道明尼資源 (D) 2014 Q3 法說會逐字稿

Good morning, and welcome to Dominion's third-quarter earnings conference call. (Operator Instructions).

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. The 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 have 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 follow 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 the measure of our Company's performance that differ from those recognized by GAAP. Those measures include our third-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 the 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 have made on our growth plan.

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 the 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 in 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 the previously deferred 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 Trust. A reconciliation of operating earnings to reported earnings 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 its guidance range. Kilowatt hour sales were below expectations due to the milder than normal weather. Excluding weather, sales for the quarter were consistent with our 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 expectations 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 are pleased with our third-quarter and year-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 had $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 were $2.7 billion. And taking into account cash and short-term investments, we ended the quarter with liquidity of $2 billion. For statements of cash flow and liquidity, please see pages 14 and 25 of the earnings release kit.

Now moving to our financing plans, during the third quarter we issued $1 billion of mandatory convertible 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 144A 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 are always looking for opportunities to optimize our capital structure and lower our financing costs. During the third quarter we issued a notice of redemption for $685 million of hybrid junior subordinated debt, replacing it with a 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 rate environment.

Finally, we successfully completed the initial public offering of Limited Partner common units in 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 at an offering price which 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 from 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 7. Positive factors for the quarter compared to last year include higher revenues from our rider projects, higher earnings from our farmout transactions at Dominion Energy, sales growth at Virginia Power, a return to normal weather, and better margins from our merchant fleet due to existing hedges. Negative factors include a refueling 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 are up $0.15 per share or 6% over last year. Combining year-to-date operating earnings with the midpoint of our fourth-quarter guidance range and the year-to-date net weather hurt of $0.04, produces 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 prices for both years.

So let me summarize my financial review. Operating earnings were $0.93 per share for the third quarter of 2014. Excluding the $0.08 per share impact of mild weather, earnings would have been in the upper end of our guidance range. Our financing 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 to $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 the 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 will be among the best in class. We will also outline our planned drop-down strategy for DM, and outline how the cash flows from the future drop downs, Dominion's 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's shareholders. We hope you will be able to attend.

I will 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 OSHA recordables for Virginia Power are at an all-time historic low, while performance at the other business units is consistent with our targets for the year.

Our nuclear fleet 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 1,329 megawatt Warren County combined cycle plant is nearly complete, on schedule, and on budget. Startup and commissioning activities are underway, and all of the units have completed first fire and have successfully synchronized to the grid. The project is expected to be operational later this year.

Construction of the 1,358 megawatt combined cycle facility in Brunswick County is well underway. There are approximately 975 workers on site. The combustion turbines and generators have been set on their foundations, and construction of the air-cooled condenser is progressing. Overall construction is about 35% complete, and is on budget and on time for a mid-2016 commercial operation date.

We plan to submit a filing to the Virginia State Corporation Commission in the first half of next year for a CPCN and a rate rider for our next major generating project, another large, 3-on-1 combined cycle plant scheduled for service by 2019.

Construction is also on schedule for six solar projects totaling 139 megawatts purchased earlier this year from Recurrent Energy. There are over 1,300 workers on site, and 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 Selmer Project was placed into service on October 22. All of these California and Tennessee facilities are expected to reach commercial operation later this year. In the third quarter, Dominion announced agreements to acquire two additional solar projects in California. These acquisitions are under long-term power purchase agreements, and are expected to qualify for the federal Investment Tax Credit in 2015. Once constructed, these additional projects will bring our total solar generating portfolio to 274 megawatts.

At Dominion Virginia Power, we have a number of electric transmission projects at 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 Transmission's capital budget for growth projects, including NERC, RTEP, 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 for Dominion Energy continues as well. The Allegany Storage, Western Access I, and the Natrium to Market to market expansion projects will be in service tomorrow, all on time and on budget.

Since last year, we have announced nine producer outlet 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, and all are on time and on budget.

Since our last earnings call, Dominion Transmission signed an agreement for another farmout project, by which we allow producers in the Marcellus Basin to drill for gas in and around our storage pools. These projects provide multiple earning streams to Dominion, including payments for mineral rights, royalties on production, as well as transportation and potential processing business. This farmout covers 24,000 acres of Marcellus development rights beneath our Oakford storage field in Pennsylvania.

Our agreement provides for payments to DTI of approximately $120 million over four years, and a 5% overriding royalty interest in gas produced from the acreage. Portions of northern Pennsylvania have seen drilling attention from producers since two significant production wells were drilled by Shell in the deeper dry gas Utica formation. We have a number of storage reservoirs in this area, and are exploring additional farmout 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 and North Carolina.

The pipeline will support new electric generation being developed by Duke Energy and Virginia Power, as well as to support growing LDC gas demand. The pipeline will be owned by a joint venture of its principal customers. Dominion will own 45% and will be the constructor and operator of the pipeline. Duke Energy will own 40% and be the largest customer. Piedmont Natural Gas will own 10%. And AGL Resources, the parent of Virginia Natural Gas, will own 5%.

The 550-mile pipeline starts in West Virginia and crosses portions of Virginia and North Carolina, including some areas currently without gas service, terminating about 15 miles from the South Carolina border.

The estimated cost of the pipeline is $4.5 billion to $5 billion. Currently, about 91% of the 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 a 1.5 billion cubic feet per day pipeline, ACP is expandable to over 2 billion cubic feet per day with additional compression.

We will initiate the FERC prefiling process today, and expect to make the formal filing with FERC in September of next year. Assuming a normal timeframe for FERC approval, we expect to be able to begin construction during the fall of 2016 and be in service by November 2018. We have already hosted 13 town hall meetings, and surveyed 70% of the proposed route.

We have begun solicitations for several engineering and procurement activities, including the large diameter pipe procurement. We have received bids 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 policymakers to this critically important reliability project.

Concurrent with the open season for the Atlantic Coast Pipeline, we are 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 and about 40 miles of pipeline looping.

It is expected to have capacity of 1.5 billion cubic feet per day. The estimated cost of the project is $500 million, and 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 Utica permits have been issued, and 1,122 wells have been drilled, an increase of 50% in wells permitted and 65% in wells drilled so far this year. The number of producing wells has increased by 125%, from 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 to process 200 million cubic feet of natural gas per day, are in service. The third plant is scheduled to be operational this quarter, and a fourth plant is scheduled for early in the second quarter of next year. Blue Racer also plans a 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 at Natrium is also being 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 meeting.

Now an update on our Cove Point liquefaction project. On September 29, we received FERC 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. FERC issued authorizations for construction of off-site 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 contractor to begin construction activities that same day.

The project is estimated to cost between $3.4 billion and $3.8 billion, and is targeted to be in service in late 2017. As of September 30, the project is on budget; the engineering was 62% complete; and the procurement of critical equipment is on schedule.

So, to summarize, our businesses delivered strong operating and safety performance in the third quarter. The Warren County and Brunswick County construction projects are proceeding 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 Shale regions.

Dominion, along with its joint venture partners, will develop the Atlantic Coast Pipeline, a transformational infrastructure project to bring new supplies of natural gas to the southeastern United States.

We have also commenced an open season for the $500 million Supply Header Project. We have begun construction of the Cove Point liquefaction project. We launched Dominion Midstream Partners at the lowest yield in the history of operating MLP IPOs.

And, finally, we look forward to updating all of you on our long-term growth strategy for Dominion Resources and Dominion Midstream Partners at our February 9 analyst meeting in New York, with particular emphasis on both our potential earnings growth as well as dividend growth.

Thank you. And we are ready to take your questions.

(Operator Instructions). Michael Weinstein, UBS O'Connor.

Actually, Julien here. So, first, if you could talk real briefly, just focusing on the results actually quickly. What's the normalized number here for 2014, just broadly speaking, if you were to take out the weather impacts year-to-date?

I think he's asking, what's the weather impact year-to-date?

Yes, what's the weather impact year-to-date?

Weather is down about $0.04 to $0.05, Julien, to norm year-to-date.

Got you, excellent. And then secondly, just broadly, as you think about the opportunities before you, could you perhaps lay out a little bit of a timeline here for your pipelines, Atlantic? And perhaps just thought processes 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?

Julien, we have, across the pipeline business that Dominion East Ohio, Dominion Transmission, through the joint venture we now have with Atlantic Coast Pipeline; you've got the Blue Racer joint venture -- all of them have multiple opportunity to expand. The Atlantic Coast Pipeline itself, starting out at 1.5 billion cubic feet, can go to 2 billion cubic feet with not very much additional work. And the governors of West Virginia, Virginia, and North Carolina, are very excited about the economic development opportunities, having that new source of gas supply and reliability we'll provide those states.

So those are all areas -- the Marcellus and Utica we have are -- we have lots of storage assets where potential farmouts exist. But to get specifically to your question about the Northeast basin -- and one thing to consider is, sooner or later, Governor Cuomo will make some decision about fracking in New York State. Obviously we don't know how that will come out. We have a lot of assets in New York State. But specifically Northeast basin, that would be a difficult push for us, I think Julien, just to be frank about it. It's a long way from where we are, and would be difficult for us to compete with the other pipes.

And they have a very difficult chicken-and-egg problem in New England, as you all -- as everybody on the phone is aware. Atlantic Coast Pipeline, a perfect example: we have 20-year end user contracts, take-or-pay, and that's sufficient for us to get a FERC permit and justify the economics of the pipe. And that's a difficult thing in the New England market, to get that kind of assurance for a pipeline operator.

I hope that answers your question.

Yes. Just hitting the Atlantic Pipeline more directly, though. As you think about -- when you think you'd get some comfort on getting that incremental 0.5 billion a day of subscription? What are you looking for? Are there key RFPs out there that are the incremental subscribers?

I wouldn't pick out a particular date for you, Julien, but I think the pipeline won't come online until November 2018. To increase the capacity, even between now and then, just would take some additional compression. So there's lots to do. And you have governors out running around like crazy. You've got all these announcements in European countries moving manufacturing facilities to the United States because of low energy prices.

And, of course, you have the carbon rule coming, which will be final in about eight months. EPA has given every indication that they are going to issue the final rule next summer. You get one year to file your SIPs. So, long before this pipeline comes on operation, there's going to be a lot of clarity around the effects of the carbon rule.

Great, thank you.

Dan Eggers, Credit Suisse.

Tom, on the Marcellus farmout that you guys announced this quarter, can you maybe give a little more color on how many more acres of prospective projects you guys have that can fit into that bucket? And then with this project in particular, the $120 million over four years -- what is the cash flow, the earnings stream for you guys beyond four years?

Well, I'll let -- Mark can answer the question about the cash flows and earnings over the next -- after four years. You still have the royalty payments after that time. But we have -- I would just say it this way, Dan: the farmouts to date have been for Marcellus, so that's one thing to consider. We have not farmed out any Utica acreage, which is below the Marcellus in the same acreage.

And I think it's just easier to just say it this way: we have tens of thousands of acres, many tens of thousands of acres across the system.

As far as this particular farmout, Mark?

Yes, Dan, I think we showed on the slide, it's $120 million in terms of lease payments over the four-year period or so. All of the farmouts we have and that we're looking at are structured in a similar manner, where we will get multi-year payments for the opportunity to drill in and around our storage.

On top of that, we will have an ongoing royalty payment based on production coming out of the ground. And our hope is that we'll also be able to gather -- we'll have incremental revenues due to gathering; and, depending what the region is, potentially processing.

But we see four potential revenue streams from it. We'll have, in the fourth quarter here, about a $0.06 benefit from the initial lease payment. And that will continue, as I say, for another 3 to 4 years.

So you get $0.06 in the fourth quarter, and then it will normalize after that. So you get a one-time uplift, and then normal beyond that. Is that right, Mark?

Yes, I'd assume in the last three years of contract, for modeling purposes, I'd spread it.

Okay. And then I guess the next question, just on generation with the 2019 to-be-named-later CCGT. Where does that put you guys as far as -- is this being added to keep up with demand? Or is this still working against your short capacity position in Virginia?

Still working against the short capacity.

Tom, with your prospective changes in RPM rules, is there any motivation for you guys to look at maybe accelerating closing that short position, so you can get out of paying capacity back to PJM just because it gets 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 to our customers. Theoretically, I think we probably could have built all three -- we could have built Warren, Brunswick, and the 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, so we try to balance it so that the impacts are reasonable.

And I guess one last question. Solar investments have gone pretty well, it appears, from the outside. How are you guys thinking about that over the next couple of years? Is it going to accelerate, or have you guys thought about expanding that program from what the original targets were?

We've been looking very hard at solar. In February, we will give you an update on our longer-term strategy around solar. We have a lot of ideas on what to do with it, both in and out of our service territories, that we'll try to explain in more depth in February.

Okay. Thank you, guys.

Steven Fleishman, Wolfe Research.

Dan asked my main question. But just on the utility business, the -- could you just give us an update on when you need to file your next biennial, and how you feel about your positioning around the utility business?

The next biennial is due -- I guess it's March 30 -- or how many days are there in March? Whatever it is, the last day of March, of 2015. That's the normal cycle when we make the filing. And then the Commission has to issue an order, I think it's by December 1 of 2015.

Now, remember, it's the first we were -- we did not over earn in the last biennial review, so you have the 2013-2014 that will be reviewed. The year is not over; the two-year cycle is not over. We have had significant write-offs with the North Anna Plant, et cetera, and very mild weather.

But in order for there to be some base rate impact, you'd have to over earn in the 2013-2014 cycle and the 2015-2016 cycle, because it has to be two consecutive biennial reviews.

Great, thank you.

Greg Gordon, ISI Group.

Couple questions. I was just running some basic math off of your earnings book. If we normalize for weather, based on your disclosures, it looks like you would've been -- and I just want to make sure these numbers are right -- are like 269 at Dominion Virginia Power, weather normal for the quarter. And at Dominion Energy, you would've been -- sorry, Dominion Generation, you would've been at like 625. Do those numbers sound right on a weather normal basis?

Yes, I think if you look at -- I think that's in the range. We'll, off-line, get with you on the details for each of the business, Greg.

Okay, because I just want to baseline that as I look forward. And then my second question is on a completely different subject. On the Atlantic Coast Pipeline, I've gotten some pushback from people who cover E&P, saying that the cost of transporting gas on that pipeline, based on your construction costs, looks really prohibitive relative to the cost of moving gas on other new pipeline projects to other trunk lines for the producers.

And I know you say you're 90% subscribed, but you are 90% subscribed by consumers. So how was the transportation cost of this gas going to be dealt with? Should we assume that the LDCs on the consuming end of the pipe are going to bear some of the costs 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 whoever is giving you the pushback, and tell him they really don't have much idea what they're talking about. It was a very competitively bid pipeline. There were six bidders. The offtake contracts are from regulated utilities that will -- some of them power generation, some of them local gas distribution companies -- all of which will be dealt with through the regulatory process. But it's a very competitively priced pipeline, and the transportation costs are very competitive.

But I will let Paul Koonce give you more details.

Greg, I think one thing you need to recall is that this is straight fixed/variable rate design. So the variable cost to move gas is going essentially be the fuel costs only. So when producers are looking at the netback cost of 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.

Got you. Thank you very much.

Paul Fremont, Jefferies & Company.

First question is just simple math. If I take the $0.80 to $0.90, you are basically looking at an annual number that's going to be between $3.39 and $3.49. Is that a correct read for the full year?

I think that's a correct read.

Okay, because you're maintaining obviously a much wider guidance range, and I'm just not quite sure I understand why.

Yes, Paul, we have historically not changed our guidance range unless we were to fall outside of that guidance range, which I can't recall when we ever have. So we always try to put a guidance range out in the year that we feel comfortable we will land in.

And then the variables are typically for us, weather, up or down, and where you move in that range. And not knowing what the rest of this year would be weather-wise, we could move up or down in it. But we felt, based on what we knew today, and what the actual earnings were through the third quarter, that an $0.80 to $0.90 range was reasonable. Again, weather can move that higher, or weather could potentially move it lower, depending on how November and December turn out.

And then are you going to recognize any tax benefits from the closeout of IRS past-year audits in the fourth quarter? Or were those already recognized? It looks like, in the second quarter, you had a pretty good tax contribution.

Yes, we're not -- 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, if any, benefit from incremental audit closeout.

We're almost caught up. We're actually working on 2013 now. All the legacy years have been resolved with the IRS. So again, I would assume that that benefit would not be there in the fourth quarter as it might have been in previous years.

Also 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 2014 to the third quarter of 2013, it looks like it's $0.01 positive, but it's -- in your slide presentation, it's a negative driver.

Yes, 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 the two references.

And do you have any thoughts on potential new build announcements in New England? And have you looked at generation yourself as a potential investment opportunity in New England?

No, we have not. We've got enough to do with our pipeline and our regulated utility business. But I can see why others might be quite interested, but I think it falls outside our interest level at this point.

And last question for me, what was weather normalized growth in at VEPCO?

For the quarter? For the year? What --?

Well, year to date?

Okay. Weather normalized, 1% at VEPCO, right where it's been tracking here for the last several quarters. We had a very solid third quarter. And just 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 real good about the 1%. And, again, we see a growing improvement in sales as we go forward. And we think, year-end, we'll be right on that.

Thank you.

Jonathan Arnold, Deutsche Bank.

Question on what you've been saying about the analyst day. At the September conferences, I think you said you would be talking about the impact on long-term EPS and dividend growth of 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 firm up, 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 on both dividend and EPS growth rates. And we'll expand on that more in February.

All right, thank you. That was it.

Paul Patterson, Glenrock Associates.

Just a few quick follow-ups. On the demand side, there was an article indicating that there had been a delay for 60 days in an Alexandria, Virginia, underground line because of a difference, it seems, in terms of demand for -- or not a difference, but I guess it seems that there's a delay because you are waiting for PJM to come out with its demand forecast in December. And I guess there was some difference of opinion, perhaps, as to what the demand forecast might be in order to support the project. Could you talk about that a little bit?

Yes, Paul. Paul Koonce will deal with that.

Yes, good morning, Paul. You really -- we are aware that PJM every year puts out their forecast in December. We're getting so close to that time. Just to assure the community that our planning is solid, we're just going to wait for that forecast. We don't expect any change in plans. So, really, it's just a one of we're so close. There's been a lot of community dialogue about that. We just wanted to update it, and then we'll move forward.

Okay, I got you. Thanks for the clarity. And then in terms of being short, and the capacity performance of a product that's being proposed, I haven't seen your guys' specific comments on it -- and it may be just because I missed it because there's so many comments -- but how do you guys view that as basically a regulated utility short, it seems? How do you look at this capacity performance product from the Dominion, Virginia Power perspective? Any thoughts about that in terms of -- anything you can share with that, from your perspective?

Well, Dave Christian will handle that question.

Well, as you know, it's a work in progress. And we can certainly appreciate the efforts that PJM is undertaking to enhance the reliability of the system, in light of what happened during the polar vortex.

That said, we've been a participant and a 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 that has to do with the operational reliability of generation plays to our strengths. So we look forward to participating in that process, and we'll see what the outcome is.

There was a proposal by some states to have an FRR carveout. 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 is it just too early to say?

We look at the FRR carveout, and we evaluate that. But, frankly, as it relates to the 19 CC, we would see the exemption under self-supply is more likely the option.

Okay. I appreciate it. Thanks so much.

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