Good morning, and welcome to Dominion's Third Quarter Earnings Conference Call. On the call today, we have Tom Farrell, CEO, and other members of senior management. [Operator Instructions] I would now like to turn the call over to Tom Hamlin, Vice President of Investor Relations, for Safe Harbor statement.

Good morning, and welcome to Dominion's Third Quarter 2011 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 have not done so, I encourage you to visit our website, register for email alerts and view our third quarter 2011 earnings documents. Our website address is www.dom.com/investors. 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 third quarter operating earnings and our operating earnings guidance for the fourth quarter and full year 2011, 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 were able to calculate and report are contained 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 begin with a discussion of the earnings results for the third quarter, as well as our guidance for the fourth quarter. Tom will discuss our operating and regulatory activities, as well as our plans for the dividend. We will then take your questions. I will now turn the call over to Mark McGettrick.

Good morning, everyone, and thank you for joining us. Dominion had a strong third quarter. Operating earnings were $0.95 per share, which were at the midpoint of our earnings guidance range of $0.90 to $1 per share. Weather helped the quarter's earnings by about $0.06 per share, but some of this benefit was offset by lower revenues due to the loss of electric service caused by hurricane Irene. Restoration costs associated with this hurricane totaled $133 million, and the non-capitalized portions have been excluded from operating earnings. The last storm for which we took a non-operating charge to our electric business was hurricane Isabel in 2003. GAAP earnings were $0.69 per share for the third quarter. About half the difference between GAAP and operating earnings for the quarter was due to the charges related to hurricane Irene. Other factors included a write-down of the value of our CAIR-related emission allowances and the incremental inspection expenses at North Anna due to the August 23 earthquake. A summary and reconciliation of GAAP to operating earnings can be found on Schedules 2 and 3 of the earnings release kit. Now moving to the results by operating segment. At Dominion Virginia Power, EBIT for the third quarter was $263 million, near the top of our guidance range of $230 million to $270 million. Favorable weather, management of our normal distribution O&M expenses and the execution of our transmission growth plan supported this strong performance. Like other retailers who operate in Texas, our Dominion Retail business was challenged as a result of the extreme heat in July and August. Because we are gauged exclusively in residential and small commercial retail sales, and because of our hedging practices, we are not exposed to wholesale trading losses. However, at times, it was necessary to purchase power at…

Good morning. During the third quarter, Dominion's employees were twice challenged by Mother Nature, not just in the same quarter, but actually during the same week. We've done some research and cannot find an occasion during this century or the last, when a particular area was hit by both a significant earthquake and a major hurricane within a 7-day period. While we had time to prepare for hurricane Irene, there is no advance warning for an earthquake. However, in both cases, Dominion's employees responded to the emergency safely and professionally, and I'm proud of their efforts. On August 23, a 5.8 magnitude earthquake hit the eastern United States. The epicenter of the quake was just 11 miles from our North Anna nuclear power station. Sensors at this station immediately triggered an automatic shutdown of both units, just as they were designed to do. The quake also impacted the transformers that connect the plant to the grid. Diesel generators at the plant powered the necessary safety-related systems until off-site power was restored. Both units at North Anna are shut down and in safe condition. Inspections by engineering since the earthquake occurred have found no significant damage to any nuclear structures, equipment, pipes, valves, pumps, the Lake Anna dam or any safety-related equipment. We have notified the Nuclear Regulatory Commission that Unit 1 is ready for restart as soon as the Commission is satisfied that it can be done so safely. Additionally, the fall refueling outage for Unit 2 was advanced and completed during the shutdown and it is also ready for restart. Two teams of inspectors from the Nuclear Regulatory Commission have conducted their own walk-downs and posted seismic event inspections. At a public meeting in early October, the NRC said that Dominion responded appropriately after the earthquake shut down the…

[Operator Instructions] Our first question comes from Daniel Eggers with Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Tom, I wondered if you could just walk through the time frame for the process for getting the approvals and what plans are going to be reinvested and which one's are going to close on the coal side and in the construction of a replacement gas generation kind of when those approvals occur? And when the capital will start to get spent?

Dan, I'm sure you saw that the -- I'm sure everybody saw that EPA has now delayed the HAP's final regulations about a month to the middle of December, so they will still become effective starting 2012, which gives you 3 years for compliance and the possibility for additional year. And there's lots of things under consideration by the EPA to give some more flexibility on timing. That remains to be seen. Our conclusion from looking the draft regulations, and it's pretty consistent, actually, where we thought they would come out as long as a year ago, that it is in our customers' best interest to close our 2 -- or several of our coal plants at Chesapeake, which is in far eastern Virginia. And one of our coal plants in Yorktown and convert one of those smaller plants to gas. So we have -- to deal with the HAP regulation, we have 3 solutions: We will put on -- or expect to put on pollution control equipment at 2 large oil units. That's about $300 million. That will take place over the course of the 2012 through 2015-period; we will seek to convert one of the Yorktown plants to natural gas, it's a much smaller project; we will enhance or expand our electric transmission projects by adding another $300 million project above and beyond what was already in our plans, to get electricity down to eastern Virginia, to replace the missing coal plants; and then the capacity will have to be covered with a 1,300 megawatt, we expect to be three-on-one gas-fired plant that would be very similar to the Warren County -- or identical to the Warren County facility. Just actually, I guess it was this week, it was either earlier this week or late last week, we got zoning approval in Brunswick County, Virginia which is south of Richmond, where we would put that plant. So that plant will cost around $1.2 billion. If you add that up, it's $1.8 billion, that will all be spread out over the 2012 through 2016 period. Dan Eggers - Crédit Suisse AG, Research Division: Great. And then on the -- we've seen some movement, I guess, recently in consolidation -- further consolidation in the natural gas infrastructure business. Is that doing anything to impact what you guys already worry about, greater competition and maybe lower cost of capitals, as those guys have more scale, or is that impacting anything you guys see in the market?

We don't see that, Dan. We're obviously, we're watching it with interest. We see very -- investors are giving a lot of value to midstream assets. And they should. They're valuable, particularly in this region. We've been competing in this region for 75 years. We don't think the consolidation that we've seen so far will have any impact on our projects. We have a tremendous amount of interest. Dan Eggers - Crédit Suisse AG, Research Division: Got it. And I guess this is the last question. As far as treatment on the storm cost from Irene, is there any way to recover that, or what is the process for recovering that, and how will that -- would you just remind us how that's going to affect the next biennial review for earned ROEs?

The cost -- the biennial reviews are done on GAAP earnings. So that charge will be reflected in our 2011 GAAP earnings. And that will be taken into account in the 2011 and 2012 biennial review. It's possible that if we earned below the allowed band, that we would seek a rate increase to help recover those. If we recover within the band -- if we earn within the band, then they'll be taken into account, those charges will be taken into account, deducted from our earnings and reflected in the earnings band that would be reviewed in 2013.

Our next question comes from Paul Patterson with Glenrock Associates.

Just wanted to touch base with you on the write-down associated with the emissions. Could you elaborate a little bit on that?

Paul, this is Mark. What that relates to is that we had excess emission allowances in our banks that we got through the CAIR program. And because CAIR is going to expire in terms of the value at the end of this year, we calculated how many allowances we would need between now and the end of the year, and those excess, we wrote off.

Okay. Then the share repurchase, you're not going to go through with the extra $100 million, is that just simply because the earnings are coming in sufficient that there's just no need for it? Or is there something else going on that we should think about?

No, what we always said on that, Paul, is that this was really a '12 issue for us, that we were trying to ensure that we can grow 5% to 6% on '12, and because of the loss of some tax deductions and a lower, wider rate base that we want to ensure we could make that commitment to our shareholders, and we believe we don't need to buy back that incremental to do that, that we can cover any shortfall from bonus depreciations through the initial buyback that we've had.

Okay, great. And then finally, the interest expense. Looks like it's going to be falling in Q4 relative to Q3, a little bit more than I would've thought. Just any sense as to what's going on there. Is it just simply refinancing or something. Could you let us know what's going on there?

We've taken advantage of some of these extraordinary rates that are out there, actually over the last couple of years as we've locked in. So I would call it its normal course.

Our next question comes from Greg Gordon with ISI Group.

So we'll just -- you guys look like you were remarkably successful in getting -- well, you were clearly remarkably successfully in getting good hedged pricing on the incremental hedges. Just looking at forward curves, is it fair to assume that those were -- those hedges were put on in June and July, before gas prices really came down?

I think that's probably a fair assumption.

And then looking at the capacity market in New England. I know, Mr. McGettrick, for some time, you've been skeptical of demand response in that market and its impact on capacity. I've heard that there might be some consideration of changes in the way demand response is allowed to bid into capacity auctions prospectively in New England, that it might be treated more like generation resources in the future, and that, that could -- I think, that's possible that could have a positive impact on capacity pricing. Are you aware of any of those potential changes?

There's a number of types of items being discussed now as they talk about the next capacity auction where they're going to take the floor away. So these are some of the associated issues that have come up. Our view on [indiscernible] hasn't changed over the last several years. We see the Northeast being in the market that's going to tighten the quickest. The demand response is probably at the max. And so as the economic recovery continues in the Northeast, and with coal shutdowns, oil shutdowns, that we're bullish long-term on capacity for baseload units in Northeast.

Do you think we'll start to see positive developments on that as early as this next auction?

I think it's too early to say. We need to get a clearer view on what the timing is going to be on some of the environmental rules, to see what shutdowns are out there. We also have a pretty large excess capacity position still, that being just all generators in the Northeast. So I'm not sure you're going to see as much in next auction, but over the next several auctions.

Our next question comes from Jonathan Arnold with Deutsche Bank. [Operator Instructions]

My question has to do with -- I mean, the quarter O&M, you mentioned you'd managed the market, it looked like it was down about somewhere north of 15% overall. Can you give us a little more insight into what was driving that, it seemed to be pretty much across the segments. And then, what's embedded in your 4Q guidance for O&M. Was there some of it -- is it timings in Q3, that will flow into 4, or something like that?

Jon, if you look at the third quarter '10 versus third quarter '11 on operating expenses, we're down about $135 million, I think, is what disclosure says. First you have to do, is you have to take out Kewaunee out of those numbers. Because remember, year-over-year, Kewaunee is now a non-operating, so we don't have that in there. Second, the third quarter is the first we've really seen a full quarter's impact of our voluntary separation program from last year. Remember, that was done very late in the second quarter, so we had some pretty significant quarter-over-quarter changes down. And you can continue to see those types of benefits as you go forward. And then we had some timing issues on maintenance, both in our generating units, but mainly, in our distribution business. They were focused on the hurricane, repairs, not only during the storm period but subsequent to that, is they had to go back and make more permanent repairs. So that pushed some of the normal maintenance that we would've done in the third quarter into the fourth quarter, and some of our outage maintenance as well, had some timing impacts there. So that's the reason really, for quarter-over-quarter why we're so far down. I would expect a small portion of that to come back, particularly in the distribution business. And to some extent, in the transmission business in the fourth quarter.

So adding it altogether is -- should we be expecting fourth quarter O&M be up or down?

I think you should be expecting fourth quarter O&M is down, if you’re looking at last fourth quarter.

And then one other question, please. Mark, on the -- looking at the fourth quarter guidance for DVP, just the increase seems to be kind of much bigger than you've seen earlier in the year. What's just driving that sort of move from $230 million up into the $272 million to almost $300 million range in the fourth quarter, specifically?

Two things there, Jonathan. We expect, in the fourth quarter, to have very strong margin support from our retail. And our transmission margins are also going to be very strong in the fourth quarter.

So for what -- why is that?

Just timing over expenditures throughout the year.

On transmission?

Yes.

And the retail? Just -- market conditions?

Just the retail book that we have. It's much larger than what we had in the fourth quarter of last year. We're well-positioned, both gas and electric for the quarter. We've picked up a lot of customers, and we're bullish on the fourth quarter for retail.

Can you maybe put a number around that?

No, I don't think we want to put a specific number around that. We have our guidance range out there and we'll stay with that for retail guidance.

Okay. And then, finally, the tax rate you're guiding to in Q4 is a little below normal, what's driving that?

I'm going to let Scott Hetzer answer that question.

We're still looking at 37% to 38%, which is in-line for the year.

For the year, or so it's just fourth quarter getting you to that place, Q4 itself looks like it's more like 35%, 36%?

No, it's -- we still expect to come in between 37% and 38% for the year. And that's where we see fourth quarter as well.

Our next question comes from Michael Lapides with Goldman Sachs.

Couple of questions. First of all, on O&M long-term, a little bit of a follow-on from John's question. What do you see for the next few years, as part of your long-term EPS growth target, the O&M growth component of that, and if you could kind of decompose that at some of the businesses, really at the high level?

Michael, we said back in May of last year that in 2011, that our operating expense is going to be up about $70 million year-over-year due to extraordinarily large number of outages in our generation fleet in 2011. But then it would normalize back in '12 to a fairly flat 2010 expenditure rate. And we still believe that is where we are. It would be a very flat or very modest increase in 2012. We haven't talked about '13 and beyond. We'll do that on future calls.

Got it. One other question. On construction costs of the combined cycles. Your dollar per KW number that you referenced for Warren County, kind of well below what lots of industry peers talk about for combined cycles. Can you just talk about what drives that?

Let me have Dave Christian to talk about that.

Essentially, it's the effective negotiations with all of the gas turbine suppliers and the deep sea participants.

But I mean, is that a labor cost driver, just to the region you're in? Is that a -- you're able to get the components because you're buying in bulk? I'm just trying to understand. Just because even when I talk to some of the other larger cap companies, they tend to quote a little higher numbers?

It probably a combination of all of those, and I don't have those specifics at hand.

Our next question comes from Leslie Rich with JPMorgan.

Tom, could you review again, the -- when you were talking about some of the new midstream projects, you’ve listed a few that weren't on Slide 13, that you filed for FERC approval? You mentioned the Gateway project, which you expect to be in service in 2012. What were the other 2?

There's the Ellisburg to Craig (sic) [Craigs] line and the Northeast expansion line were the 2 I mentioned, Leslie. We also are -- I think our -- I think, it was our last call. It could've been one of the fall conferences. We mentioned that we had -- Natrium had been -- not Natrium, Phase I had been 90% contracted. We did announce today that it is now 100% contracted and our negotiations are now dealing with Phase II, which would be about another $300 million project, which would effectively double the size of Natrium 2, would be finished about a year later. And then there's the liquefaction plant, which is not in any of our plans – I mean our capital programs at the moment, until we get a little more clarity on the possibility of long-term take-or-pay contracts.

What are your thoughts in terms of the structure of that. Would it be sort of a joint venture or someone else contributed the equity or would you finance that? And in light of Cheniere's announcement with BG, sort of how are you thinking about the contract structure?

Leslie, we're obviously still in -- discussing it with -- actually, it's numerous parties. All I understand about the Cheniere structure, Leslie, is what I've read in the trade press. If I understood it correctly, it's not a structure that we would have particular interest in, where they're taking commodity risk. We don't have any interest in commodity risk at a liquefaction export facility at Cove Point. It will -- if we enter into the contracts and we build the facility, it will look a lot like the import contracts that we have now which are long-term take-or-pay contracts. So we're in those negotiations. We are certainly open to folks taking a partnership position with us. That helped defray some of the capital cost we otherwise would incur ourselves, but we're large enough and diverse enough to be able to afford it ourselves, but we'd be very open to a partner.

And do you have FERC approval for that?

We -- not yet. And -- but I think the most important one, Leslie, is remember, keep in mind that we have -- obviously, everything is there. We have the pipeline with almost 2 B a day of throughput is already there, 14.5 billion cubic feet of storage are already there. The expanded peer that can handle the supertankers, is already there. So all of that work you would normally have to do for a liquefaction project is complete and has all the necessary FERC approvals. All we would need approval for is actual liquefaction facility itself. We architecturally already have a small one at the site. I think it's -- the DOE permit is the one to keep our eye on to get the right to export the gas. Cheniere has gotten that for their facility and we expect to be able to get it. We got one for the NAFTA countries, but that's like Mexico and the Caribbean and Canada, and a few others. But the important one is to get to the non-NAFTA countries.

Our next question comes from Paul Ridzon with KeyBanc.

Just following up on Leslie's question on Cove Point. What kind of in-service date are you thinking about?

It would be in the second half of the decade.

Okay. No finer than that? No more clarity, because it's still exploratory here?

Yes. I would not use the word exploratory, but it's in development. I think it's a little bit further along than exploratory. I would put it -- it's in development, but it would be after '15.

Our next question comes from Anthony Crowdell with Jefferies. Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: Just a quick question on Cove Point. You mentioned that if you would -- if Cove Point gets approval and you do construct it as a liquefaction facility, that you would be mainly, I guess, fixed-C [ph] -- or you would not take a commodity risk, which is what Cheniere is planning to do. What type of returns could we assume on a fixed-C [ph] LNG facility?

Well, it's too early to tell on that. But on our overall pipeline business, we look at Dominion Energy's projects from all -- when you take them all into account, we use -- we look at mid-teens returns.

Ladies and gentlemen, we have reached the conclusion of our call. Mr. McGettrick, do you have any closing remarks?

Yes, thank you. I want to thank everybody for attending today and I just wanted to remind everybody, we will be filing our 10-Q this afternoon. Thank you very much.

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