Thomas F. Farrell - Executive Chairman, Chief Executive Officer, President, Chairman of Virginia Electric & Power Company, Chief Executive Officer of Dominion Energy and Chief Executive Officer of Virginia Electric David A.

Christian - Executive Vice President and Chief Executive Officer of Dominion Generation G. Scott Hetzer - Senior Vice President of Tax and Treasurer Mark F.

McGettrick - Chief Financial Officer and Executive Vice President Thomas Hamlin -

Michael J. Lapides - Goldman Sachs Group Inc., Research Division Dan Eggers - Crédit Suisse AG, Research Division Jonathan P.

Arnold - Deutsche Bank AG, Research Division Greg Gordon - ISI Group Inc., Research Division Paul Patterson - Glenrock Associates LLC Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division Leslie Rich - Columbia Management Anthony C.

Crowdell - Jefferies & Company, Inc., Research Division

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 peak prices.

Nevertheless, Dominion Retail is still on track to deliver results within the guidance range we disclosed at the beginning of the year. EBIT for Dominion Energy was $168 million, near the top of its guidance range of $145 million to $170 million.

Lower fuel costs at Dominion Transmission and lower-than-planned O&M expenses were positive factors. Dominion Generation produced EBIT of $696 million for the third quarter, which was in the upper half of our guidance range of $650 million to $710 million.

Favorable weather and lower-than-planned O&M expenses were partially offset by an unplanned outage at Millstone Unit 2. Overall, we are pleased with all of our operating segment results.

Moving to cash flow and Treasury activities. Funds from operations was $2.7 billion for the first 3 quarters, on track with guidance given at the beginning of the year.

Regarding financing activities, we have completed our financing needs for the year, except for one Virginia Power issue of up to $500 million. We have already locked in treasury rates for this issue, as well as all of our anticipated debt needs for 2012.

As a reminder, we do not plan to issue any net common stock in 2011. Also other than the potential issuance of up to $300 million of stock through our stock purchase and dividend reinvestment plan, we do not plan to issue any net common stock in 2012.

Through the end of the second quarter, we had repurchased approximately 13 million shares of common stock at a cost of about $600 million. We do not plan to repurchase the additional 100 million in common stock we had estimated might be necessary to offset the EPS impact of the current provisions for bonus depreciation.

Liquidity at the end of the quarter was $2.8 billion. In September, we amended the pricing and extended the terms of our credit facilities.

These facilities, originally set to expire in 2013, now have termination dates of September 2016. For statements of cash flow and liquidity, please see Pages 14 and 27 of the earnings release kit.

Now to earnings guidance. Our operating earnings guidance for the fourth quarter of 2011 is $0.58 to $0.73 per share, compared to operating earnings of $0.63 per share in the fourth quarter of 2010.

When combined with year-to-date results, this effectively narrows our guidance range for the full year to $3.05 to $3.20 per share. As we have said, since May of last year, a scheduled refueling outage at Millstone and an outage at Brayton to tie in one of the new cooling towers will have a negative impact on this year's fourth quarter earnings, in addition to the impact of lower power prices.

Also weather contributed about $0.03 per share to last year's fourth quarter earnings. Offsetting these negatives are higher base in rider revenues and a lower share count.

We continue to expect annual earnings per share growth of 5% to 6% beginning in 2012. A reconciliation of operating earnings to GAAP earnings for the fourth quarter of 2010, as well as the fourth quarter and full year 2011 GAAP guidance can be found on Pages 40 and 41 of the earnings release kit.

As to hedging, you can find the update of our hedge positions on Page 29 of the earnings release kit. We've added to our hedges for Millstone in 2012 and 2013, increasing the hedging percentage to 76% and 59%, respectively.

Also as coal prices have softened recently, we were able to add to hedge positions for New England Coal units. Our sensitivity to a $5 move in New England power prices in 2012, is now only about $0.04 per share.

As shown in Slide 7 and on Page 29 of the earnings release kit, we have hedged about 1/4 of our expected production at Millstone in 2014 and 2015. Locking in the uplift in prices in these forward markets reduces the risk associated with achieving our 5% to 6% earnings growth targets.

So let me summarize my financial review. First, operating earnings for the third quarter this year were at the midpoint of our guidance range.

Operating results for each of our 3 business units were within our guidance range. We have hedges in place for all of our remaining debt needs for this year and next.

We have added to our hedge positions for our merchant generation fleet, reducing our sensitivity to changing commodity prices. And finally, fourth quarter operating earnings guidance is $0.58 to $0.73 per share.

Our operating earnings guidance range for 2011 is now $3.05 to $3.20 per share. I will now turn the call over to Tom Farrell.

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 reactors and that there was no significant damage, despite ground movement that exceeded the levels to which the plant was originally licensed.

On October 21, the NRC held another public meeting, at which the results of the analysis of the event and the inspection of the plant were discussed. Significant safety margins built into the design of the plant prevented damage to safety equipment.

After the meeting, a senior NRC official stated that North Anna will probably be allowed to restart within weeks. There is another public meeting scheduled for next Tuesday to present the results of the startup inspection completed by the NRC.

Hurricane Irene was a massive storm that inflicted significant damage to our electric transmission and distribution systems during the weekend following the earthquake. Although we knew the storm was coming, it's path and intensity were unpredictable.

While we had originally expected the worst of the storm to hit the southern and eastern areas of our service area, the bulk of the damage actually occurred in and around Central Virginia, where winds in excess of 40 miles per hour continued for more than 17 hours. The storm prompted the second-largest restoration effort in the company's 100-year history, exceeded only by hurricane Isabel in 2003.

The incorporating lessons learned from that storm improved our responsiveness to Irene. About 1.2 million, or half of Virginia Power's customers, were affected by the storm.

More than 7,000 line, patrol and support personnel, including 3,100 mutual aid and tree crews, for more than 20 different utilities and contractors repaired damage at 35,000 work locations and restored service to more than 92% of our customers within just 5 days. Compared to our restoration efforts for Hurricane Isabel, we had about 2/3 as many customers affected but restored service in about half the time.

We applaud the outstanding work of our employees, and we thank our fellow utilities for their mutual aid personnel. I'll now turn to operating results for the quarter, beginning as always, with safety.

Both Dominion Generation and Dominion Energy reported record for improving safety performance for the first 9 months of the year. At Dominion Virginia Power, hurricane restoration work led to an increase in both OSHA recordables and lost time restricted duty incidents.

Our electric transmission business has gone 122 days without an OSHA recordable. Moving to operations, our generating plants performed well in the third quarter.

Surry Units 1 and 2, Millstone 3 and Kewaunee achieved capacity factors greater than or equal to 98.7% during the quarter. Before the earthquake, North Anna Unit 1 had been online for 298 consecutive days, and Unit 2 for 289 consecutive days.

Millstone Unit 3 had been online 409 days through the end of the third quarter. Millstone Unit 2 experienced a 14-day outage due to a leak in the service water piping.

Economic growth continues to drive improving results for Virginia Power. Projected demand growth in Dominion's service territory is the highest in PJM.

Unemployment in Virginia is about 6.5%, which is well below the national average of over 9%, and is actually below 5% in Northern Virginia. Weather-adjusted sales were up 1.4% through the third quarter and 1.7% if you exclude the impact of Hurricane Irene.

We expect demand from data centers to grow from 295 megawatts at the end of 2010, to a total of 370 megawatts by the end of this year. Much of which has already been realized through the third quarter.

Data center load is expected to grow approximately 545 megawatts by the end of next year, and to approximately 715 megawatts by the end of 2013. We continue to move forward on our long-term infrastructure growth plan.

The Virginia City Hybrid Energy Center is about 93% complete, and is proceeding on-budget and on-time, with about 1,900 workers on-site during the quarter. Chemical cleaning of the boilers was completed last month, in preparation for a first-fire of the boilers by the end of this year.

More than 50% of the systems at the plant have been turned over for testing and commissioning. Initial synchronization is scheduled for early 2012, and commercial operation is scheduled for the summer of next year.

Our next new generating plant will be a gas-fired 3-on-1 combined cycle project in Warren County, Virginia, that will provide more than 1,300 megawatts when operational. The CPCN and Rider applications were filed with 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 final Notice to Proceed was issued for the combustion turbines and the steam turbine. Once regulatory approvals are received, construction should begin in the spring of next year, and the plant should be in commercial operation in late 2014.

The estimated cost of the project is approximately $1.1 billion, excluding financing costs, or only about $821 per installed KW. Combined with its 6,600 heat rate, Warren County will provide substantial economic benefit for our customers.

Even with the planned addition of the Warren County plant, Virginia Power will still need to construct additional generating capacity to overcome its existing shortfall and to meet the demands of its growing service territory. We have identified the need for up to 3 additional combined cycle plants similar in size to the Warren County project, 2 to meet demand growth, and another to replace coal-fired units at our Chesapeake and Yorktown power stations.

They will likely have to be retired as a result of proposed new emissions regulations from the Environmental Protection Agency. Virginia Power has also announced plans to convert 3 small generating plants from burning coal to less-expensive waste wood as fuel.

The air permit applications were filed at the end of May, and the CPCN and Rider applications were filed with the State Corporation Commission on June 27. An EPC contract, which is also fixed-price, was executed on June 30, and we have finalized our fuel aggregator contracts for each of the facilities.

The estimated cost of the conversions is $165 million. And once the projects are approved by regulators, it should be completed in 2013.

The upgrade of our transmission system is a key component of our infrastructure growth plan. The modernization of the Mt.

Storm-to-Doubs line was approved by the State Corporation Commission last quarter. Work is underway on this project, and will be conducted during the spring and fall of the next 3 years, and is estimated to cost about $350 million.

Our electric transmission project pipeline contains over 40 additional projects, totaling about $450 million per year, for at least each of the next 5 years. Recently, our electric transmission operations were ranked first in reliability among all of our peers.

Our transmission investments are providing excellent service to our electric utility customers. The growth program at our natural gas infrastructure business continues to move forward as well.

Construction of our $634 million Appalachian Gateway Project began this summer, and the project should be in service by September 2012. FERC approval for the Northeast expansion project, as well as the Ellisburg to Craigs project was received this quarter.

Both projects are expected to be in service by November 2012. We should expect to see a focus by us on a variety of midstream investment opportunities available to -- in both the Marcellus and Utica shale formations.

Last quarter, we announced the Natrium processing project. The Natrium site can access production in both the Marcellus and Utica shale regions, and is able to ship products via barge, rail, truck and pipe, offering significant value to producers.

On July 1, we executed an EPC contract for the construction of facilities that can process 200 million cubic feet of natural gas per day, and fractionate 36,000 barrels of NGLs per day. Recently, we executed an agreement with the producer that now fully contracts Phase I of Natrium.

This phase of the project is expected to cost about $500 million and should be in service by December 2012. We can also expand the facility to accommodate additional demand from producers.

Since we announced Phase I, interest from producers in the second phase at the site has been strong. We are in detailed negotiations with multiple producers for volumes to support the possible construction of Phase II at Natrium, which could be in service by the fourth quarter of 2013.

With the continued successful development of the Marcellus and Utica shale formations, interest in our potential Cove Point liquefaction project is growing as well. We are engaged in discussions with numerous potential customers in Europe and Asia, as well as producers in the Appalachian basin.

We filed a request on September 1 with the Department of Energy for authorization to export LNG to countries with which the U.S. has entered into a Free Trade Agreement.

The DOE approved that request on October 7, authorizing for export up to the equivalent of 365 billion cubic feet per year for a 25-year term. On October 3, we filed for approval to export LNG to non-Free Trade Agreement countries.

This phase of the approval process requires market demand, supply and economic studies to show that the export of LNG is not inconsistent with the public interest. Our filing supports our belief that the project will have many positive economic benefits.

Our application requests approval by June of next year, but it could take longer. Our regulatory calendar has been fairly active this year as well.

As many of you know, the first biennial review on the Virginia's reregulation statute is taking place. Hearings were held last month, and the State Corporation Commission must issue an order by the end of November.

The purpose of the review is to determine: One, whether the company's average earnings for 2009 and 2010 covered by base rates were within the authorized return on equity range of 11.4% to 12.4%; and two, what returned on equity will be used in the next biennial review and be incorporated into future project Rider filings. Hearings are scheduled to begin in December for State Corporation Commission approval of our Warren County project and in January, for the proposed biomass conversions.

We are confident in the value of these projects bring to our customers and are hopeful for commission approval next year. So to conclude, third quarter operating earnings were at the midpoint of our guidance range.

All 3 of our business units performed well and delivered results that met our expectations, despite the major earthquake and Hurricane Irene. We continue to move forward with our growth plans and expect to deliver 5% to 6% earnings per share growth beginning next year.

We also plan to request board approval for an increase of at least 7% in the dividend for 2012. Thank you, and we are now ready for your questions.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.