Good morning, and welcome to Dominion's Second 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 conference over to Tom Hamlin, Vice President of Investor Relations for Safe Harbor statement.

Good morning, and welcome to Dominion's Second 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've not done so, I encourage you to visit our website, register for email alerts and view our second 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 discussions. 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 third 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 are 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 second quarter, as well as our guidance for the third quarter. He will also discuss our financing activities and provide an update on our hedge positions. Tom will discuss our operating and regulatory activities, and 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 very strong second quarter. Operating earnings were $0.59 per share, which were in the top of our earnings guidance range of $0.50 to $0.60 per share. Weather, which boosted earnings for the second quarter of last year by $0.06 per share, added only $0.01 compared to normal. Despite the normal weather, both of our electric business segments delivered earnings at or above the top of the respective guidance ranges. Other factors impacting the results for the quarter relative to guidance were lower interest costs and higher income taxes. GAAP earnings were $0.58 per share for the second quarter. The principal differences between GAAP and operating earnings for the quarter were the benefit of a resolution of a lawsuit with the Department of Energy over spent nuclear fuel, offset by severance charges related to the previously announced closing of the Salem and State Line merchant generation plants. A summary and a reconciliation of GAAP to operating earnings can be found on Schedules 2 and 3 of the earnings release kit. Now moving to results by operating segment. At Dominion Virginia Power, EBIT for the second quarter was $227 million, near the high end of our guidance range. Higher transmission revenues and a higher contribution from Dominion Retail were principal factors in this strong performance. EBIT for Dominion Energy was $184 million, just above the midpoint of our guidance range. A strong contribution from Producer Services offset lower results from our distribution companies. Dominion Generation produced EBIT of $372 million for the second quarter, exceeding the high end of our guidance range. Higher ancillary service revenues and higher-than-expected merchant generation margins were the principal favorable earnings drivers. Overall, we are very pleased with all of our operating segment results. Moving…

Good morning. We continue to move forward on our long-term infrastructure growth plan. Many of the projects announced at the outset of this program in 2007 are either currently in operation or nearing completion, and we are now well into the development of the next round of projects. These investments which we announced last September are spread across all of our regulated lines of business and provide the foundation for our growth in earnings and dividends. We see the potential for this growth to continue beyond the current 5-year window through the end of the decade. Since we began this program in 2007, we have added over 1,500 megawatts of generating capacity to our Virginia fleet, with the construction of a new combined cycle facility, peaking facilities, as well as upgrades to some of our existing plants. In May, the 580-megawatt Bear Garden Power Station in Buckingham County began commercial operation and has run for over 60 days without any forced outage or automatic trips. Bear Garden was completed on time and on budget. We will add another 585 megawatts next summer when the Virginia City Hybrid Energy Center, a coal and wood-burning plant in Wise County, is scheduled to begin commercial operation. Virginia City is about 90% complete and is also proceeding on budget and on time, with about 2,200 workers on site during this past quarter. Our next generating plant will be a gas-fired 3-on-1 combined cycle project in Warren County, Virginia that will provide approximately 1,300 megawatts when operational. The CPCN and Rider applications were filed with the State Corporation Commission on May 2, and an EPC contract was executed on June 30. EPC contract is fixed-price, which significantly reduces the risk of cost overruns to the company and its customers. Site work has commenced and the…

[Operator Instructions] Our first question comes from Daniel Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG: I guess, Tom, first question, you said that you're going to readdress or kind of finalize the environmental CapEx plans due to the EPA rules due later this year. Can you just give us a little more clarity on timeline and kind of what the ROP process will look like?

Yes. And I'm referring to first with CSAPR, the so-called Casper rules have no material impact or significant impact on our environmental plans. So let's set that aside. When we've been talking about future capital expenditures, I think we announced maybe 6 months ago that we expected the Mercury rules, the now called -- or the HAPs rules to cost around $1.9 billion at Virginia Power. We don't see any reason to see that, that will change. We'll be within that range. We will give a lot more clarity around how exactly we will comply with HAPs when we file the integrated resource plan, which will be at the end of August. And we will explain where we plan to go on from there with the investor conference season starting in September. Dan Eggers - Crédit Suisse AG: Okay. And then on kind of the Cove Point conversation as far as export, any feel for when you guys might have something more substantial to talk about as far as maybe a plan or some memo use or anything like that?

Not at this time. When we're ready to announce something, we'll let you -- you will be among the first to know. Dan Eggers - Crédit Suisse AG: Okay. And then I guess just one other question. Clearly, there's been some interesting bidding activity on the market for other infrastructure opportunities similar to what you guys have in the Marcellus. This is an old question, I understand, but are you guys kind of, given the valuation discrepancy between what some of those assets trade at relative to where your stock is, have you guys been revisiting the idea of maybe pursuing other alternative vehicles to better represent the value of year Marcellus exposure?

I'll answer the, I guess, a macro answer to that question. I'll let Mark talk about the financing. To the extent the question asked, are we considering selling or spending our midstream business, the answer to that is no. And Mark can talk to you about financing options.

Yes, Dan, we see the Marcellus opportunities just continuing to grow based on our current location and our success with our early processing plants. And based on that and the spend requirement over the next several years, we're committed to our investment grade ratings. But we are looking at different types of financing options to finance this large level of growth as we go out there, all the ones that you might think about. And as we make progress on that, Dan, we'll let you know.

Our next question comes from Greg Gordon with ISI Group.

A couple of questions. Given how strong your earnings have been year-to-date, is it even necessary to contemplate doing the incremental $100 million in buybacks to get to the middle or the high end of your guidance range?

Greg, this is Mark. We talked about this previously. This is really an issue for 2012. As we looked at the buyback, we're entered into the buyback to make sure we're able to meet our 5% to 6% growth rate and keep our shareholders neutral to bonus depreciation. So we'll decide between now and the end of the year if we want to do the $100 million. It's not an '11 issue, it's potentially a '12 issue.

Got you. As we look at growth in demand in your service territory and how robust it is, are we -- should we expect more generation growth projects post the Warren plant coming online in 2014 to be presented to the commission as you see the demand continuing to grow out to the second half of that gate?

Yes.

And then what's the time -- the usual time horizon for presenting those resource plans to the commission?

Vague question, can't answer that question.

The integrated resource plan that Tom talked about earlier will be submitted no later than September 1, probably the end of August. And that will enumerate our plans to meet projected load growth in the state of Virginia.

And how far out will that plan go?

Typically, just 10 years.

Got it. And finally, when you talk about alternative financing plans, are you talking about using an MLP structure or is that off the table?

It's one of the structures we're looking at, but we're looking at others too, JVs, et cetera. But we're -- we are looking at an MLP structure.

Our next question comes from Paul Patterson with Glenrock Associates.

I'm sorry if I missed this, but the fractionation of the gas processing plant, what kind of contracting are you guys having with that? I mean, is it going to be a certain percent of proceeds or fee-based? Or can you give us a sort of a feel for what you might be seeing with that?

It's largely fee-based, almost entirely fee-based.

Okay. And then with respect to the Cove Point export potential, you guys obviously have a facility there, and that's obviously, I would think that there would be some synergy with that. But there is, my understanding, a considerable amount of CapEx with respect to an export facility as opposed to an import one. Any sense as to how much CapEx potential might be there?

Paul, it all depends on the size of the contracts that we sign. There is no prospect of us starting a liquefaction process without long-term contracts for an extended period of time that fully fund the expansion or the liquefaction itself. And it depends on -- we have to have a certain amount to make it worth our while to build at all or make it worth the while to customers to build at all. So we're a long way from deciding what the size it would be, although we are doing the studies now on how to size it and what it would look like and we're talking to vendors. And we're doing the market studies around impacts on gas price and all things you need to do to go ahead with this project. Interest has been strong.

Okay. Great. Then finally, I see that you guys are testifying this morning on the Minimum Offer Price Rule on the "self supply" issue. What we've also seen is that in other RTO environments, and I was thinking New England because you guys have Millstone there and what have you, efforts to reign in out of market subsidy impacts on the capacity market, in particular, I guess. Any sense as to whether or not there may be upsides that you might see from these activities with respect to the forward years and what have you in terms of the full capacity market? Any thoughts on that at all?

Yes, Paul, this is Mark. What we're focused on is protecting the interest of our customers in Virginia. The current rules define unconstrained zone versus constrained zone, the rules are different. As you know, some proposals were made to potentially change some of those rules down the road. And our total focus is to make sure our customers don't double pay essentially for capacity if the rules are changed in order to keep their rates down.

Sure. But I'm just wondering in New England, I guess, I know it's a different process and it's not as far along, but it does seem that there are efforts by others to basically sort of institute some sort of buyers side market mitigation efforts, I guess, right? Market power mitigation efforts. And again, I'm just wondering if you thought that, that might have some impact on the New England market or whether or not it's too early to tell or?

I think at this point in time, Paul, it's way too early to tell.

Our next question comes from Paul Ridzon with KeyBanc.

I know you can give an update later, but would you characterize your kind of post '13 hedging as dabbling? Or is it more substantial than that?

Look, we never dabble. That's a great question. I don't know how to define dabble, but we'll talk about that when we come out with the numbers in the fall. We'll let you decide but again, we want to make share everybody knows we're focused on uplifting these curves. We're focused on our 5% to 6% growth, and if that '14, '15 period we can lock in some value to support that, then we're going to move ahead and do that.

And just switching to another topic, can you discuss some of the potential synergies this processing plant will have with existing pipe? I mean is it going to increase the utilization and fees?

Yes. We'll be converting some of our existing pipes to wet to be able to provide liquids, et cetera. So the reason why this facility will be extremely competitive, and has been in the market, that's why it's sold out, is because we were able to integrate it with our existing gathering pipeline system. It's -- now the Utica Shale and the Marcellus Shale is bisected by Dominion Transmission's pipeline. And there are other pipelines, of course, in the same region. But this is our backyard and we've been there for 75 years and we have the infrastructure there to exploit the opportunities.

So what's the implication of Massachusetts not being part of Casper with regards to Brayton Point?

The implication is that we are -- we don't have to comply with the regulations. So whatever the limitations on admissions, et cetera, are inapplicable to Brayton Point and to Manchester Street.

So that makes them that much more competitive. Okay. Who's the EPC contractor on Warren County?

BMZ [ph], Burns MacZachary [ph].

And then finally -- the more -- every quarter, it seems like there's more projects in the pipe. I mean, at some point do we need to revisit the 5% to 6% growth?

Not at this time.

Our next question comes from Jonathan Arnold with Deutsche Bank.

Just curious on you're halfway through the year, you've had a couple of decent quarters. You nearly had a 10% range on the third quarter. Power prices are pretty well hedged for the rest of the year, but still a $0.30 range on the '11 guidance. Is that just a -- we'll revisit it when we get the third quarter down? Or what are the things that could really move you that much at this stage?

Jonathan, this is Mark. I think halfway through the year, as you know, we're a pretty weather-sensitive company in Virginia. We think to talk about any change in range at this early in the year will be premature. We'll see where we are at the end of the third quarter. But again, it's -- we're a third quarter company really on the electric side and we'd like to see what those results are before we talk about the range.

And if I may, on the NEPOOL fleet, it looked like you ran a good bit less than you anticipated in the second quarter, that you still managed to kind of deliver a number price-wise close to your hedge price. What was the reason for kind of -- there was it just dispatch? Was it operational issues? What pushed you off that generation target?

Jonathan, it's really market issues where we could replace our generation at a equal or lower cost with market purchases to settle our hedges. So those units didn't run as much, but we were able to make the same contribution as we would expect in running those units.

Our next question comes from Paul Fremont with Jefferies. Paul Fremont - Jefferies & Company, Inc.: When I look at the estimated annual NGL sales guidance, I guess it's on Page 29 of your packet, does the number for 2013 include the Natrium plant or is that not in there?

No. That's not in there, Paul. Paul Fremont - Jefferies & Company, Inc.: So this would essentially be a commodity-type sale, so can you give us a sense of what types of volumes -- I mean, it looks as if in '13, you could do close to 600 just on Natrium if you're at capacity.

We need to make sure we're clear on this. And I'm glad you asked the question, Paul. The Natrium processing fractionation facility is largely fee-based, okay? So we're not going to be selling, taking ownership of the NGLs, except a small fraction. So while that fraction is not included in what you see on the disclosures, as I understand it, it's not going to be -- it's not something that you should focus on, I don't believe, as to earnings power of Dominion. Paul Fremont - Jefferies & Company, Inc.: Right. But I guess, am I correct in sort of thinking about the fact that when Natrium is in operation, granted it's going to be at a much lower margin, that you're going to be looking at volumes that are sort of greater than the volumes that you're disclosing on that Page 29.

I'm not sure, to be honest with you, Paul. I'm just not sure I understand your question. Why don't you -- it would be better for you to follow up, I think, with our IR folks. We want to make sure we answer that really, and I'm afraid I just don't understand exactly what your point is.

And then I guess the other question I have is with respect to the cross state rules, and I recognize that any change in variable cost in VEPCO would probably be recoverable under a fuel clause. Can you give a sense of what you would expect to be the impact on your variable costs of operating those power plants?

In Virginia, we're in a good position with respect to the allowances that we expect to go into the bank. And we don't find ourselves in a short position and not predicting any material impact.

Our next question comes from Michael Lapides with Goldman Sachs.

Real quick, just looking at Page 13 on the slide deck, the various plants projects, all of those embedded in the CapEx guidance you gave for energy the last time you gave it, I think it was one of the analyst presentations over the last couple of months. So anything on that slide in the plants projects, those 4 items that is not embedded in that CapEx guidance that you gave a month or so ago?

We're checking the slide here, Michael, to make sure we answer your question. Natrium, we did not -- I mean, we didn't give you the amount in that slide. We have been talking about Natrium since the last quarter. We haven't finalized contracts until fairly recently. So while it shows up on Slide 13, the amount that we announced today is $500 million for Phase 1.

Okay. And the other 3?

The other 3 are in the plan.

Okay. The other 3 are in the plan. What's the timeline on the Utica Shale project?

He's talking about to you, Gary. Gary, why don't you answer that question?

Actually we'll be looking at that -- some of that gas will be ready to flow actually this year and more of it in 2012.

Okay. And I may have missed or I don't know if you discussed, did you talk about the scale in terms of the capital spending requirements for Dominion Energy for that, the Utica Shale Gathering Project?

You should actually consider that part to be relatively small. We're laying a few lines to help gather some of the new wells being drilled, but it's not a huge play for gathering.

Got it. And last question, this is on Virginia Power, and it's a little bit of a follow-up of one that someone asked earlier. When you look at your potential capacity needs between now and 2015, and do you see yourselves as needing incremental generation above what you already have in your construction plant to meet summer peak by 2015?

By 2015, I think the answer would be no. Because Warren will be coming in late 2014, but shortly after Warren, there is a need for increased generation in Virginia. As we look to the balance of the decade, there's still a significant shortfall that we're going to have to build with -- fill with new plant.

Our next question comes from Steve Fleishman with Bank of America.

Just on Natrium and, I guess on potentially other projects that come up like this, how should we think about the returns that you might be getting on a project like this? Is it -- I'm not sure you can be specific, but maybe generally, is this above utility returns? Or how should we think about returns?

Above utility return.

But still with long-term fee commitments in terms of revenue?

Yes, yes.

Okay. And I guess the second question on both the Casper rule and the HAP MACT rule, could you give any flavor either as your CEO position or in the EEI position, just current thinking how to react to those rules?

Well, I think first with HAPs, EEI will be filing its comments along with everybody else in about a week. I think it's August 6 is the date. We received a 30-day extension on the original 60 days. And I expect that EEI will be asking for some additional time for plants that will be retrofitted or replaced. I don't expect it to ask for additional time for plants that are being retired. Dominion has said we don't -- obviously the rule's not final, but from what we've seen, we don't anticipate any additional expenditures other than we projected originally, which was $1.9 billion at the high end of the possible range that we would have to spend. And that will be what we're trying to -- what we're finalizing is how we're going to -- what food groups we're going to use to meet those regulations, whether it's new power plants or environmental controls or transmission solution. We're nearly done with that, and that will become clear I think, in our IRP. The Casper rule, as I said, in particular because Massachusetts and Rhode Island were excluded from the regulation, there's no impact from the Casper rules on Dominion.

Our next question comes from Nathan Judge with Atlantic Equities.

I just wanted to see if you have any comments on the recent FERC ruling on transmission and as it relates to possible new transmission projects for you.

Paul Koonce can answer that question.

Yes, Nathan, we have been through the 620-page order. What they've done is deferred cost allocation to the RTOs, PJM's supports cost allocation at the 500kV level. So that's no change. And in terms of merchant transmission, again, I think the commission is deferring to the RTOs who developed those rules, but have given deference to where the transmission right-of-way currently exists or where facilities currently exist. We have a very constructive relationship with PJM, so we don't see really any impact from that as well.

Do you have any concerns or any issues with the ROFR decision?

Well, we did not have a ROFR in our FERC transmission tariff, but we do have a ROFR in our operating agreement with PJM. And again, the NOPR basically removes the ROFR from the transmission tariff does not impact us because we didn't have one, and has deferred the matter to the RTOs to develop the rules. So we've got a very constructive relationship with PJM. We're unaffected by the ROFR rule itself because we didn't have one, and I think we feel very good about our ability to carry on with PJM as we have in the past.

Great. And also could you just give us an update on perhaps timing regarding discussions of assets, perhaps disposals in your portfolio?

Well, the only asset that is up for consideration for disposal is Kewaunee as we have previously announced, and we have nothing to announce on Kewaunee today.

Is there a more definitive timeline that you're looking at now?

No.

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

Yes, thank you. I appreciate everybody's attention today. And I just want to remind you that we'll be filing our 10-Q tomorrow. And our third quarter earnings release will be scheduled for October 28. Thank you very much.

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