Paul D. Koonce - Executive Vice President and Chief Executive Officer of Dominion Virginia Power 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 -

Dan Eggers - Crédit Suisse AG, Research Division Paul B. Fremont - Jefferies & Company, Inc., Research Division Carrie Saint Louis Jonathan P. Arnold - Deutsche Bank AG, Research Division Paul Patterson - Glenrock Associates LLC Nathan Judge - Atlantic Equities LLP Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division Steven I. Fleishman - BofA Merrill Lynch, Research Division

Good morning, and welcome to Dominion's Fourth Quarter Earnings Conference Call. On the call today, we have Tom Farrell, CEO, and other members of senior management. [Operator Instructions] I would 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 Fourth 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 fourth 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 from 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 fourth quarter and full year 2011 operating earnings and our operating earnings guidance for the first quarter and full year 2012, as well as our operating earnings before interest and tax, commonly referred to as EBIT. Reconciliations 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. Tom will begin with a review of the progress we have made on our growth plan in 2011 and our outlook for 2012. Mark will discuss our earnings results for the fourth quarter, as well as our guidance for the first quarter and full year 2012. We will then take your questions. I will now turn the call over to Tom Farrell. Thomas F. Farrell: Good morning. For Dominion, 2011 was a year of significant accomplishment. Across our business units, our employees delivered improved service quality in nearly all areas of operations, and in most cases, with record-setting safety performance. We completed several major capital projects in our strategic growth plan and made significant progress in the construction of several others. We also worked to secure the contractual commitments and regulatory approvals necessary for the next round of projects that should sustain our growth plan for the foreseeable future. We delivered operating earnings per share within our guidance range in the face of a sluggish, yet improving economy, weak commodity prices and mild weather, particularly in the fourth quarter. Shareholders were rewarded in 2011 with a total return of 29.4%, which exceeded the returns for most of our industry peers as well as the overall market. Our strategic growth plan consists of investments in new infrastructure in all of our regulated lines of business. At Dominion Generation, it involved the construction of new generation to reduce the existing capacity deficit of Virginia Power to meet the expected growth in demand from our service territory and to replace the generating capacity that is being retired, in order to comply with new EPA regulations. At Dominion Virginia Power, it involves the modernization of the 500 kV loop that has been the backbone of our electric transmission system, as well as upgrades in new service lines to support demand from new customers, including data centers, and to maintain reliability to portions of our service area affected by generation plant retirements. At Dominion Energy, it involves the construction of the gathering, processing and transmission infrastructure that will be needed to facilitate the natural gas production from Marcellus and Utica Shale formations. It also includes the systematic replacement of much of the pipeline network at Dominion East Ohio. All told, this plan involves about $11.6 billion of new plant investment and identified projects over the next 5 years, providing the foundation for our 5% to 6% expected growth in earnings per share beginning this year, which we again affirm today. 2011 was a year of significant progress at Dominion Generation. Construction of our 90-megawatt Bear Garden Power Station was completed on time and on budget. The plant began commercial operations on May 23 and had a 126-day continuous run. The Virginia City Hybrid Energy Center was over 95% complete as of the end of last year and is on schedule for commercial operations by the middle of this year. This $1.8 billion project is also on time and on budget. Our next large-generation construction project is the Warren County three-on-one combined cycle plant, which is expected to provide approximately 1,300 megawatts of capacity. The CPCN Rider applications were filed with Virginia State Corporation Commission last May, and the hearing was held last month. An order from this commission must be issued no later than next Thursday. If regulatory approvals are received, construction will begin this spring. And the plant should be completed by the end of 2014 at a cost of roughly $1.1 billion. We expect to file the Warren County project with a similar size combined cycle plant for completion in mid to late 2016. This plant was identified in our 2011 integrated resource plan and will be necessary to offset the reduction in capacity caused by the retirements of older coal-fired units at our Chesapeake and Yorktown power stations due to the HAPs MACTs [ph] rule from the EPA. Local conditional use permits have already been obtained for potential sites in Chesterfield and Brunswick Counties for the proposed facility. We will make a determination on a specific site this quarter and expect to file for a CPCN and rate rider with the commission, either late this year or early next. Other growth projects at Generation include the conversions of older coal-fired units to burn other fuels. We plan to convert Units 3 and 4 at our Bremo station from coal to natural gas. The company issued an RFP for the Engineering, Procurement and Construction contract for the project last quarter and expect to file a CPCN request with the commission this summer. We are also converting 3 of our smaller coal units to burn wood. The hearing for this conversions was held in December, and we expect the commission order in March. If approved, work on the $165 million project should be complete next year. Dominion Virginia Power completed 2 large 500kV transmission lines during 2011. The Meadow Brook to Loudon and Carson to Suffolk lines were both completed on time and on budget. Work began last year on the modernization of the Mt. Storm to Doubs line and will be performed during the spring and fall of the next 3 years at an estimated cost of about $350 million. Our electric transmission project pipeline contains over 40 additional projects totaling about $600 million per year or at least each of the next 5 years. Dominion Energy also made significant progress on its own growth program in 2011. Construction of the $634 million Appalachian Gateway Project began last summer, and the project should be in service by September of this year. FERC approval for the Northeast expansion project, as well as Ellisburg to Craigs was received in the third quarter of last year. Both projects are expected to be in service by November 2012. Last year, we announced the Natrium processing project. Construction has begun on Phase I, which is fully contracted and is designed to process 200 million cubic feet of natural gas per day and fractionate 36,000 barrels of NGLs per day. Phase I should cost about $500 million and should be in service by December. We are in detailed negotiations with multiple producers for volumes to support the possible construction of Phase II at Natrium, which would 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. On October 3, we filed for approval to export up to an equivalent of 365 Bcf per year for 25-year term to non-free-trade agreement countries. Our filing supports our belief that the project will have many positive economic benefits, and we are hopeful for DOE approval later this year. I will now turn to operating results for the year, beginning with safety. Both Dominion Generation and the Dominion Energy reported record or improving safety performance. Fossil & Hydro generation completed a best on-record incident rate of only 0.33 for 2011, well below their previous record of 0.62 set last year. Our nuclear business unit had only 5 OSHA reportables in 2011, yielding an incident rate of just 0.12, its best on record. Both Dominion East Ohio and Dominion Hope also had the fewest number of OSHA reportables in their history. At Dominion Virginia Power, hurricane restoration work contributed to an increase in both OSHA reportables and lost-time, restricted-duty incidents. However our transmission business went 165 consecutive days without an injury. Our service company has best year ever with only one OSHA reportable. Safety continues to be one of our core values at Dominion, and we are pleased with our improvement. Moving to operations, our generating plants performed well last year. Our Fossil & Hydro utility fleet achieved a net forced outage rate of 3.8%, with our large coal units surpassing their previous record with the rate of only 3.18%. The peak season equivalent availability of 96% was the highest in the last 3 years. The overall capacity factor for our nuclear fleet declined from just above 90% in 2010 to 85% in 2011. Several natural events contributed to the decline. A tornado last spring touched down in the switchyard at our Surry plant, and an earthquake that shook the entire East Coast caused both North Anna units to be offline for about 80 days. Capacity upgrades for 3 of our 4 nuclear units at Virginia Power have been completed, and the final upgrade of 21 megawatts at North Anna Unit 1 will be completed during its refueling outage this spring. Dominion Virginia Power had a challenging year in 2011. Hurricane Irene resulted in the loss of power to almost 1.3 million customers. The second-largest restoration effort in company history was completed in less than 9 days at a cost of about $108 million. As compared to Hurricane Isabel in 2003, approximately 2/3 the number of customers were affected. However, restoration was completed in half the time and about 1/2 the cost. Economic growth is expected to drive improving results for Virginia Power. In July, we set a new record system peak load of 20,061 megawatts, exceeding the previous record, which had been set in August of 2007. Additionally, PJM's updated forecast projects peak demand growth in the zone that includes Dominion service territory of 1.9% per year over the next 10 years, or an increase of nearly 4,000 megawatts. Unemployment in Virginia is just 6.2%, well below the national average of 8.5% and is actually only 5% in populist Northern Virginia. Weather adjusted sales at Virginia Power were up 1.6% for 2011, and actually 1.8%, if you exclude the impact of Hurricane Irene. Our estimate for weather-normalized sales growth in 2012 is 2% to 2.5% for Virginia Power, with data centers continuing to be a strong contributor to our growth. For Dominion Energy, development activities by producers in the Marcellus and Utica Shale regions continue to grow, providing the foundation for the infrastructure projects that are a key component of our growth plan. In the fourth quarter, there were 51 new horizontal Utica well permits issued in Ohio, more than doubling the number in effect at the end of the third quarter. 10 different producers have permitted Utica wells, up from 7 at the end of September, and 6 of those producers are currently drilling. Actually, every single Utica well online in the state of Ohio is tied into the wet gas gathering system at Dominion East Ohio. Producer activity in the Marcellus and Utica formations is occurring despite low natural gas prices due to the economic value of the liquids contained in the gas stream. Our Hastings extraction plant achieved an all-time record reliability factor of 99.3%, leading to an all-time record fractionation volume of over 180 million gallons of NGLs in 2011. After a binding open season held in early November, DTI executed precedent agreements with 3 of the customers at Phase I at Natrium to transport 185,000 decatherms per day of firm transportation from Natrium to Texas Eastern. You can expect a number of announcements related to various DTI growth projects over the course of this year. Our regulatory calendar was also fairly active last year. The first biannual review on the Virginia's re-regulation statute took place in 2011. The State Corporation Commission issued its order on November 30, determining that earnings from Virginia Power's base rate revenues produced an earned rate of return on common equity in excess of 12.4% in order to refund to customers $78 million. Furthermore, the commission set a return on equity to be used in the second binding review of 10.9%, which under Virginia's law allows the company to earn up to 11.4% before triggering any potential refunds or rate reductions. We are seeking clarification from the commission as to whether the new rate will apply to the entire 24-month period covered by the second review, or whether the new rate only became effective as of the date of the commission's order as all of the parties had agreed to in the settlement agreement from the going-in rate case. Our GAAP earnings for 2011, which comprises 1/2 of the next review period, were significantly below the authorized level due to write-off of the value of our coal units that are being retired, restoration costs related to Hurricane Irene, the inspection costs at North Anna brought on by the earthquake and the impairment charge on the value of our CAIR emissions allowances. Furthermore, the commission's treatment of severance costs related to our 2010 voluntary separation plan actually shifted about $100 million of expenses into 2011, further lowering the earned ROE computed for regulatory purposes. Finally, I want to comment on our dividend. Last week, our Board of Directors authorized a 7% increase in the quarterly dividend rate, which subject to further declarations by the board, equates to an annual rate of $2.11 per share. The new rate represents about a 65% payout at the midpoint of our earnings guidance range for 2012, and reflects the board's confidence in our ability to achieve our earnings growth targets. Last month, our board affirmed our 60% to 65% targeted payout ratio, therefore pending board approval, you can expect future dividend increases in line with our growth and earnings per share or about 5% to 6% annually. So to conclude, all 3 of our business units performed well and delivered results that met our expectations for the year. We continue to move forward with our growth plans and expect to deliver 5% to 6% earnings growth per share beginning this year. Thank you, and I now turn the call over to Mark McGettrick. Mark F. McGettrick: Good morning, everyone. Dominion's 2011 operating earnings were within the guidance range we gave at the beginning of the year. And largely due to mild weather in the fourth quarter, we're at the bottom of the revised range we issued on our last call. Operating earnings were $3.05 per share for the year and $0.58 per share for the fourth quarter. Very mild weather, particularly in December, reduced earnings by $0.08 per share in the fourth quarter. GAAP earnings were $0.35 per share for the fourth quarter and $2.45 for the year. During the fourth quarter, we wrote down the value of our coal units at our Chesapeake, Yorktown and North Branch Power Stations which will be retired primarily as result of new EPA emissions regulations. These charges account for most of the difference between GAAP and operating earnings for the quarter. Other factors for the year include restoration costs related to Hurricane Irene, merchant plant retirements, Kewaunee operations and the net impact from the SCC's order and the biannual review. 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 fourth quarter was $232 million, which was below the bottom of our guidance range. This variance was driven primarily by warmer-than-normal weather plus higher-than-expected storm restoration expenses. EBIT for Dominion Energy was $258 million, which was above the top of its guidance range. Greater-than-expected earnings from Producer Services and lower fuel costs at Dominion Transmission were positive factors. Dominion Generation produced EBIT of $229 million for the fourth quarter, which was below the bottom of its guidance range. Mild weather at Virginia Power and lower merchant generation margins due to lower commodity prices and extended outage at Millstone Unit 3 were principal factors in the lower results. Offsetting lower results from our operating segments were lower interest expense and lower income taxes, both of which came in better than expected. Moving to cash flow and treasury activities. Funds from operations were $3.5 billion for 2011, on track with guidance given at the beginning of the year. Regarding liquidity, we had $3.5 billion of credit facilities. Commercial paper outstanding at the end of the year was $1.8 billion, resulting in available liquidity of $1.7 billion. Last September, we extended the maturity of our credit facilities to September 2016. For statements of cash flow and liquidity, please see Pages 13 and 26 of the earnings release kit. Now moving to our financing plans. Earlier this month, we issued $450 million of 10-year notes at Virginia Power. This issue was a carryover from our 2011 financing plan. Excluding that issue, we plan to issue between $1.6 billion and $2 billion of debt this year, fairly evenly split between Dominion and VEPCO. This amount includes the replacement of about $1.5 billion in maturing debt. We have already locked in treasury rates with hedges for all of our anticipated 2012 debt offerings. As part of our 2012 financing plan, we will issue new shares of common stock to our dividend reinvestment and other stock purchase programs, which will raise about $300 million of new equity. Since our existing SEC shelf registration expires at the end of this month, we plan to file a new universal shelf with the SEC later today to cover financing needs for the next several years. Included in this shelf registration will be the ability to issue common stock through an at-the-money or ATM program. We do not expect to issue any shares under this program this year. We're simply creating the flexibility to use this program in future years, when we choose to issue equity above amount raised through our dividend reinvestment in other stock purchase plans. Now to earnings guidance. As Tom said earlier, we expect our operating earnings to grow 5% to 6% this year. Based on our operating earnings of $3.05 per share in 2011, this would imply an operating earnings range of roughly $3.20 to $3.25 per share for 2012, assuming normal weather. Incorporating some degree of sensitivity to weather and other factors to that range, results in operating earnings guidance for 2012 of $3.10 to $3.35 per share. On Slide 8, we have highlighted the principal drivers, positive and negative, to our 5% to 6% growth in 2012. As you can see, interest expense, VEPCO revenues, rate adjustment clauses and gas transmission and distribution are expected to provide significant growth. On the downside, DD&A and merchant generation margins are negative drivers year-over-year. Let me spend a few moments going over these drivers. First, on Slide 9 is the breakdown of our merchant generation challenge. In confirming our growth guidance on our last call, we anticipated a merchant margin reduction in 2012 of about $0.13 to $0.16 per share, mainly driven by the shutdown of our State Line coal units this quarter. However, as shown in the middle of this slide, we currently see an initial challenge of $0.06 to $0.08 based on the recent drop off in our open NEPOOL positions. We plan to offset the additional margin weakness by reducing operating expenses as shown on Slide 10. Our total annual operating and maintenance budget is approximately $3.2 billion. We plan to reduce that by 2% to 3%. I've highlighted a few areas that we will focus on. First, we will have a number of natural offsets due to current depressed 1x and lower margins at our coal units. We expect to have lower variable operating, environmental and maintenance costs due to reduced production. We are also evaluating planned maintenance outage schedules and other routine maintenance in all of our businesses to meet this challenge. Finally, we'll be closely managing our employee and contractor levels. If you review our expense level performance over the last several years, we believe cost management is a significant strength for us. Moving to interest expense on Slide 11. We expect year-over-year interest expense to drop by approximately $30 million as we continue to take advantage of the current low interest rate environment. Recent swaps and the replacement of maturing debt are expected to be the main drivers. On Slide 12, we outlined our anticipated VEPCO sales and revenue growth. Year-over-year sales should grow between 2% to 2.5% with data centers providing nearly half of the uplift. Outside of data centers, our projected sales are estimated to grow only 1% to 1.3%. This may turn out to be conservative. Moving to rate adjustment clause revenue growth on Slide 13. You can see the transmission Virginia City and Warren County should provide most of the incremental growth based on the capital spend in these areas. And finally on Slide 14, we provide a breakdown of our gas business growth drivers. These growth projects continue to support of the Utica and Marcellus infrastructure needs. All of these projects have been outlined in the growth plan for some time. We hope the breakdown will truly be helpful and provide the details of how we will grow this year. Moving to operating earnings guidance for the first quarter of 2012. Our guidance for the first quarter is $0.85 to $1 per share compared to operating earnings of $0.93 per share in the first quarter of 2011. Please note, we have one additional first quarter nuclear outage in Virginia than last year. A more detailed layout of our earnings guidance for the first quarter and full year 2012 can be found in our earnings guidance kit, which will be posted on our website later today. As to hedging, you can find the update of our hedged positions on Page 28 of the earnings release kit. We've added to our hedges from Millstone in 2012, increasing the hedging percentage to 80%. Our sensitivity to a $5 move in New England power prices in 2012 remains about $0.04 per share. Our sensitivity to a similar move in 2013 is about $0.07 per share. As shown on Page 28 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 pricing in these forward markets reduces the risk associated with achieving our 5% to 6% earnings growth targets. So let me summarize my financial review. Operating earnings for 2011 were within the guidance range. Mild weather, particularly in December, led to an operating earnings per share for the fourth quarter and full year 2011 that were at the bottom of the ranges given last October. Our operating earnings guidance for 2012 is $3.10 to $3.35 per share. The midpoint of this range is consistent with our 5% to 6% earnings growth targets. First quarter operating earnings guidance is $0.85 to $1 per share. And finally, while recent declines in commodity prices present a challenge, we are confident that through control of operating expenses and taking advantage of the low interest rate environment, we are well positioned to meet our growth targets. Thank you, and we are now ready for your questions.

[Operator Instructions] Our first question comes from Paul Ridzon with KeyBanc Capital. Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division: What's the trajectory of new data centers? I mean, does that look like it's saturated? Or do we have a few more years of this? Thomas F. Farrell: I'm sorry, new gas what? Paul B. Fremont - Jefferies & Company, Inc., Research Division: New data centers, excuse me. Thomas F. Farrell: No, they moved data centers. I'll let Paul Koonce give you the detail, but it's been going on for some years, and it's expected to go on for at least several more. But Paul can go ahead and give you that exact numbers we have. These are points that are under contract. Paul D. Koonce: Yes, Tom. For 2011, we expected to add about 75 megawatts of new demand from either existing or new data centers. And in 2011, that's exactly what we did. We added about the 9 new centers. For 2012, because data centers require facilities, that work is already underway. So for 2011, we expect to add about 11 new data centers. And between 2000 -- and between existing data centers and the new ones, we expect to add about another 175 megawatts of contract demand, for a total of about 545 megawatts. So it's a very predictable schedule. And we have not seen any change in customer needs in this area. Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division: And philosophically, in this commodities market, how do you think about hedging the outyears? Do you -- I mean, are you cautious here, and you just don't want to -- I guess, I was asking, are you bearish or bullish on gas at this point? Mark F. McGettrick: We're not either bearish or bullish, Paul, on gas. This is Mark. As we look at the outyears, we look it as part of the package. And we're shooting to grow 5% to 6% commodity prices or a piece of that. So as we look at OEM opportunities, other growth opportunities, if we see a power price out there, a commodity price that helps support that long-term strategy, then you can see us hedge it. But you should watch us to average in hedges still at Millstone, but again, it'll be part of a bigger package as opposed to more of a standard averaging that we have done over the last several years? Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division: Does your 1Q and full year guidance contemplate year-to-date weather? Mark F. McGettrick: Year-to-date as in January? Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division: Yes. Mark F. McGettrick: Well, we don't -- January is 1 month out of 12 and 1 month out of 3. I think right now, we assume normal weather for the year. That's how we build our guidance range, and we'll see what the actuals prove out.

Our next question comes from Paul Patterson with Glenrock Associates. Paul Patterson - Glenrock Associates LLC: Just to clarify, on the long-term earnings growth. If you guys, despite -- if I heard you guys correctly, despite what we've seen in the current market, coal, gas prices, et cetera, because of your hedging and because of the growth prospects and the other parts of the business, effectively, you still think that you can make the 5% to 6% growth, correct? Thomas F. Farrell: Yes. Paul Patterson - Glenrock Associates LLC: Okay. And then the second thing is the impairment on the Generation assets. Could you just give us a little bit more flavor as to what happened this quarter? Mark F. McGettrick: Paul, its Mark. I'll be glad to do that. We got the final mercury order in December. And we have been talking to investors for some time that based on what we thought was going to come out, along with some -- with other orders out of the EPA that we would have several facilities in Virginia that would not be economically complying. And so we identified those. And then when the final order came out in December, we impaired them. We anticipate those coal units shutting down and being replaced by new gas unit. And so we impaired them based on a 2015, 2016 end of life, which is the exactly the same treatment that we talked with our State Line and Salem units, as we identified those as shutdown candidates based on environmental regulations. Paul Patterson - Glenrock Associates LLC: Okay. Now these are regulated assets? Mark F. McGettrick: They are regulated assets. Paul Patterson - Glenrock Associates LLC: Now, wouldn't you be able to recover the -- I mean, I guess, this is a regulatory treatment, how does it mean -- is this really a real write-off that you guys are going to be a -- you mean, there's going to be a hit to common equity? Is that -- how should we think about those in terms of regulatory rate case kind of thing? Mark F. McGettrick: Right. Well, I guess the way we think about it is we have an obligation to our customers and shareholders. We're going to be asking customers and our regulators to approve a new $1 billion plus gas facility with 100 basis point premium to replace these facilities. We felt it was appropriate to go ahead and remove them from rate base at the appropriate time, take that charge now and not ask for our customers to pay twice for facilities that will have the same megawatts. Paul Patterson - Glenrock Associates LLC: Okay, so you guys are going to be taking a hit on this, it seems like. Mark F. McGettrick: We'll take a hit -- we took a hit in 2011 on it to our GAAP earnings. Paul Patterson - Glenrock Associates LLC: Now how does that -- you mentioned that these are going to be coming out of 2015 and -- that was the expected life anyway. So does that have a depreciation benefit that we should be thinking about in the next few years? I mean, does that possibly impact EPS. Mark F. McGettrick: No, you shouldn't think about depreciation benefit for the next several years. And we'd be glad to go through the mechanics of write-down with you, with our IR [ph] after the call.

Our next question comes from Paul Fremont with Jefferies. Paul B. Fremont - Jefferies & Company, Inc., Research Division: Just to follow up on Paul's question. We should assume that this gets removed from rate base beginning in 2011 or in 2015 and '16? Mark F. McGettrick: No. We're going to remove it from rate base in 2013, which is when we would have our next biannual review. Paul B. Fremont - Jefferies & Company, Inc., Research Division: Okay. So it would be removed from 2013? Mark F. McGettrick: We're going to take the charge in 2011, and then as we file the biannual review for those 2 years, it'll be included in the 2013 biannual review. Paul B. Fremont - Jefferies & Company, Inc., Research Division: Okay. So this charge then would not apply towards '12 earnings, in the biannual review. We should apply this charge towards whatever you would potentially be earning in 2013? Mark F. McGettrick: No. You should apply the charge to 2011. And on average, the review is done on '11 and '12 earnings. But the actual charge was taken in December of 2011, and that's where you should apply it. Paul B. Fremont - Jefferies & Company, Inc., Research Division: Okay. There was a markedly lower tax rate in the quarter and also a lower tax rate for the year relative to guidance. Can -- what drove that? And should that sort of -- should we -- do we need to make an adjustment on what we assume as a tax rate in 2012? Mark F. McGettrick: I'm going to let Scott Hetzer answer that question for you. G. Scott Hetzer: Paul, the tax rate for the year was better because of favorable settlements from federal audit issues and reduced state taxes and having to do with state tax credits on items like the Brayton Point cooling towers. And in the guidance kit, we have a range for 2012, 36 to 37.5. Mark F. McGettrick: Paul, its Mark. I'd add to that, that we have had a concerted effort over the last couple of years to resolve outstanding IRS audits that date back almost a decade. And the tax group has done a great job doing this. A great deal that benefited in the fourth quarter was a catch-up benefit from those audits. We still have some more work to do on that. And so in 2012, give me a fairly wide range on taxes. Sometimes it's a benefit, sometimes it's a detriment. But we're consistently working on getting as current as we can with the IRS on our federal tax returns. Paul B. Fremont - Jefferies & Company, Inc., Research Division: And the last question for me is if I look at the utility rate base, I guess there's been a lot of accelerated depreciation that's taking place. Is it possible to sort of get an updated snapshot on what that rate base would be at the end of 2011? Mark F. McGettrick: We'll be glad to do that, which we'll have the IR team call you on the breakdown.

Our next question comes from Jonathan Arnold with Deutsche Bank. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Can I just follow-up on this question about what your thoughts around -- not having included the sort of mild start to the year in the guidance score. And did I hear you right that weather was kind of an $0.08 drag in Q4? Mark F. McGettrick: That's correct. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Was that versus normal or year-over-year, Mark? Sorry, didn't... Mark F. McGettrick: No, that was versus normal. It would be about $0.11 year-over-year. Jonathan P. Arnold - Deutsche Bank AG, Research Division: And was it -- and you said most of that was December. So is that also correct? Mark F. McGettrick: Yes. It was extraordinary mild December in Virginia. Thomas F. Farrell: We have 5 days over 70. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Okay. So I mean, I guess, January -- I guess my question is assuming that kind of January has been somewhat similar, do you feel you have enough O&M flex that you could also accommodate that, let's just say, we're just normal from here? Mark F. McGettrick: Well, from what we've seen, Jonathan, from so far in January 1, its nowhere near what December was. December was one of the lowest ones on record in the state. January is not anywhere near that level. And again, what we balance is -- with our other activities. I mean is economy going to be stronger. Is February, March weather going to be better to offset, if there's going to be a shortfall in January? So again, I think we feel real comfortable right now that with all the drivers we have based on what we've seen so far in January, that our guidance range looks good. Jonathan P. Arnold - Deutsche Bank AG, Research Division: So January is pretty less of a drag than December was, so that's good. Can I ask -- and one other thing. Your -- can you comment on where you are on sort of your levels of coal you have under contract going into this year versus, say, where you were last year? Is that appreciably lower or around the same? And as follow on to that, do you expect to see meaningfully incremental switching, in terms of gas substituting coal, given where the curves are, and given how your contracts look maybe in Virginia and also up in New England? Mark F. McGettrick: Okay, Jonathan, let me ask Dave Christian to answer that. David A. Christian: I think you could fairly say that we are solidly in the range of gas-coal switching. We followed this coal parity and have been for some time, and we're solidly in the substitution range now. We saw some of this coming in New England and reduced our coal hedging positions. If you were to look the hedging percentage in the kit, you'll probably see coal hedging at about 26% this year. Last year at this time, it would have been about 70%. So you're seeing significantly reduced coal burns everywhere and saw some of it coming and took some actions. So I think you're going to see a lot of gas burn for the remainder of the year. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Any quantification around how much additional switch might be? David A. Christian: I can tell you what it is for Dominion. We have in 2011, we went -- from '10 to '11, we from 13.5% gas to 17.7% gas. And coal went down by about the equivalent amount. Jonathan P. Arnold - Deutsche Bank AG, Research Division: And any view on how '12 will shake out as you model it now? David A. Christian: Too early to give a percentage number on that.

Our next question comes from Carrie Saint Louis with Fidelity.

Two questions. First, I'm wondering where your annual cash flow guidance that you normally provide is located?

It's in the guidance kit. Mark F. McGettrick: It's in the guidance kits, Carrie?

Okay. I couldn't find it, so I don't know if I'm missing it or what, but I don't know if you know what page it is. Mark F. McGettrick: We'll check for the page -- Page 10. [indiscernible] Okay. It'll -- It's going to come out after the call, and it's going to be on Page 10.

Okay, after the call. All right. And then I was just wondering, it's been a while since I've seen in any of your published materials, like kind of what balance sheet strength and credit quality metrics you guys have been targeting. So I don't know, have you -- maybe you could just provide an update about what metrics you target like a FFO-to-debt metric and what credit quality you guys are hoping to maintain during this large CapEx build? Mark F. McGettrick: I'm going to go ahead and have Scott answer that for you. G. Scott Hetzer: Carrie, it continues to be the credit metrics that would help us achieve the existing ratings. We really like the high BBB rating. And, of course, each rating agency looks a little differently, so we try to get away from specific targets on credit metrics. But they're not different from what you've seen in the recent past.

Okay. But the high BBB is kind of -- because, obviously, you have right now a few different credit ratings, so that's kind of where your modeling the business. Do you define that as kind of roughly around the 20% FFO to debt? Or what ballpark do you kind of look out there? G. Scott Hetzer: That is certainly in the ballpark.

Our next question comes from Nathan Judge with Atlantic Equities. Nathan Judge - Atlantic Equities LLP: I may have missed it, but did you quantify what your last 12 months ROE was at VEPCO if you had taken all those -- after all the charges and adjustments that you've mentioned in the call? Mark F. McGettrick: Nathan, we didn't quantify it, but I would tell you that we believe our ROE for 2011 will be below 9%. Nathan Judge - Atlantic Equities LLP: So is it -- is there a reason why we couldn't see above allowed ROEs to balance that to get to -- you to that average in the second period -- second half of this period? Mark F. McGettrick: Well, there's a lot of drivers that go into that as you know. But the biannual review is based on an average over the 2-year period. And if you were to ask us know, do you believe that we will over earn our authorized return in the biannual period? Our answer to that would be no.

Our next question comes from Dan Eggers with Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: You guys have done a good job managing cost the last couple of years, and you're obviously targeting more, given these conditions. How should we think about kind of the durability of continuing to manage down O&M looking forward? And what sort of inflation rate should we thinking about from an O&M perspective, as you guys look at a 2- or 3-year period? Thomas F. Farrell: Well, Dan, we've been very focused on it. We gave very specific guidance in May of 2010 on what we thought our O&M expenditures will be in '10, '11 and '12. And we're right on target with that. We've taken a more aggressive stance now in '12 than what we've shown, so our '12 expenses will now be below 2011. We continue to optimize our operations. O&M's a huge driver for us. We have flexibility in a number of parts of our business to shape O&M year-to-year, in terms of focusing on different expense levels. So we don't have a specific long-term growth rate on O&M or a reduction level on O&M. We'll look at that as -- along with the other drivers that we have and take advantage of the opportunities that we have. We do have focus on it this year at a lower level. And based on the slides we show, we would expect to drive out an incremental $60 million to $90 million in O&M cost from where we stood last fall. Dan Eggers - Crédit Suisse AG, Research Division: Got it. And I guess the other kind of question is, with the degradation in the forward curves -- this is long-term situation, but are you having any change in conversation with people about some of the gas development needs? Or do you see any slowdown? Or are people are kind of charging ahead even as the recount is being talked down a little bit? Thomas F. Farrell: Dan, it hasn't slowed down at all. Actually, it accelerated in the fourth quarter. Where people are concentrating is in the West formations, which in particular for us is the Western Marcellus. But even more than that, the Utica. I mentioned it in the script. There's a lot in the script, you all could have missed it. It's actually every single well online in Ohio, in the Utica formation, is producing into our gathering systems at Dominion East Ohio. So permitting is going up, drilling activity is going up. But as you note in -- it's not accelerating in the dry gas. It's accelerating in the wet gas, which supports -- and there's not enough facilities in Ohio or West Virginia or Pennsylvania to handle all the wet gas that's coming online. So that's what supports Natrium, for example. And that were not the only one doing it. There are others pursuing these facilities. But we've gotten our share, and we expect to continue to get our share.

Our next question comes from Steve Fleishman with Bank of America Merrill Lynch. Steven I. Fleishman - BofA Merrill Lynch, Research Division: Just a couple of questions. I think Tom, you mentioned something about the one issue that's not clarified on the rate order with respect to the timing of starting it. Could you just clarify that issue? And if it matters at all within the guidance range? Thomas F. Farrell: Well, it doesn't matter in the guidance range, first. Because our rates weren't changed. They weren't subject to being changed. And if we over -- remember, you have to over-earn in 2 consecutive biannual reviews under Virginia law. The commission found we over-earned in the first, which for -- it's for the years '09 and '10. They'll review '11 and '12 in 2013. So what the issue there is -- was this is our view, fairly strongly held view. All the parties agreed in the going-in case in 2009 that the new ROE level for the second biannual review would become effective at the commission's order in the first biannual review or when -- which was issued on December 1. So there's a -- we didn't think it was clear from the order that was entered in December whether they were going to do what that settlement agreement called for, which was that the first biannual review ROE, which was 11.9% apply to the first 11 months of the biannual review, and the new ROE to the second 13 months, or whether they were going to apply to the new ROE to the entire 24 months. It makes a difference of 40 or 50 basis points, I think, on the average of the 2 years. So it's -- we think it's fairly clear, but that's in front of the commissioners under our motion for clarification and they'll rule. Steven I. Fleishman - BofA Merrill Lynch, Research Division: Got you. One unrelated question. Just on the Cove Point export approvals and the DOE process. Could you just go through what their process is? And this has become a bit of a political issue. Just maybe give a little more color on the reasons for support, the reasons against, and your -- how you think you'll be able to prevail? Thomas F. Farrell: When you file for a -- first, we got the NAFTA country permits. That's a fairly simple thing to do, because there's a limited number of countries. What matters is getting the non-NAFTA country permit, which is presently under consideration. When you file for that permit, you have to file an economic impact study with it, which we did and is available for review, and you look at a typical economic impact study what -- they're looking at what are the potential impacts on the price of natural gas, if this permit is allowed. But you also look at the economic activity that is created by the issuance of the permit: New jobs, tax revenues. Things like that, that will occur upstream from the facility: a new pipeline operations, processing facilities, drilling jobs, the jobs that spin off of that to support functions, et cetera. The study we filed shows that there are very significant beneficial impacts and economic activity from allowing the permit to be issued, so they'll consider that. They'll certainly consider other people's views. They'll look at what the potential is for impacts on gas prices out into the future. I think if you look at all of it in a balanced way, with all the gas that's available in this country now, and particularly in this region, we think it is likely the permit will be issued. We expect to have it later this year. And if you look at just the map, if you're going to export gas from the Marcellus and Utica Shale regions, I think it's pretty likely that's going to happen through the Cove Point facility, just because of the close -- how close we are to the region.

We have reached the conclusion of our call. Mr. McGettrick, do you have any closing remarks? Mark F. McGettrick: Yes, thank you. I just want to remind everybody that our next scheduled earnings call will be April 26. And that you should expect our year end K to come out of the end of next month. Thank you very much.

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