Thomas Hamlin – VP, IR and Financial Planning Mark McGettrick – EVP and CFO Tom Farrell – Chairman, President and CEO Paul Koonce – CEO, Energy Infrastructure Group David Christian – EVP and CEO, Dominion Generation Group

Julien Dumoulin-Smith – UBS Dan Eggers – Credit Suisse Steve Fleishman – Wolfe Research Paul Patterson – Glenrock Associates

Good morning and welcome to Dominion’s Third Quarter Earnings Conference Call. At this time, each of your lines is in a listen-only mode. At the conclusion of today’s presentation we will open the floor for questions. At that time instructions will be given as to the procedure to follow if you would like to ask a question. I would now like to turn the call over to Tom Hamlin, Vice President of Investor Relations and Financial Planning for the Safe Harbor statement.

Good morning and welcome to Dominion’s third quarter 2014 earnings conference call. During this call, we will refer to certain schedules included in this morning’s earnings release and pages from our earnings release kit. Schedules in the earnings release kit are intended to answer the more detailed questions pertaining to operating statistics and accounting. Investor Relations will be available after the call for any clarification of these schedules. If you’ve not done so, I encourage you to visit the Investor Relations page on our website, register for email alerts and view our third quarter earnings documents. Our website address is www.dom.com. In addition to the earnings release kit, we have included a slide presentation on our website that will guide this morning’s discussion. And now for the usual cautionary language, the earnings release and other matters that will be discussed on the call today may contain forward-looking statements and estimates that are subject to various risks and uncertainties. Please refer to our SEC filings, including our most recent Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for a discussion of factors that may cause results to differ from management’s projections, forecasts, estimates and expectations. Also on this call, we will discuss some measures of our company’s performance that differ from those recognized by GAAP. Those measures include our second quarter operating earnings and our operating earnings guidance for the fourth quarter and full year 2014, as well as operating earnings before interest and tax commonly referred to as EBIT. Reconciliation of such measures to most directly comparable GAAP financial measures, we are able to calculate and report are contained on Schedules 2 and 3 and Pages 8 and 9 in our earnings release kit. Joining us on the call this morning are our CEO, Tom Farrell; our CFO, Mark McGettrick and other members of our management team. Mark will discuss our earnings results for the third quarter and our earnings guidance for the fourth quarter and full year 2014. Tom will review our operating and regulatory activities and review the progress we’ve made on our growth plans. I will now turn the call over to Mark McGettrick.

Good morning. Dominion reported operating earnings of $0.93 per share for the third quarter of 2014, which was below the midpoint of our guidance range of $0.90 to $1.05 per share. Mild summer temperatures and low humidity in our service territory one of mildest summers in the last 30 years had a significant impact on electric sales and revenues reducing operating earnings by $0.08 per share compared to normal. Excluding the impact of weather, third quarter operating earnings would have been at the upper end of our guidance range. Positive factors during the quarter were lower than expected operating and maintenance expenses and lower than expected interest expenses. Offsetting these positives were lower kilowatt hour sales due to mild weather and lower merchant margins. On a year-to-date basis, our 2014 weather normalized operating earnings were $0.10 per share better than the first nine months of 2013. GAAP earnings were $0.90 per share for the third quarter. The principal difference between GAAP and operating earnings was a charge associated with a previously differed or capitalized cost related to a possible third unit at North Anna power station, offset by a number of items including higher returns from our nuclear decommissioning trusts. A reconciliation of operating earnings to reported earns can be found on Schedule 2 of the earnings release kit. Now moving to results by operating segment, at Dominion Virginia Power EBIT for the third quarter was $248 million which was below this guidance range. Kilowatt hour sales was below expectations due to the milder than normal weather. Excluding weather, sales for the quarter were consistent with a year-over-year expectation of 1% growth. Positive factors for the quarter were higher revenues from electric transmission and lower major storm and service restoration expenses. Dominion Generation produced EBIT of $572 million in the third quarter which was below its guidance range. EBIT from utility generation was below expectation due to lower than expected kilowatt hour sales and lower than expected revenues from ancillary services. EBIT from merchant generation was slightly below expectations due to lower margins. Third quarter EBIT for Dominion Energy was $236 million which was above the top of its guidance range. Higher transportation and storage revenues and lower operating expenses drove the strong results. On a consolidated basis, our effective tax rate was about 33% for the quarter which was in line with our guidance. Interest expenses were lower than our expectations. Overall, we were pleased with our third quarter –to-date operating results. Moving to cash flow and treasury activities, funds from operations were $2.8 billion for the first nine months of the year. We have $4.5 billion of credit facilities at the end of the third quarter. Commercial paper and letters of credit outstanding at the end of the quarter was $2.7 billion and taking into account cash and short term investments, we ended the quarter of liquidity $2 billion. For statements of cash flow and liquidity, please see page 14 and 25 of the earnings release kit. Now moving to our financing plans, during the third quarter we issued $1 billion of mandatory securities. The issue was very well received by the market and we thank those of you who participated. Also during the third quarter, we exchanged $1.2 billion of 144-A bonds issued by Dominion Gas Holdings last fall for registered securities. We expect another new debt issue of at least $1 billion for Dominion Gas in the fourth quarter. We were always looking for opportunities to optimize our capital structure and lower our financing cost. During the third quarter, we issued a notice of redemption for $685 million of hybrid junior subordinated debt replacing it with similar security in October which lowered our annual interest expense by about $18 million. We also called all of the remaining $134 million of outstanding Virginia Electric and Power Company preferred stock. You can expect us to undertake similar actions in the future to take advantage of the current interest environment. Finally, we successfully completed the initial public offering of limited partner common units and Dominion Midstream Partners earlier this month. Despite a volatile environment for stocks in general and MLPs in particular we were able to complete the transaction and offering price that translated into a record low IPO yield for an operating master limited partnership beating the previous record by nearly 40 basis points. Net proceeds of just under $400 million will be used to help fund construction of our Cove Point liquefaction project. Dominion Midstream Partners now trades on the New York Stock Exchange under the ticker DM and we have been pleased with its market performance since the offering. DM will make its first 10-Q filing in November and we plan to discuss its quarterly results and take questions for analysts covering the MLP during Dominion’s fourth quarter earnings conference call. Now to earnings guidance, our operating earnings guidance for the fourth quarter of 2014 is $0.80 to $0.90 per share compared to $0.80 per share for the fourth quarter of 2013. A breakdown of the positive and negative drivers of our guidance is shown on slide seven. Positive factors for the quarter compared to last year plus higher revenues from our lighter projects, higher earnings from our farm out transactions at Dominion Energy. Sales growth at Virginia Power a return to normal weather and better margins from a merchant fleet due to existing hedges. Negative factors include every fueling outage at Millstone Unit 3 and higher DD&A expenses. Our operating earnings guidance for the year remains, $3.35 to $3.65 per share. Through the first nine months of the year, operating earnings were up $0.15 per share or 6% over last year. Combining year-to-date operating earnings for the midpoint of our fourth quarter guidance range and the year-to-date net weather of $0.04 was full year projected operating earnings in the middle of our guidance range. As to hedging you can see our hedge position on page 27 of the earnings release kit since our last earnings call, we have made modest additions to our hedges at Millstone for both 2015 and 2016, improving the average weighted hedge value of prices for both years. So let me summarize our financial review. Operating earnings were $0.93 for the third quarter of 2014, excluding the $0.08 per share impact of mild weather, earnings would have been at the upper end of our guidance range. Our financings plans for the remainder of 2014 include a debt offering for Dominion Gas Holdings. Our operating earnings guidance for the fourth quarter of 2014 is $0.80 or $0.90 per share. Our operating earnings guidance for the full year remains $3.35 to $3.65 per share. And finally, we plan to host a meeting for analysts and investors on Monday February 9, in New York at Waldorf Astoria Hotel. At this meeting, we plan to discuss the long term growth strategy for both Dominion Resources and Dominion Midstream Partners. Given the longer term construction schedule for Cove Point and the Atlantic Coast Pipeline which we plan to contribute to the MLP, our presentation will cover our expectations beyond the normal five year time horizon. We will detail Dominion Midstream’s long term distribution growth rate which we believe were among the best in class. We will also outline our plant drop down strategy for DM and outlined how the cash flows from the future drop downs Dominion share of the LP units and our general partner interest will be used to enhance Dominion’s earnings and dividend growth rates. In addition, we expect MLP cash flows will allow us to strengthen our balance sheet. By addressing all of these areas in February, investors will readily see the significant incremental value the MLP affords to Dominion shareholder. We hope you’ll be able to attend. I’ll now turn the call over to Tom Farrell.

Good morning. Our business units delivered strong operational and safety performance in the third quarter. Year-to-date recordables for Dominion Power are at an all time historic low our performance at the other business units is consistent with our targets for the year. Our nuclear play continues to operate well. The net capacity factor of our six units was 94.4% for the first nine months of the year. We completed two refueling outages in the second quarter and are completing two more in the fourth quarter. We continue to make significant progress on our growth plan. Construction of the 1,300 29 megawatt Warren County combined cycle plant on plant and on budget. Start up and commissioning activities are underway and all of the units have completed first fire and have successfully synchronized for the grid. Project is expected to be operational later this year. Construction of the 1,358 megawatt combines cycle facility confronts with Brunswick County is well underway. There are approximately 975 workers on site the combustion turbines and generators have been set on their foundations and the construction of the air cools condensers is progressing. Overall construction is about 35% complete is on budget and on time for our mid 2016 commercial operation date. With plans to filing to the Virginia state corporation commission in the first half of next year for a CPCN and a rig rider for our next major generating project another large three on one combined cycle plant scheduled for service by 2019. Construction is also on schedule for six schedule projects totaling 139 megawatts purchased earlier this year from the current energy. There are over 1,300 workers on site in construction is well underway 100% of the posts are installed and over 96% of the 1.3 million solar panels are in place. We continue to make progress on our two Tennessee solar projects as well. The summer project was placed in service on October 22nd. All of these California and Tennessee facilities are expected to reach commercial operation later this year. In the third quarter, Dominion part two additional solar projects in California. These acquisition on the long term purchase agreements and are expected to qualify for the federal investment tax credit in 2015. Once constructed these additional projects will bring our total generating portfolio 274 megawatts. At Dominion Virginia Electric Power we have a number of electric transmission projects of various stages of regulatory approval and construction. During the third quarter 187 million of transmission assets were placed into service. The year-to-date in service total is almost 700 million and we expect to place over $900 million of new transmission assets into service by the end of this year. Electric transmissions capital budget for growth projects including maintenance as well as security related investments will average over $600 million per year through at least the remainder of the decade. Progress on our growth plan continues as well. The Allegheny Storage, Western Access 1 and Natrium to Market expansion projects will be in service tomorrow all on time and on budget. Since last year we have announced nine produced round of projects totaling nearly 2 billion cubic feet per day of capacity. Of the nine four have been placed into service with the fifth expected tomorrow. The remaining four will be in service by year end 2016. They all were on time and on budget. Since our last earning call, Dominion Transmission signed an agreement for another farmout project from which we allow producers in the Marcellus Basin to drill for gas in and around our storage wells. These projects provide multiple earnings stream for Dominion including famous for mineral rights royalties on productions as well as transportation and potential processing business. This farm out covers 24,000 acres of Marcellus development rights and these are upward storage period in Pennsylvania. Our agreement provides payments to DTI of approximately $120 million over four years and a 5% overwriting royalty interest in gas produced in the acreage. Portions of Northern Pennsylvania has seen drilling attention from producers since two significant production wells were drilled by shale in the deeper dry gas Utica formation. We have a number of storage reservoirs in this area and in order to exploring additional farm out opportunities. In September, we announced the Atlantic Coast Pipeline a transformational infrastructure project designed to bring much needed natural gas supply and reliability to utilities in Virginia in North Carolina. The pipeline would support new electric generation being developed by Duke Energy and Virginia Power as well as to support growing LDC gas demand. The pipeline would be on by joint venture of its principal customers the mineral own 5% will be the constructor and the operator of the pipeline. Duke Energy will own 40% and be the largest customer. Piedmont Natural Gas will own 10% and AGL Resources of Virginia Natural Gas will own 5%. The 550 mile pipeline starts in West Virginia and passes portions of Virginia and North Carolina including some areas currently without gas service terminating about 50 miles from the south Carolina border. The estimated cost of the pipeline was 4.5 5 billion. Currently about 91% of 1.5 billion cubic feet per day initial capacity of the pipeline will be under 20 year firm contracts with the four owners of the joint venture as well as public service company of North Carolina. Last week we began a binding open season for the remainder of the capacity. While initially 1.5 billion cubic feet per day ACP is expandable to over 2 billion cubic feet per day with additional pressure. We will initiate the first three filing process today and expect to make the formal filing with in September of next year. Assuming a normal timeframe for approval we expect to be able to begin construction through the fall of 2016 and be in service by November 2018. We’ve already hosted 13 town hall meetings and surveyed 70% of the . We have begun solicitations for several engineering and procurement activities including large diameter pipe. We have received this and expect to award these long lead items by year-end. We are pleased with the progress to-date and with the reaction of public policy makers to this critically important reliability project. In current with the open season for the Atlantic Coast Pipeline, we were also conducting a binding open season for a related wholly owned Dominion transmission opportunity called the supply header project. As envisioned in our open season announcement this project is designed to connect the origination point of the Atlantic Coast Pipeline with five supply points using expanded compression about 40 miles of pipeline looping. It is expected to have capacity of 1.5 billion cubic feet per day. The estimated cost of project is $500 million and it will be in service at the same time as the pipeline. The ACP customers have all expressed interest in taking capacity on the supply header project. The Utica region continues to be very active. Through the middle of October a total of 1,560 horizontal unit permits have been issued and 1,122 wells have been drilled, an increase of 50% wells permitted 65% wells drilled so far this year. The number of producing wells has increased by 125% of 270 to 607 so far this year. Our Blue Racer joint venture continues to execute its business plan. Currently two processing facilities each with the capacity process 200 million cubic feet of natural gas per day or in service. The third plant was scheduled to be operational this quarter and the fourth plant is scheduled for early in the second quarter of next year. Blue Racer is also planned for fifth processing plant which is expected to be in service in September of next year bringing its total processing capacity to 1 billion cubic feet per day. Fractionation capacity also been expanded from 46,000 barrels per day to 123,000 barrels that project will be completed in the second quarter of next year. We are very pleased with the success of Blue Racer and will provide an updated business plan at our February Analyst meet. Now an update on our Cove Point Liquefaction project, in September 29 we received court approval to construct and operate Cove Point. The order contains 79 conditions which were identified as part of the environmental assessment. We accepted the order the following day, Berk issued authorizations for construction of offside areas A and B and we began activities immediately. On Wednesday we received authorization to begin initial site preparation at the terminal itself. We authorized our EPC contract to begin construction activities that same day. The project is estimated cost of 3.4 to 3.8 billion and it’s targeted to be in service in late 2017. As of September 30, the projects on budget the engineering was 62% complete and a procurement of critical equipment is on schedule. So to summarize our business has delivered strong operating and safety performance. The Warren County and Brunswick County construction projects are perceiving on time and on budget. Our Blue Racer joint venture Dominion East Ohio and Dominion Transmission continue to capitalize on the growth opportunities in the Marcellus and Utica share regions. Dominion along with its joint venture partner will develop the Atlantic Coast Pipeline a transformational infrastructure project to bring new supplies of natural gas to the Southeastern United States. We’ve also commenced an open season for the $500 million applied at a project. We have begun construction of the Cove Point with the fractio we lost Dominion Midstream partners at the lowest yield in the history of operating MLP IPO. And finally we look forward to updating all of you on our long term growth strategy for Dominion Resources and Dominion Midstream Partners Analyst Meeting in New York with particular emphasis on both our potential earnings growth as well dividends for us. Thank you and we are ready to take your questions.

Thank you. [Operator Instructions]. Our first question will come from Michael Weinstein with UBC O’Connor. Julien Dumoulin-Smith – UBS: Actually, Julien here. So first if you could talk really briefly just focusing on the results actually quickly what is the normalize number you hear for 2014 just broadly speaking. If you were to kind of take out those weather impacts year-to-date?

Weather is down about 4 to 5 times Julien so no to you today. Julien Dumoulin-Smith – UBS: Gotcha. Excellent. And then secondly just broadly as you think about the opportunities before could you perhaps lay out a little bit time on here for your pipelines Atlantic and perhaps thought process about future pipes and opportunities across your footprint. I’m thinking specifically here is there an opportunity to address Northeast basis given your coverage into that market as well. We have crossed the pipeline business at Dominion East Ohio Dominion Transmission through the joint venture we now have Atlantic Coast Pipeline you get the Blue Racer joint venture all of them have multiple opportunity to expand the Atlantic Coast Pipeline itself is starting off 1.5 it can go to 2 but not very much additional work. The governors of West Virginia North Carolina a lot of people about very excited about the economic development opportunities having that new source of gas supply and reliability pool will provide those state. So those are all areas Marcellus and Utica we have lots of storage assets where potential farm outs exists. But I guess specifically your question about the northeast base one thing sooner or later form will make some decision about fracing in New York states obviously we don’t know how that will come out. We have a lot of asset in New York state but specifically Northeast Basin that would be difficult push for us I think really just to be frank about it, it’s a long way from where we are and it would be difficult for us to compete other pipes. And they have a very difficult chicken and egg problem into England as everybody on the phone is aware. Atlantic Coast Pipeline is a perfect example we have 20 year NGUs and contracts take or pay and that’s sufficient for us to get a permit and just by the economics of the pipe and that’s a difficult thing in the New England market to get that kind of assurance but pipeline operator. Hope that answers your question? Julien Dumoulin-Smith – UBS: Yeah. Just hitting the Atlantic Pipeline more directly though as you think about when do you think you’d get some comfort on getting that incremental half of subscription what are you looking for are there key RSPs out there that are kind of the incremental subscribers? I wouldn’t take out a particular date for you Julien but I think the pipeline won’t come online until November of ‘18 to increase the capacity even between now and then just to take some additional compression. So there’s lots to do and you have governors running around like crazy you got all these announcements in the European countries moving manufacturing slows the United States because of oil energy prices. And of course the other carbon role coming which shall be final in about eight months EPA has given every indication that they are going to issue not completing like summer. You get one year to file your steps so long people this pipeline comes off there is going to be a lot of clarity around the effects of getting from a card breakdown. Julien Dumoulin-Smith – UBS: Great. Thank you.

Thank you. Our next question will come from Dan Eggers with Credit Suisse. Dan Eggers – Credit Suisse: Tom on the Marcellus farmout you guys announced this quarter can you may be give little more color on how many more acres are expected you projects you guys have been considering in that bucket and then with this project in particular the 120 million over four years where is the cash flow the earnings from you guys beyond four years?

I’ll let Mark can answer the question about cash flow and earnings after four years we still have the royalty payments after that time. But we have I’d just say at this point Dan the farmouts today have been the Marcellus so that’s one thing to concern we have not form about any Utica acreage which is below the Marcellus and the same acreage. And I think it’s easier to just say thing where have we tens of thousands acreage across the system as far as this particular farmout Mark?

Yeah, Dan I think we showed it on slide, $120 million in terms of lease payments, over the four year period or so, all of the farm outs we have and that we’re looking at are structured in a similar manner where we’ll get multi-year payments for the opportunity to drill in and around the storage. On top of that, we’ll have an ongoing royalty payment based on a production coming out of the ground and our hope is that we’ll also be able to gather, we’ll have incremental revenues in gathering and depending on what region is potentially processing. But we see four potential revenue streams from it. We’ll have it in fourth quarter here about a $0.06 benefit from the initial lease payment and that will continue to say for another three to four years. Dan Egger – Credit Suisse: So you get $0.06 in the fourth quarter and then it will normalize after that one time uplift and then normal beyond that mark?

I’d assume in the last three years of contract for modeling purposes I’ll spread it. Dan Egger – Credit Suisse: I guess the next question is kind of on generation with 2019 [inaudible]. Where does that put you guys, as far as is this being added to keep up with demand or is it still working against your short capacity in Virginia?

Working against the short capacity. Dan Egger – Credit Suisse: Tom your perspective changes in RPM rules, is there any motivation for you to look at may be accelerating that short position so that you can get out of paying capacity back to PJM because it’s more expensive?

Dan we’re always looking at these things. You can look at our IRP there’s a variety of alternatives there. We’re trying to balance the needs for reliability against the increased cost of our customers. I mean theoretically I think we probably could have built all three, we could have built Warren, Brunswick 2019 CC all at the same time and we could have justified that I think. I’m sure we could have justified that. But that would have had a very significant impact on our customers. We try to balance it so that the impacts are reasonable. Dan Egger – Credit Suisse: I guess one last question solar investments have gone pretty well in the outside. How are you guys thinking about that over the next couple of years, is it going to be accelerate or have you guys thought about expanding that program from what the original targets were?

We’ve been looking very hard at solar and I think leave it, in February we will give you an update on our longer term strategy around solar. We have a lot of ideas what to do with it both in and out of our service territory, that we’ll try to explain in more depth in February. Dan Egger – Credit Suisse: Okay. Thank you, guys.

Thank you. Our next question will come from Steve Fleishman with Wolfe Research. Steve Fleishman – Wolfe Research: Hi, thanks. Dan asked my main question, but I guess just on the utility business. Could you just give us an update kind of the when you need to file your next Biennial and how you feel about your composition around the utility business?

Good morning. The next Biennial is due I guess it’s March 30th how many days are there March, whatever it is, last day of March of 2015 and investment normal cycle when we make the filing and then the commission order I think it’s by December 1st, ‘15. I remember at first we were – we did not over earn in the last Biennial Review, so you have the ‘13 ‘14 that will be reviewed year is not over, the two year cycles not over. We have had significant write-offs with the North Anna plant etcetera and very mild weather. But in order for there to be some base rate impact, you’d have to over earn in ‘13 ‘14 cycle and the ‘15 ‘16 cycle. It has to be two consecutive Biennial Review. Steve Fleishman – Wolfe Research: Great. Thank you.

Thank you. Our next question will come from Greg Gordon with ISI Group. Greg Gordon – ISI Group Inc.: Thanks. Good morning guys. Couple of questions, I was just running some basic math off of your earnings book, if we normalize for weather based on your disclosures you would have been I just want to make sure these numbers are right 269 at the Virginia Power weather normal for the quarter and that Dominion Generation you would have been 625? Those numbers sound right on a weather normal basis?

If you look at, I think that’s in the range. Offline we’ll get with you on the details for each of the business, Greg. Greg Gordon – ISI Group Inc.: Okay, because I just want to baseline that as I look forward. And then my second question is on completely different subject, on the Atlantic Coast pipeline, we’ve gotten some push back from people who cover E&P are saying the cost of transporting gas on that pipeline based on your costs looks really prohibitive relative to the cost of moving gas on other new pipeline projects, few other trunk mines for the producers. I know you say you’re 90% subscribed but you’re 90% subscribed by consumers. So how is the transportation cost of this gas going to be dealt with? Should we assume that the LBCs on the consuming end of the pipe are going to bear some of the cost of transportation if indeed, the producers can move the gas cheaper on other pipes?

Greg, I think the short answer is I’d go back to a year whoever is giving you the pushback you tell them they really don’t have much idea what they’re talking about. It was very competitively fit pipeline, there were six bidders. The off-take contracts are from regulated utilities that some of them power generation, some of them local gas distribution companies all of which will be dealt with in the regulatory process. But it is a very competitively priced pipeline and the transportation costs are very competitive. Let Paul Koonce give you more detail.

Greg, I think one thing you need to recall is that this is straight rate design, so the variable costs to move gas, is essentially going to be the fuel cost. So when producers are looking at the net back transporting on this line it will be enormously competitive because the customers who have contracted for the capacity are really paying the demand charges, the producers aren’t paying anything. Greg Gordon – ISI Group Inc.: Gotcha. Thank you very much.

Thank you. Our next question will come from Paul Fremont with Jefferies and Company. Paul Freemont – Jeffries & Co.: Thank you very much. I guess first question is just I guess simple math, if I take the $0.80 to $0.90, you’re basically looking at an annual number that is going to be between, $3.39 and $3.49. I mean is that a current read for the full year?

I think that’s a correct read. Paul Freemont – Jeffries & Co.: Okay, because you’re maintaining obviously a much wider guidance range and I’m just not quite sure I understand why.

Yeah Paul, we have historically not changed our guidance range unless we were to fall outside of our guidance range which I can’t recall that we ever have. So we always try to put a guidance range out in the way we feel comfortable in land-in and then the variables typically for us weather up or down or where you move in that range, and not know what the rest of this year would be weather wise we could move up or down in it. But we feel what we knew today and what the actual earnings were in the third quarter, then the $0.80 and $0.90 range was reasonable. Again weather can move that higher or weather can potentially move it lower, depending on how November and December turn out. Paul Freemont – Jeffries & Co.: And then are you going to recognize any tax benefits from the close out of IRS past year audits in the fourth quarter and were those already recognized? It looks like in the second quarter you had a pretty good tax contribution.

Over the last couple of years, Paul, we have been very fortunate to have closed out a number of legacy IRS audits to our benefit most of that work is done. So I would not expect in the fourth quarter to have much of any benefit from incremental audit close out. We’re almost caught up. We’re actually working on 2013 all the legacy years and resolve the IRS. Again, I would assume that benefit would not be there in the fourth quarter as it might have been in previous years. Paul Freemont – Jeffries & Co.: I’m a little confused on whether the merchant generation margin is up or down because if you look at page 10 of your reconciliation for the third quarter ‘13 it looks like it’s a penny positive but it’s in your slide presentation it’s a negative driver.

Yeah, quarter over quarter, it was higher than last year but it was slightly lower than what was in our guidance. So that’s the difference between two references. Paul Freemont – Jeffries & Co.: And do you have any thoughts on potential new build announcements in New England and have you looked at sort of generation yourself at a potential investment opportunity in New England.

No we have not. We got enough to do with our pipeline and our regulated utility business but I can see why others might be interested. But I think Paul it’s outside our interest level at this point. Paul Freemont – Jeffries & Co.: And last question for me, what was weather normalized growth at VEPCO?

For the quarter, for the year? Paul Freemont – Jeffries & Co.: Year-to-date?

Okay. Weather normalized, 1% at VEPCO right where it’s been tracking here for the past several quarters. We had a very solid third quarter and just kind of a quick synopsis of it. Residential has been very solid the whole year, commercial has been flat to slightly negative aside from data centers and industrial has been very solid so we feel really good about the 1% and again we see a growing improvement in sales as we go forward. I think year end we’ll be right on that. Paul Freemont – Jeffries & Co.: Thank you.

Thank you. Our next question will come from Jonathan Arnold with Deutsche Bank. Jonathan Arnold – Deutsche Bank: Good morning, guys.

Good morning, Jonathan. Jonathan Arnold – Deutsche Bank: Question on what you’ve been saying about the Analyst Day, on the September conference you said you would be talking about long term EPS and dividend growth and the MLP and just the strategy generally. And then I think on today’s call I think I heard you use the word enhance the long term growth rate which I haven’t heard you say before. So I guess my question is, does enhance mean firmer or does it mean potentially increase?

Well we’ll talk about this more in February but as we’ve looked at the cash flows over the past six months or so, that are going to be distributed out of the MLP we are very bullish both dividend and EPS growth rates and we’ll expand on that more in February. Jonathan Arnold – Deutsche Bank: Right. Thank you. That was it.

Thank you.

Thank you. Our last question will come from Paul Patterson with Glenrock Associates. Paul Patterson – Glenrock Associates: Good morning.

Good morning. Paul Patterson – Glenrock Associates: Just a few quick follow ups. On the demand side, there was an article indicating that there has been a delay of 60 days in an Virginia underground mine because of a difference it seems in terms of demand not a different but I guess there is a delay because I guess it seems that there is a delay because you’re waiting for PJM to come out with its demand forecast in December and I guess there was some difference within your perhaps what the demand forecast might be in order to support the project. Could you talk about that little bit?

I’ll let Paul Koonce will deal with that.

Yeah good morning Paul. We are aware that PJM every year puts out their forecast in December we’re getting so closed to that time. Just to assure the community that our planting is solid. We’re just going to wait for our forecast. We don’t expect any change in plans so really it’s just one we’re so close. There’s been a lot of community dialogue about that. We just want to move forward. Paul Patterson – Glenrock Associates: Okay. I gotcha. Thanks for the clarity. Then in terms of being short and the capacity performance product that’s been proposed, I haven’t seen you guys specific comments on it and may be because I missed it, because there is so many comments. But how do you guys view that as basically regulated utility short that seems how do you look at those capacity performance product from the Virginia power perspective? Any thoughts about that in terms of, anything you can share about that from your perspective?

I’ll let Christian handle that question.

As you know that’s a work in progress and we can certainly appreciate the efforts the PJM is undertaking to enhance the reliability in light of what happened during the polar vortex. That said, we’ve been participant and stakeholder in that process and we believe that, PJM is receptive to some of the comments that we have made. I’ll note that in our performance last year during the polar vortex was far better than PJM as a whole and anything they come up with it has to do with the operational reliability generation plays to our strength. So we look forward to participating in that process and we’ll see what the outcome is. Paul Patterson – Glenrock Associates: There was a proposal by some state to have an FRR carve out and I was just wondering with the amount of capacity that you guys have been adding and what have you, is that something you guys might think about or was it just too early to say?

We look at the FRR carve out and we evaluate that but frankly as it relates to the 19cc we would see the exemption under self supply is more likely the option. Paul Patterson – Glenrock Associates: Okay. I appreciate. Thanks so much.

Thank you. This does conclude this morning’s teleconference. You may disconnect your lines and enjoy your day.