concerns around PJM’s proposals. Last week, as a member of a coalition representing more than 69,000 megawatt of installed capacity in PJM, we advised PJM that three important changes should be made in the capacity performance proposal.

First, a multi-year pricing mechanism that limits year-to-year price declines to not more than 5% should be incorporated into the proposal. Second, price cap for the transitional auctions should be increased to the net cost of new entry.

And third, the proposed penalty structure should be reformed so that the potential penalties are better balanced with the financial opportunities for participating as a capacity performance unit.

We will continue close engagement on PJM’s proposal and will participate fully in the stakeholder and thought proceedings that are unfolding through the end of the year. Another key issue is the proper role of demand response in PJM markets.

As Tony mentioned, the DC Circuit recently rejected a request for rehearing ruling that PJM does not have jurisdiction to regulate demand response by means of wholesale energy market rules and tariffs.

At FERC’s request, the Court has stayed the enforcement of its order until December 16 of 2014 and then pending FERC’s potential request that the US Supreme Court accept an appeal of the Circuit Court's ruling.

In light of possible outcomes from the decision, a PJM white paper recently proposed to move demand response from the supply side to the load side.

However, because the proposal still would permit demand response to participate in price formation in the capacity markets, including potentially to set the market clearing price, we believe that the proposal is legally unsupportable.

We have communicated our concerns with this approach to PJM and expect to continue this dialogue with PJM and affected stakeholders.

Finally, on September 22, 2014, we filed our amended complaint regarding participation of demand response in the May 2014 base residual and obviously more rule develop on our complaint with order 745 proceedings progress. Let’s now move to our assay formula rate filing at FERC.

As Tony said, this filing, which was made on October 31st, proposes to change the structure of the ATSI formula rate.

The proposed change requests moving from historic test year for transmission rates reflect actual cost from the prior calendar year to a forward-looking test year which would reflect the estimated cost for project expected to be in-service within the current calendar year, with an annual true-up which would allow for real-time recovery of cost.

We have requested that new rates be effective on January 1. Turning now to review of state initiative. In Ohio, our fourth ESP called Powering Ohio's Progress, which was filed in August, is before the PUCO.

In addition to building on the success of our current ESP, the plan includes the proposed economic stability program, which involved a 15-year purchase power agreement between our Ohio utilities and SEF, which will help ensure the continued operation of more than 3,200 megawatts of vital baseload generation while benefiting our customers by mitigating market volatility and rising retail prices.

Hearings are scheduled for January with the decision requested by April 8, 2015. We continue working with customers, employees and officials on the state to advocate for this plan, which we believe is very good for Ohio and for our customers.

Let’s turn now to New Jersey where the Board of Public Utilities approved an Administrative Law Judge request for 45-day extension to render an initial decision in our base rate case. The ALJ’s initial decision is expected to be filed by November 13.

The BPU also issued a favorable decision in the generic proceeding reviewing its policy regarding the use of a consolidated tax adjustment and base rate cases. The Board stated that it would continue to apply its CTA policy and base rate cases subject to the following modifications proposed by the BPU staff.

Calculate savings using a five-year look back from the beginning of the test year, allocate savings with 75% retained by the company and 25% allocated to rate payers and exclude transmission assets of electric distribution companies in the savings calculation.

As it relates to our pending rate case, the order provides for the BPU following the initial decision of the ALJ to reopen the record for the limited purpose of adding a CTA calculation reflecting this modified policy.

Although we are still reviewing the CTA order, by our interpretation and calculation we expect the CTA revenue adjustment to be reduced from approximately $56 million under the earlier policy to approximately $5 million to $6 million.

In Pennsylvania, evidentiary hearings in the base rate proceeding of our four operating companies are scheduled for January 13 through 16, 2015 with the final order expected in May.

And finally, in the Mon Power and Potomac Edison rate case yesterday we filed a settlement agreement with the Public Service Commission of West Virginia, which is subject to their approval. The agreement includes a base rate increase of $15 million to help address operating costs at our power stations and our distribution business.

It also moves the costs associated with the Harrison asset swap into base rate and eliminates the recovery of those costs through the temporary transaction surcharge.

It also includes a vegetation management surcharge of approximately $48 million, recovery of nearly $46 million and cost associated with major storms of 2012 and increased billing assistance for low income customers.

Parties to the settlement agreement include the PSC staff, the Consumer Advocate Division, the West Virginia Energy Users Group and Walmart.

We're very satisfied with the settlement and believe it will provide us with the resources necessary to help ensure continued safe and reliable electric generation and service for our customers with reasonable returns for our business. Pending approval by the PSC the rate increases would go into effect on February 25, 2015. Thank you for your time.

We are pleased with our progress to position the competitive business for future success and to assure a successful regulatory environment for our regulated businesses. Now let’s turn the call over to Jim for a review of our third quarter and year-to-date financial results..

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. As Tony mentioned earlier, our third quarter operating earnings were $0.89 per sh0are in line with our expectations. Third quarter 2013 operating earnings were $0.94 per share.

On a GAAP basis 2014 third quarter earnings were $0.79 per basic share compared to $0.52 per basic share in the third quarter of 2013. A list of the special items that make up the $0.10 difference between our GAAP and operating earnings can be found on page 2 of the consolidated report.

Now let’s review the key drivers of operating earnings across each of our business segments. We will begin with our distribution business where we reported third quarter operating earnings of $0.56 per share compared to $0.60 per share in the third quarter of 2013.

Moderate weather was the most significant factor this quarter with lower distribution deliveries impacting earnings by $0.03 per share. With respect to the other drivers in the distribution business pension expense, depreciation, and interest expenses all increased slightly in the quarter.

However, these factors were offset by earnings related to the Harrison/Pleasants asset transfer and a lower effective income tax rate. Looking more closely at the affects of weather on third quarter results, cooling degree days were 15% below last year and 17% below normal, which led to a 1.5% decrease in total distribution deliveries.

Most of this impact can be seen in the residential sales, which decreased 784,000 megawatt hours or about 6% compared to the third quarter of 2013. In the commercial sector, third quarter distribution deliveries to commercial customers decreased by 199,000 megawatt hours or 2% due to the moderate weather.

We can get a better picture of the sales trends by looking at the 12-month weather adjusted average for the period ending September 30. Over that time frame residential sales are basically flat compared to the same period a year earlier while commercial sales are up nearly 2%.

Finally industrial deliveries, which do not have a strong correlation with weather, increased 3% compared to the third quarter of 2013, driven by continued strength in most of our key industries, including steel, shale, refinery, electric manufacturing and chemical.

The industrial sales trend over the 12-month period through September 30th also reflects a 3% increase. As Chuck mentioned, we're very encouraged by the continued strength of the commercial and industrial sectors in our region.

And we remain optimistic that we are seeing signs of an authentic turnaround in the economy after the sharp declines that began in 2007 followed by long period of stagnation. Let’s look now at our transmission business. Third quarter operating earnings were $0.13 per share, unchanged from the third quarter of 2013.

Drivers in the quarter included higher transmission revenues as a result of the revenue requirement increases associated with ATSIs annual rate filing and higher capitalized financing costs related to our 'Energizing the Future' investment program. These were offset by higher vegetation management expenses and increased interest expense.

In our competitive business, third quarter operating earnings were $0.25 per share, compared to $0.24 per share in the third quarter 2013. Operating earnings benefited from lower operating and maintenance costs, a lower effective income tax rate partially offset by lower commodity margin and lower capitalized financing cost.

Commodity margin decreased operating earnings by $0.04 per share due primarily to lower contract sales volume and higher capacity expense partially offset by higher PJM capacity revenues. Additionally, while higher capacity rates resulted in higher contract sales prices, overall unit prices had a negative impact compared to the third quarter of 2013.

As we mentioned in the past, this can be traced back to the significant decline in market power prices that began in the fourth quarter of 2011, when we held a larger open position for 2014 relative to 2013.

Consistent with our strategy to reposition our sales portfolio, our overall retail customer account is now approximately 2.3 million, a decrease of about 400,000 compared to the third quarter of 2013. At the same time, total channel sales decreased 4.5 million megawatt hours or 16%.

This decline is intentional, as we focus on effectively hedging our generation and eliminating weather sensitive low. Sales to governmental aggregation customers decreased 14% due to lower sales and eliminate an Ohio driven by pure customers and lower usage due to milder whether.

Total generating output at our ongoing units increased 802,000 megawatt hours driven by fewer outrages at both our super critical coal units and nuclear fleet compared to third quarter of 2013. A strong generating output along with lower contract and wholesale sales resulted significantly lower purchase power costs.

Commodity margin also benefited from higher capacity revenues and lower MISO and PJM transmission costs, while higher net financial sales and purchases, which are used to hedge our exposure to market pricing congestion volatility reduced market.

The lower commodity margin was more than offset by a decrease in O&M resulting from lower retail and marketing-related expenses and decreased plant costs. Finally, I'd like to review the benefits we're seeing this year related to the effective tax rate.

On a consolidated basis the effective tax rate for the third quarter was 32.1% compared to 34.1% in the same period of 2013, resulting in an increase in consolidated earnings of $0.02 per share. The 2014 effective tax rate benefited from an IRS-approved adjustment that increased the tax bases in certain assets allowing for increased tax deductions.

This was partially offset by higher tax valuation allowances. On a year-to-date basis consolidated effective tax rate is 32.4% compared to 36.2% for the same period in 2013.

We continue to focus on managing our tax obligations through various federal and state planning initiatives and currently estimate our effective tax rate to be 30% to 31% for the year, primarily reflecting additional benefits in the fourth quarter resulting from the resolution of a state tax position.

Our 2013 effective tax rate was 36.2% and we anticipate our tax rate going forward to be between 36% to 38%. Before we move on to review of financing activity, I'd like to take a moment to review our 2014 operating earnings guidance.

As Tony mentioned earlier, we are reaffirming the range of $2.40 to $2.60 per share and at the same time making adjustments among the segments. I’ll walk you through these changes which are outlined on slide 154, the fact book that was posted to our website today.

First; in our distribution business, the impact of mild temperatures lower than the forecasted residential usage and increased non-deferred storm expenses bring that segment’s operating earnings to a new midpoint of a $1.93 per share for the year.

We also see improvement in our competitive business from lower operating costs bringing the midpoint up $0.03 to $0.20 per share, an improvement in our corporate segment, reflecting the favorable tax rate increases the midpoint $0.05 to a negative $0.17 per share and regulated transmission remains unchanged with the midpoint of $0.54 per share.

Finally, we continue to fund our transmission expansion program during the quarter through the issuance of $400 million of 30-year senior notes at ATSI in September. Also during the quarter, we re-marketed $241 million of pollution control revenue bonds at FirstEnergy generation and First Energy nuclear generation.

We remain pleased with the strong overall performance of our transmission and distribution businesses during the third quarter and first nine months of the year. We have a solid plan in place across our company to drive results and we're committing to creating value for investors. Now I'll open the call to your questions..

Thank you. (Operator instructions) Our first question is from Dan Eggers of Credit Suisse. Please go ahead..

Hey. Good afternoon guys..

Hello Dan..

Hey. There was huge matter of information. Thank you for all that. I guess, looking at the PPA or the ESP process in Ohio, something that’s come up and raised is the idea of the off-market transaction for 15 years in those assets.

Can you just kind of walk through, maybe a little more of the legal justification for beyond the obvious benefits to Ohio customers or the visibility?.

Hi, Dan. This is Leila. So obviously and proposing this, my legal team was very mindful of the legal precedence that was out there. I think from a policy perspective, we put forward a very wonderful case that we address that and then, I will go into more of the legal specifics.

If you think about these plans, especially Ohio plans build and service Ohio customers, Ohio jobs, Ohio tax saves. So from a standpoint of, whether this is something that is beneficial certainly from an economic standpoint is very beneficial.

Having this generation, as we justified on our filing also, over the 15-year period would provide essentially $2 million worth of benefits to customer, so acting like an insurance policy. From a legal perspective, if you think about the aggregate rule, Ohio is a competitive state. So we do not have captive customers.

So FERC has waived the rule, it applied to us. Also, we were very mindful of two of the other cases up there, being the -- hit the (indiscernible) case and the Hanna case.

And have put in place mechanisms within the case, so that we do not run or fall of the particular things in those cases that triggered FERC’s finding that they were legally informed. So, offline, we can go into the details.

But, again, the legal team is very mindful of that in the structure of the PPA proposal and what the commission can and can’t do and the terms and conditions actually associated with the PPA..

Okay. And I guess on the West Virginia settlement, the element that I haven’t gone through all of it, given the earnings day today. But the Harrison plant probating contributed as much or any on this that we’d expected on the first transfer.

Would this settlement help get the full value of that rate base uplift into earnings going forward?.

So, essentially, what this case did, so let me back up for a second so. In the Harrison transaction, we stipulated that case. In that agreement, we agreed to file this base rate case and so this is the case where we basically flipped what would have been surcharged into base rate.

So, essentially, all we did is take what we’ve covered in that revenue stream and flip it to base rate treatment. And then on top of that, the stipulation provides for an additional $15 million increase.

And in addition to that, roughly $48 million of our vegetation management surcharged, which should help with our distribution and reliability which is good in West Virginia but should help enhance that as we go forward.

The stipulation also provides for establishment of regulatory assets associated with mass investments in 2016 and ’17, and other different provisions from the company's perspective, which we believe is very good.

Again, this is a case that we filed as a result of a stipulation and I think -- prior stipulation and I think from a company standpoint, our customers’ standpoint is a very good result..

Okay. And just one last question just on the quarter.

With this lower demand with the weather and all that, how much benefit did you guys see out of the retail business despite reduced volatilities, is that kind of what helped on some of the earnings gap this quarter?.

Dan, this is Donny. In the main, what we saw obviously, there wasn’t a volatility issue that we faced in the first quarter. But we took advantage of a lot of the O&M savings. We’ve reduced the workforce and that sort of things, so that's really what flowed through for us in the quarter..

Okay. Thank you guys..

Thank you. The next question is from Paul Fremont of Jefferies. Please go ahead..

Thank you very much.

I guess my first question is, if I look at capacity performance and the potential hatter, how should we think of that relative to your PPA proposal in Ohio? Would you potentially rethink the offer in Ohio?.

Hi Paul. This is Leila. So we made our filing and we are going to go full with our filing. I think, having the potential for capacity performance proposal by PJM and if it gets eventually approved by FERC, will be even a more enhancement for Ohio customers. But we would not withdraw our ESP commitment.

I think overall the proposal by PJM is a positive development. But as I noted, I think there are ways that it could be improved. I think that they should consider with performance persistent pricing mechanism.

If you think about it in terms of the generation, the need for revenue and kind of the longer-term horizon, if it were to have a mechanism whereby year-to-year, the downside were kept by 5% generators, where we could get a better sense of what the capacitive pricing might be from year-to-year that would definitely be a positive development.

In the transitional years, we think it should be uncapped up to net cone, given that the markets, I think everybody’s account have not produced the revenues that most agreed that they should have.

We think that that would be a more appropriate place getting revenue to generators, so they can make the investment in their plans to increase reliability and a better balancing of the penalty structure. I think PJM approved upon it but we still think the penalty structure is a little bit more draconian than it should be at this point in time..

And when, Jim when you ran through corporate another, I guess corporate another is already benefiting this year from tax, from lower tax what should we think of -- in terms of corporate and other as sort of a better indication for a run rate?.

Okay, Paul. I’d said earlier our effective tax rate would be anywhere between 30% to 31% this year and its going to most likely move back up to the 36% to 38% of our range next year. So that that would be probably about $0.25 a share, Paul, and most of that flows through corporate another..

So a $0.25 per share increase off of the 17, right?.

That’s correct. No, not all of that will go to corporate but most of that would..

Okay. And in terms of the nuclear leases. The last nuclear leases if I recall you bought them in the range of like $1500 per KW.

Can you -- what type of a price did you pay for the most recent lease purchases?.

We haven’t disclosed that yet Paul. The transaction hasn’t completed yet. I can say I would say both parties are very comfortable with the price we paid. So that’s something we are ready to disclose at this point..

And the last question in West Virginia, was it a black box settlement or was there some agree to level of ROA?.

So the parties agreed to the $15 million increase in the other terms. The commission actually asked that we -- in our filing how we got to that. So you will see us part of the settlement. If you go to the exhibits, each of the parties will lay out how it got there. The company has not laid out the ROE associated with it. But there is an ROR number..

Thank you..

Thank you. The next question is from Jonathan Arnold of Deutsche Bank. Please go ahead..

Yeah. Good morning. Sorry, good afternoon guys..

Hi. Jonathan..

Hi.

Just a quick question on as we look at these adjusted EBITDA outlooks for the competitive business, am I right that this is a delta between the commodity margin and the EBITDA number is mainly O&M consistent -- and probably general taxes consistent with the earnings statement?.

That will be correct Jonathan..

Okay. So I guess my question is when you look at the 15 to 16 numbers the implied expense number goes down about $100 million between 15 and 16. And if you look at the run rate on 14, its down quite a bit more than that 15 or 14.

So can you just talk about how we think the components that bridges that as those numbers just seem quite big?.

Jonathan, this is Donny. Yeah I think if you take a look at the EBITDA from 15, if you’re trying do come up a walk from 15 to 16. In ’15, we’ve got a midpoint of $950 million. And then if you look at what the capacity revenue does from ‘15 to ‘16, it comes down about $225 million….

Yeah but….

And then we have improved margins about a dollar megawatt hour so that’s a positive about $80 million. And then other O&M and cost reductions, that’s about $100 million, gets you right to about $900 million for midpoint..

Okay. That was already my question, is there a $100 million of O&M saving embedded in that forecast, it sounds like the answers is yes..

Yes. That’s throughout and we have one last nuclear outage in the ‘16 timeframe and that especially helps..

Okay. Can you also bridge so that we’re in a $1.5 billion of non-GAAP O&M in a year-to-date through September and it’s been running about $400 million at least last quarter. So how does it got from that number down to the $1.250 billion or so implied in the ‘15 guidance? What are the big drivers there? I’m looking at the delta between….

Jon, it’s one or two have high rates, take it get back because there’s probably a lot of components to make that up, so I shall get back to you after the call..

Happy to do that..

Thank you. The next question is from Stephen Byrd of Morgan Stanley. Please go ahead..

Good afternoon..

Hello..

I wanted to explore the capacity performance penalty side of the equation and Leila, you touch briefly on it. Just curious if the ultimate roll ends up quite similar to the proposed penalty rule that PJM has laid out.

Would that as you assess kind of the risk reward of your fleet? Do you think that would likely lead you to think about some degree of asset shutdowns, not at all or how do you generally think about that the risk of penalties?.

So the penalty structure again, I think was mitigated from their prior proposal. But you can’t look at it in isolation, you have to look at the other moving pieces in parts. Right now, the coalition noted in their comments that right now if you had a single 12-hour too bleak, it could cause you to lose the equivalent of 71 days of revenue.

So there are both kind of things you need to look at and have a trade-off. If the pricing mechanism will raise in that color and you’re able to recover that level. You might be able to think a little more positively about that kind of penalty. So again, there are a lot of moving pieces in parts and I wouldn’t look at the penalty just in isolation..

Okay. Understood.

And then just thinking also about carbon regulation and how the different states might look at that, I was particularly interested in Pennsylvania and Ohio, is it your sense that there is some probability to those states who think about joining the regional carbon mechanism such as regi, do you think the states are more likely to resist the proposed regulations? What’s your general sense of those two states and how they are thinking about carbon?.

Stephen, this is Tony. I think at this point it’s a little too early to tell. I still think that each states evaluating and trying to understanding and comprehend the proposed rule and as well as trying to figure out whether or not the alternatives to them moving from to a mass kind of calculation would be easier for them to manage.

So, I think, at this point, everybody is trying to understand what’s going on, not clear where they are going to end up yet. And my senses is that until we better understand how this rules going to be applied in the options, it will be hard for any one of the states to otherwise indicate exactly which way they are intending to go..

That’s helpful. Thank you very much..

Thank you. The next question is from Angie Storozynski of Macquarie Capital. Please go ahead..

Thank you very much. I have two questions.

One is, so I’m clear in the guidance of 2016 the generation capacity that didn’t fear in either the original or incremental auction is assumed not to receive any capacity revenues?.

That’s correct, Angie..

Okay. And then second, I hope I misheard that one is, okay.

So there is a change in the effective tax rate between ‘14 and ’15, and what is the $0.25 of a swing? Is -- are you suggesting that the parent level drag increases from $0.17 to like $0.40? Jim?.

Yes. That’s right, Angie. That will be the range..

Okay.

But why is -- I mean, what was then the effective tax rate in ’13 when we have about $0.27 or $0.26 drag?.

I think the effective tax rate in ’13 was about 36%..

Okay. So it’s a same type of rate that you’re guiding for ’15 and beyond.

So why such a big delta?.

We have some additional debt outstanding and we have some of that debt had variable rates, so those rates could increase on that also Angie. So it’s primarily associated with additional interest costs..

Okay. Thank you..

Operator, we’ll take one more call..

Certainly, the next question is from Paul Patterson of Glenrock Associates. Please go ahead..

Good afternoon.

Can you hear me?.

Yes, Paul.

How are you?.

All right. There is some -- on slide 161 of the investor handbook. There is a large pension and OPEB cash flow item of $750 million to $550 million.

And I was wondering that wasn’t their last time and I’m wondering what’s the driver in that and why is there a cash benefit associated with that?.

Paul, this is Jim. What that slides referring to is that we looked at the discount rate at the end of the third quarter, which we traditionally do and we say what would be change to our GAAP earnings be, if that discount rate remain in effect till December 31.

So what that’s representing is a discount rate that goes from 5% down to a range of either 4.25% to 4.5%. That also takes into account a change in the mortality tables where the liability increases by 4%.

So that’s not a cash flow benefit, its just a change in the liability of our pension plan that we would have to report the impact to GAAP if the discount rates stays where it is today..

Okay. So, I mean, so in the sense, reconciliation of net income GAAP to FFO, this is a non-cash reversal..

That’s correct..

So, I guess, okay. I’ll have to follow up offline, I guess.

And the deferred taxes in ITC that went down by about $190 million, anything in particular there?.

This is Jon. This is primarily just utilization of some of our NOLs that are making up the difference. So that’s primarily the largest driver..

I mean, just two back on the CES EBITDA, there seems to be an other income decrease on slide 136 and I’m just wondering, what’s the driver there in 2016?.

That’s primarily lower earnings from some of the investments we have. We have an equity interest in a couple of different investments and we’re seeing lower earnings in that period, so that’s going to drive that down..

Okay. Thanks so much, guys..

Okay. Thanks everybody. Thanks for joining us today. If you didn’t have a chance to ask your questions, please contact our IR Department. We look forward to seeing many of you next week at the Annual EEI Financial Conference in Dallas.

As you heard today, we’re making solid progress on the initiatives that the designed to deliver predictable and sustainable growth at our regulated distribution and transmission businesses. And you will hear more at EEI of our future transmission investment opportunity.

In our competitive business, we’re implementing a sound strategy to reduce risk, while positioning the business for the future. At the same time, we continue to strongly advocate for market reforms that can better support much needed price stability and service reliability and we’re pleased to see growing momentum in support of these changes.

We’re building a foundation for long-term value and growth for our investors and we appreciate your continued support. Thanks and look forward to seeing you in Dallas..

Thanks everyone..

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