Dominion Energy, Inc. (D) Q1 2012 Earnings Report, Transcript and Summary

Good morning, and welcome to Dominion's First 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 a Safe Harbor statement.

Good morning, and welcome to Dominion's First Quarter 2012 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 and register for e-mail alerts and view our first quarter 2012 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 the measures of our company's performance that differ from those recognized by GAAP. Those measures include our first quarter 2012 operating earnings and our operating earnings guidance for the second quarter and full year 2012, as well as operating earnings before interest and tax, commonly referred to as EBIT. Reconciliations of such measures to the most directly comparable GAAP financial measures we are able to calculate and report are contained on Schedules 2 and 3 in pages 34 to 40 in our earnings release kit. Joining us on the call this morning are our CEO, Tom Farrell; our CFO, Mark McGettrick; and other members of our management team. Mark will discuss our earnings results for the first quarter, as well as our guidance for the second quarter of 2012. Tom will update our operating and regulatory activities as well as review the progress we have made on our growth plan. I will now turn the call over to Mark McGettrick.

Good morning. Dominion's 2012 first quarter operating earnings finished at the bottom of our guidance range of $0.85 to $1 per share. Extremely mild weather in our service territory, the warmest in the 100 plus years of record keeping reduced earnings by $0.11 per share compared to normal. Adjusted for weather, earnings would have been in the upper end of the guidance range. Non-weather factors impacting first quarter earnings were lower merchant generation margins and a lower contribution from Producer Services offset by lower O&M expenses, a higher contribution from Dominion Retail and a lower effective income tax rate. GAAP earnings were $0.86 per share for the first quarter. Now, moving to results by operating segment. At Dominion Virginia Power, EBIT for the first quarter was $324 million, which was above the high end of our guidance range. The impact of mild weather was offset by lower storm cost and cost control initiatives. The favorable variance to guidance can also be attributed to stronger than expected margins at Dominion Retail. First quarter EBIT for Dominion Energy was $256 million which was below the bottom of its guidance range. Although Dominion East Ohio's rate structure largely decouples revenues from weather, the mild weather had a $0.01 per share negative impact on portions of its business. Results from Producer Services were also below expectations given the overall weakness in natural gas markets. Helping to offset these negative drivers were lower O&M expenses and lower fuel cost. Dominion Generation produced EBIT of $396 million for the first quarter, which was below the bottom of its guidance range. Mild weather at Virginia Power, lower merchant generation margins and lower ancillary revenues were the principal factors driving these results. Partially offsetting these factors were reduced O&M expenses reflecting actions taken early in the year to offset the impact of lower power prices. On a consolidated basis, interest expenses came in slightly higher than expected but income taxes were below our estimates. A state tax benefit related to our Fairless Works power station helped reduce our overall effective income tax rate to 34% for the quarter. We now expect our full year effective tax rate to be between 36% and 37%. Moving to cash flow and treasury activities. Funds from operations were $1.09 billion for the first quarter. Regarding the liquidity, we have $3.5 billion of credit facilities, commercial paper and letters of credit outstanding at the end of the quarter for $1.1 billion and when netted against short-term cash investments resulted in available liquidity of $2.5 billion. For statements of cash flow and liquidity, please see pages 14 and 27 of the earnings release kit. Now moving to our financing plans. We plan to issue between $1.6 billion and $2 billion of debt this year with a fairly even 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 and have made significant progress on hedging our anticipated 2013 debt needs as well. Today, we have hedged Treasury rates on approximately 50% of our 2013 needs. As part of our 2012 financing plan, we will issue new shares of common stock to our dividend reinvestment, customer stock purchase and employee savings and compensation plans which will raise about $320 million of new equity. In February, we announced a tender offer to repurchase a portion of our outstanding 2006 Series B hybrid securities in order to reduce interest expense. This December, we have retired approximately $100 million of these securities principally through the tender offer. We were pleased with the results of the tender in which we offer to purchase securities at 87% to 90% of par and believe that current trading levels help validate our view on the value of the securities. In total, we have paid prices ranging from 85% to 90% of par since December. And continue to believe that this price range represents fair value to the holders of the securities and to the company. While we would consider opportunities to negotiate purchases of additional amounts, we are not interested in purchasing them at a price above the range we have previously paid. Now to earnings guidance. We estimate operating earnings for the second quarter within a range of $0.55 to $0.65 per share. This compares with operating earnings of $0.59 per share for the second quarter of 2011, which included less than $0.01 of weather help. While it is still early in the quarter, at least through the first 3 weeks of April, the weather has not been favorable. However, weather can have a much greater impact on May and June sales. So it is too early to judge the weather effect for the entire second quarter. Compared to the second quarter of last year, positive drivers for the second quarter include: sales growth at Virginia Power, higher Rider-related revenues from our growth projects and lower O&M expenses. Negative drivers for the quarter are mainly lower merchant generation margins. Our operating earnings guidance for the full year 2012 remains $3.10 to $3.35 per share. Assuming normal weather for the year, we would expect earnings to fall within a $3.20 to $3.25 range or about 5% to 6% above operating earnings for 2011. While first quarter weather was well below normal, summer weather can have a much greater impact on our overall results. So it is too early to estimate where within the overall range we are likely to land. At 2010 and 2011, strong summer weather added $0.14 and $0.08 respectively, to our earnings. As to hedging, you can find the update of our hedge positions on Page 29 of the earnings release kit. Since our last earnings call in January, we have added to our hedges from Millstone in 2012, 2013 and 2014, increasing the hedge percentages to 95%, 80% and 40% respectively. 2015 remains at 24% hedged. Our sensitivity to a $5 move in New England power prices in 2012 is now only $0.02 per share. Our sensitivity to a similar move in 2013 is now only $0.05 per share. As shown on Slide 8, since our last call we have locked in virtually all of our anticipated output for 2012 and 80% of our 2013 output at prices significantly above current market rates. Locking in these positions reduces the risk associated with achieving our earnings growth targets. So let me summarize my financial review. Operating earnings for the first quarter were at the bottom of our guidance range. Mild weather reduced our earnings for the quarter by $0.11 per share compared to normal. Our business units were able to offset the incremental earnings headwinds created by recent declines in commodity prices through reductions in operating and maintenance expenses. Our operating earnings guidance for the second quarter of 2012 is $0.55 to $0.65 per share. Our annual operating earnings guidance remains $3.10 to $3.35 per share. The midpoint of this range is consistent with our 5% to 6% earnings growth target. And finally, we have locked in virtually all of our anticipated merchant margins this year and 80% of 2013. We are confident that through control of operating expenses and taking advantage of the low interest rate environment, we remain well positioned to overcome the current commodity price environment and meet our growth targets. Thank you, and I'll now turn the call over to Tom Farrell.

Good morning. Each of our business units delivered strong operating performance in the first quarter and in every case with improving safety performance as well. Our nuclear fleet achieved a net capacity factor of 98.6% for the quarter with 5 of our 7 units operating at 100%. As a result of low gas prices, our combined cycle power stations operated more than ever. Virginia Power's large combined cycle units achieved a record capacity factor of over 90% and both our Fairless Works and Manchester power stations achieved record output during the first quarter. Units 3 and 4 at our State Line Power Station were shut down in late March. Station personnel are performing operational decommissioning activities which should be complete by the end of the second quarter and at which time, the site will be ready for physical decommissioning. The Virginia City Hybrid Energy Center was over 98% complete at the end of the first quarter. Two major milestones were reached on the project in March. When the unit was first synchronized to the PJM grid and the first fire on coal occurred. Commissioning is proceeding well and commercial operation is on schedule and on budget for the middle of the year. The CPCN and Rider applications for the Warren County power station were approved by the State Corporation Commission in February and construction began in March. The three-on-one combined cycle unit will produce over 1,300 megawatts of capacity at an estimated cost of $1.1 billion and is scheduled for commercial operation in late 2014. The plant will produce significant economic benefits for our customers. The company advanced plans for another 1,300 megawatt three-on-one combined cycle plant to be located in Brunswick County, Virginia. The plant, additional transmission and the installation of environmental controls at 2 existing oil units are necessitated by the HAP's MACT rule issued by EPA last December. The projected in-service date is 2016 and is expected to cost about the same as the Warren County Project and will also offer significant value to customers. Like Warren County, we have chosen the gas and steam turbines from Mitsubishi Heavy Industries for the Brunswick plant. We are currently soliciting engineering procurement and construction bids and expect to file the CPCN and Rider applications with the State Corporation Commission later this year. Also in March, the commission approved the applications for conversion of the Alta Vista, South Hampton and Hopewell power stations from coal to biomass. Air permits are expected to be issued sometime this summer following construction to begin with commercial operations anticipated -- allowing construction to begin with commercial ops anticipated prior to the end of 2013. Dominion has notified the federal government that it is interested in obtaining leases off the Virginia Coast in an area of 113,000 acres that has the potential to generate approximately 1,500 to 2,000 megawatts of electricity from offshore wind turbines. Virginia State Corporation Commission would have to approve any Dominion Virginia Power offshore wind generation project. Our growth projects for our electric transmission continue to move forward. The rebuild of the Mt. Storm-to-Doubs line is underway with 58% of the foundations and 9% of the conductor installed. The line is currently out of service for rebuild and is expected to be put back into service for the summer months. PJM has notified the company that when it takes the line out of service again this September, we can continue construction through mid-May 2013. This will enable more efficient construction cycles and should advance the projected closing of the project from mid-2015 to the end of 2014. Mt. Storm-to-Doubs is just one of the many growth projects in various stages of development at electric transmission. We anticipate annual investment of $500 million in upgrades and enhancements through at least the end of the decade. Dominion Energy also made significant progress on its growth program in the first quarter. Construction of our $634 million Appalachian Gateway Project began last summer and the project is expected in service by September of this year. FERC approval for the Northeast Expansion Project, as well as the Ellisburg-to-Craigs project was received in the third quarter of last year. Both projects are expected to be in service by this November. Construction has begun on Phase I of the Natrium Processing Project, which is expected to cost about $500 million and should be into service by this December. Even with depressed natural gas prices, we remain confident that wet gas lines from the Utica formation will meet or exceed expectation. Many producers have directed rigs from dry to wet shale plays to capture the uplift from the heavy hydrocarbon liquid. As of the end of the first quarter, Ohio has issued 192 horizontal well permits to 11 different Utica producer. 77 wells have been drilled or were being drilled in the formation. Currently, we are the only company gathering and processing wet gas from the Utica shale. We are in discussions with multiple producers for volumes to support the possible construction of Phase 2 at Natrium, which could be in service by mid-2014. We are pleased to announce today that we are moving forward with our Cove Point Liquefaction project. At the end of March we signed binding precedent agreements with 2 companies, one of which is Sumitomo Corporation, a major Japanese company with significant global energy operations. Between the 2 shippers, the planned project capacity of about 750 million cubic feet per day on the inlet and about 4.5 to 5 million metric tons per annum on the outlet is fully subscribed. Dominion will provide liquefaction, storage and loading services but would not own or directly export the LNG. We are continuing to negotiate binding terminal service agreements with the party and expect to complete them later this summer. Last October, we filed for approval to export up to the equivalent of 365 Bcf of LNG per year for a 25-year term to non-free-trade agreement country. Our filing supports our belief that the project will have many positive economic benefit and we are hopeful for DOE approval later this year. We plan to submit a request to FERC early this summer to initiate the prefiling process for approval of the project which may take up to 2 years. Engineering studies are underway and we will provide a cost estimate for the project at a later date. Subject to successful completion of engineering studies, execution of terminal services agreements and provided we receive the necessary approvals we anticipate beginning construction in 2014, with an in-service date in 2017. As with any project of this magnitude, we would expect some opposition from various environmental and special interest groups. For example, the Sierra Club, which is a party to an agreement restricting activities on a portion of the Cove Point property has expressed its opposition to LNG export facilities and to frac-ing process in general. We have reviewed the various regulations, agreements and rulings from various regulatory bodies governing the site and are confident that we will be able to locate, construct and operate a liquefaction facility at Cove Point. Dominion plans to design the facility to minimize environmental impacts. Economic growth is expected to drive improving results for Virginia Power. PJM's updated load forecast projects peak demand growth in the zone that includes Dominion Service territory of 1.9% per year over the next 10 years for an increase of nearly 4,000 megawatts. Unemployment in Virginia is 5.6%, well below the national average of 8.2% and that is actually below 5% in Northern Virginia. New connects for the first quarter were up 13% over the first quarter of 2011 and we now estimate a year-over-year increase of 3,200 or more than 10%. Weather-adjusted sales at Virginia Power were up 1.1% for the first quarter. Our estimate for weather normalized sales growth for all of 2012 is 2% to 2.5% for Virginia Power with data centers continuing to be a strong contributor to our growth. On the regulatory front, we submitted an application for an increase in base rates for our North Carolina service area. The request is for a revenue increase of $37 million, net of fuel rate reductions and incorporates an 11.25% return on equity. Next week, we will make our annual fuel rate filing in Virginia. Because of low commodity prices and mild weather, we anticipate a significant reduction in the fuel rate as well as the overall bill for customers more than offsetting any Rider-related increases implemented this year. Furthermore, our annual electric transmission Rider update which we also plan to file next week will result in another reduction to customer rate. So to conclude, all 3 of our business units performed well and delivered results that given the mild weather, met our expectation. 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 we are now ready for your questions.

[Operator Instructions] Our first question comes from Paul Fremont with Jefferies. Paul B. Fremont - Jefferies & Company, Inc., Research Division: In the past, you guys have talked about potentially not doing the construction all on your own, potentially partnering or finding somebody to take an interest. Should we assume at this point that it's your intention to pair up with other parties or is this something that you would take entirely onto your balance sheet?

Paul, this is Mark. We're looking at all options on Cove Point and as we get closer to what a final construction price might be, that'll help guide us which way we might do. We may do it all ourselves. We may take on a partner. We're certainly looking at various financing options, all of them that you can think of. But until we get a little more clarity on exactly what this facility is going to cost, we're keeping everything open. And as soon as we know what that is, we'll come out with a comprehensive financing plan and what the best option is for our shareholders and our balance sheet. Paul B. Fremont - Jefferies & Company, Inc., Research Division: Also, you talked about hedging. I'm assuming that because interest expense is projected down this year, that a significant amount of that is through interest rate swaps. Can you give us some color in terms of the magnitude of interest rate swap transactions that you've done? And also, how far out into the future do those swaps mature just for modeling purposes?

Well, we said on 2012 we put swaps in place for all of our anticipated debt needs for 2012, which is $1.5 billion to $2 billion. For '13, we announced today that we put swaps to around about 50% of that debt need. And although we haven't specifically said what that debt need might be for '13, you should think probably in a range of $1.5 billion to maybe $2.2 billion at this point. We anticipate continually to put in swaps for '13; it's a de-risking measure that we've been doing for a number of years and it's really helped us significantly. Paul B. Fremont - Jefferies & Company, Inc., Research Division: So in terms of a maturity profile, do these go out years? Do they go out like 1 or 2 years? How far out into the future do they go?

Let me go ahead and have Scott Hetzer answer the question.

Paul, they are scheduled to start -- these are swaps that are scheduled to start either in '12 or '13. And the term ranges from 5 to 10 to 30 years depending on what kind of security we're hedging. Paul B. Fremont - Jefferies & Company, Inc., Research Division: Okay. So they would -- the swaps would be commensurate with the maturity date of whatever it is that you're issuing, right?

That is correct. Paul B. Fremont - Jefferies & Company, Inc., Research Division: Okay. And last question, on New England volumes, you guys were down 18% in the first quarter. Your projection in the second quarter -- and you were, I think your projection for the first quarter was roughly flat. In the second quarter, you're only projecting that you'll be down 5%. Is that because the first quarter lower volumes in New England were somehow related to the mild weather or how should we think about that?

No, Paul. The reason for the second quarter being fairly flat is last year we had a Millstone unit outage in the second quarter. This year we don't. And conversely, we do not expect much run time at all out of our coal units in the second quarter.

Our next question comes from Stephen Byrd with Morgan Stanley.

I just wanted to explore the LNG export a little bit further. As we think about, over time, the earnings power of this opportunity relative to the import revenue and the import earnings that you are currently achieving, how should we think about in terms of just the transition, the construction work? And then ultimately, once export is up and running, how should we broadly think about how the existing import work and revenue would mesh with the export capability?

The Cove Point has different contracts on it on the import. The original portion of it was sold out to 3 parties. The major expansions sold out to one party. There are -- we have the opportunity with the second piece of it to use that part of the contract for importation and exporting. So as we work through the course of this time, you'll see that portion of the contract will be used for export. It's too early -- we're not at a point where we're going to start talking about what the earnings profile is from this facility because as of today we still haven't locked down the cost, financing, exact timing. It's not, when you look across our website and look at what our 5-year growth plan is and the growth CapEx, it still shows nothing related to Cove Point's liquefaction facility. We'll fill that in as we have more clarity on the costs.

Okay, understood. But broadly speaking, should we expect that the import contracts, volumes, revenues, broadly speaking, would over time start to decline as you start to ramp up your export revenues?

A portion of the import.

Your next question comes from Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Just one more LNG question then maybe we'll have them all done. But can you just explain to me as a non-lawyer, what the agreement actually means from a commitment perspective from you guys to the partners and their commitment to you during the process of getting the permits and the engineering work done?

Dan, this is a sort of term of ours in the pipeline business and it's the kind of thing we do all the time when we're doing capacity expansions on the pipeline system. If it's a non-negotiate, not a -- a typical FERC-governed transaction, we'll do an open season. We'll see what people's interests are. If we have a project that we say we wanted to be $500 million a day, we'll gauge interest. People will come in and say, hey, we're interested. And maybe people say there's $750 million a day worth of interest. We'll then sit down with them and negotiate what are called in the industry, binding precedent agreement, which commit both parties through parameters, financial parameters, around the project. There are a variety of things that have to happen as you go through the final negotiations, in this case, for a terminal service agreement or in a more traditional case, a pipeline capacity agreement. So it's -- we're in the same spot we are on -- where we are when we're doing sort of almost any kind of pipeline related expansion. We have found 2 parties who are going to take all of the capacity. The overall financial terms are established and then there's certain criteria that we have to meet, they have to meet and we'll complete that as we go through the terminal services agreement. But it is a -- not a 100% commitment that nobody can change but it is well down the path to that level. We would not have announced it otherwise. Dan Eggers - Crédit Suisse AG, Research Division: I guess kind of the next question around the development of this project. There's been some talk that having the Japanese partners was important. Obviously, [indiscernible] was part of their arrangement. Is there something politically expedient to having Japan as kind of an offtake party to help with the getting the export license or do you think this was just the best partner available?

Well, we had a lot of interest, Dan, from both Asia and European customers. And as we went through the variety -- the negotiations with a variety of partners, between the other partner, we'll -- when the time comes, we will announce who that is, I shouldn't call them partners, the other customer, these turned out to be the best for them and best for our shareholders. I think politically, obviously, the Japanese are strong allies of our country but so are European potential customers. Dan Eggers - Crédit Suisse AG, Research Division: Okay, got it. And I guess one last question, Mark. Just as far as guidance is concerned with the first quarter coming out where it was and the second quarter kind of flat year on year, there's some makeup that has to be done to get to the bottom end of the range for guidance for the full year. Is there anything markup-wise in earnings we should be thinking about? Or is it just kind of a natural progression with investments coming into service and freights going effective?

Dan, it’s kind of an unusual year. If you think about the fourth quarter alone, year-over-year, normal weather in the fourth quarter for us will pick us up $0.08 year-over-year. If you recall, we had a very, very mild fourth quarter of 2011. In addition, in the fourth quarter, we have Gateway pipeline project coming on in September and we have Natrium coming on in December. So our earnings profile is very back end loaded this year in third and fourth quarter.

And your next question comes from Paul Ridzon with KeyBanc.

Relative to your first quarter guidance, Dominion Generation materially outperformed. What drove that?

Generation was actually below their guidance range for the first quarter.

Okay, I must have misread something, sorry. And then, your annual growth is 2% to 2.5% but first quarter was 1%. What -- is it just the data centers that's going to drive the back half?

First quarter was on a weather normalized basis 1% to 1.5%. The data centers actually were a little slow in the ramp up in the first quarter which depressed that sales number a bit. And as Tom talked about, we've seen very strong new connect activity in the quarter. Job growth in the state is maturing quickly. We're seeing recovery in some of the residential markets. So while the first quarter is lighter than we'd like, we still think 2% to 2.5% on an annual basis is achievable.

And now that you've I guess gotten much closer around Cove Point, how are you thinking about the MLP option?.

MLP will be one of the options we evaluate with a lot of other options in terms of how that project might be financed long term. And we looked at the MLP option before a number of times and didn't fit us. We'll continue to look at it as Cove Point matures in terms of a project life to see if that's the best option for our shareholders. We have no view on that currently except it's one of many that we'll look at.

Your next question comes from Jonathan Arnold with Deutsche Bank.

Could I just assert one thing quickly on Cove Point? You haven't disclosed the other party, but is this a different kind of party than you have the arrangements with on the import or is it one of the same parties? Can you at least disclose that?

That was a very effective question, Jonathan. But despite that -- how good the question was, I can't answer it. We will -- it's -- each company has its own way of going about things. We will, when this counter party is prepared, we will then announce it. And I don't think it'll be in this too distant future.

I'm sorry to revisit this but I just didn't quite kind of follow the answer, Tom, but to what extent does this new project sort of limit the potential of your existing import business?

I would think about it differently. I would think about what we will have is the facility that will allow both the, in a single place, allow both the import and export of gas into the mid-Atlantic, right into the heart of the market. That's why we think it is attractive as it is. But it can't be used for both at the same time all the time. But there are -- there's 2 parts of the pier, you can load and offload at the pier, there's different pipes going out to the pier. There are multiple tanks. There is a vaporization facility. There will be a liquefaction facility. So the parties who will have these contracts will have -- certain of them will be allowed to import, certain of them will be allowed to export and we think you should be thinking about it that way rather than segmenting.

So it's -- but it's not kind of fully incremental then, it'll just depend on what the relative pricing situation is, whether it's being used for one or the other?

I believe that's correct but that'll be up to the party. They'll be paying us once a month, come rain or shine.

Okay. And then on, your slide said you would have no ownership or sourcing of LNG. In the way those contracts are structured, is there any sort of commodity or sort of volume derived commodity exposure or is it just pure and simple flat pricing?

Pure and simple capacity theme. No, we will -- there is no commodity risk associated with the income stream at all.

Okay. And then if I might just have one other. On the sales question. I think you gave a number of 1.1% weather adjusted, was that also adjusted for the leap year or was that kind of including the leap year?

No, that includes the leap year.

So absent that, that would have been down a little?

Actually, it would've been fairly flat. But -- yes, that's why I referenced, we have a few things that were delayed based on initial expectations. But again, based on the activity we see, we think it’s certainly achievable to still reach the ultimate 2% to 2.5%. But you're right, leap year really reflects most of the growth in the first quarter.

Okay. And then so if tough connects were up then usage must have been down?

Yes, the other thing I referenced, Jonathan, is although we've done the best job we can and as you estimate weather and economy, in an extreme weather quarter, it's very, very difficult to be penny accurate on what goes in what bucket. So again, I think the second quarter will give you a better reflection maybe even third, in terms of what the real growth is here in Virginia.

Fair enough. And then if I can just slide in one other thing. The -- it sounded like this Fairless tax benefit, state tax benefit must have been about $0.04, if it brought your tax rate down to 34% from 37%. Is that accurate and what drove the timing on that?

It was about $0.03. And what it was surrounding is we had some historical tax losses at Fairless. And if you recall, that was a capital lease which we had to bring on balance sheet late in the fourth quarter of last year. And by bringing it on balance sheet along with some future earnings projections based on current gas price environments, it allowed us to utilize some of those tax losses earlier than what we thought this year.

Our next question comes from Paul Patterson with Glenrock Associates.

I'm just circling back with this liquefaction stuff. As you know, the energy markets can be volatile and the politics around them can be volatile as well. And there is, I guess, with some of these licenses, the ability for the U.S. government to restrict exports for national security reasons or what have you, and I'm wondering how you look at that risk and how you dealt with that with respect to this project?

We're not getting into details with the contracts, Paul. That is a risk that we believe has been taken care of then protects our shareholders.

Okay, great. And just, in general, from your market outlook, how many of these export facilities do you guys see being built in North America? Do you -- I mean, you guys must have been sort of looking at the market or is it just, does it really matter I guess at this point because like you said you're just basically going to be getting capacity payments and what have you, any thoughts there?

Well, I don't -- in our particular case, it really doesn't matter. I'm very confident that we will get the permit from DOE and the environmental permit from FERC. And we will go ahead with the project and we will be getting capacity payments for more than a couple of decades from this facility. As far as overall, I think there are 13 or 14, I think, the number has grown to, permits that people are seeking. And it sort of reminds me of what was going on in the late '90s about how many people were going to build gas fire power plants all over in the United States. And then later about how many people were going to build import facilities all over the United States. And there were many, many announcements made, many, many, many permits sought and a handful actually happened. So I don't really know, Paul, 4, 5, 6 billion a day maybe would be allowed to be exported or could actually come to -- whether allowed or not, actually built, a facility built. But I don't think it's going to be the 13 that are seeking approval now.

Our next question comes from Michael Lapides with Goldman Sachs.

Got one Cove Point question and then a question or 2 at the utility and at the rest of energy. On Cove Point, can you just reaffirm or reiterate what the size of the facility would be or the size of the facility as you've kind of signed up in the agreement so far?

It'll be the equivalent of 750 million cubic feet a day. That's not what LNG guys use, as they use tons, but the amount of gas that will come into the facility which will be liquefied, will be about 750 million a day.

And is that smaller than what you filed for? Because I thought you all had filed for like a B a day or 7 mtpa a day, kind of roughly?

Yes.

Why do smaller size? Is that just a contract issue or construction issue or just why the difference, is all I'm trying to understand.

We think it's the optimum size for this site and with these parties.

Got it, okay. O&M, you all did a really good job of managing O&M in the first quarter. How should we think about the O&M trajectory at VEPCO and at Energy throughout the course of the year? Meaning were your O&M savings more front-end loaded? Were they more -- are they going to even get greater year-over-year as we get towards the back end of the year?

Michael, they're going to get greater as we move through the year. But I want to make sure I point out the -- on O&M, if you look at the disclosure, if you look at the operating O&M, it drops quarter-over-quarter by about $136 million. $99 million of that has to do with a bad debt rider in Ohio that's trued up every year. And so the bad debt level got lower, that's passed on to customers, but your revenue stream also was reduced, so it's a net 0. So if you look at the quarter, really quarter-over-quarter, operating expenses were down about $0.04 or about $37 million, which was very positive for us. And you should look for us to build on that throughout the year. We said on the last call we expect to reduce expenses between $0.06 and $0.09; you should look for us to be at the high end of that range.

Got it. Understand and love my use of [indiscernible] there. Last thing, at electricity demand at VEPCO. Is there concern that there is a structural change among residential and small commercial customers, not necessarily in terms of the new connect but in terms of the usage per customer of installed customer base?

Look, I'm going to let Paul Koonce comment on that.

Michael, we've not seen that. Obviously, quarter-over-quarter the volumes are down but that really has to do with the weather. We've not really seen a structural change. We have a dynamic pricing pilot in place in Virginia right now. And right now we have about 800 customers that have signed up for that rate structure. So we've really not seen any structural change in usage.

So meaning kind of, just kind of think through energy efficiency or some of those other items whether they're actually causing a reduction in electricity demand through the service territory on a weather normal basis?

Well, I mean, we still see customer additions. We still see electronic devices going into the home. So no, we've not begun to see that.

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

Not to beat a dead horse, but just one clarification question. Do you need to restructure any of your import agreements as part of the export? The other agreements you signed today?

No.

Okay.

We've announced, remember a year ago, that we had restructured one of the import contracts.

Okay. So even though you don't control the capacity, that's not relevant.

We do control the capacity as the result of the renegotiation of the import contract which we announced last year. We're not, when I say no, it is...

So you were planning ahead for this?

We did what we needed to do a year ago.

Great. And then just, Tom, I think you kind of answered this question already but I'll ask it again. Just the DOE, the political aspect that's gone on with the DOE review and the like of export. How concerned are you about that? And does it feel like we're in a bit of like a rush to capture what could be somewhat of a limited audience because of that or is...

Well, we're certainly not in a rush. I mean, we started working on this a couple years ago. As we saw -- you think about first -- let's just back up a little bit. The Appalachian region produces, forget the shale, okay, just conventional gas in Appalachia is about a B a day production. So you can fill this facility up to export and leave 1/4 of Appalachian production left for domestic consumption. So you've got -- we'll export $750 million a day through this facility, for our customer if we want. So there is an abundance of gas in the region. Shale has made that much larger. The economic study that we filed with the permit for the non-NAFTA countries shows enormous economic benefits to Calvert County, Maryland, all of Maryland, all of the Ohio basin, the Appalachian basin, the Ohio River basin that will be, all of the job growth, tax revenues, it's many, many tens of millions of dollars. This project by itself will increase or help our balance of trade by a couple of percentage points on an annual basis. So there are -- the economic arguments are pretty straightforward and they're almost overwhelming that it is beneficial to the United States, the region, Maryland, Calvert County to allow this facility to be built. So that's why we're confident that it will be approved. It doesn't hurt of course, to have a counterparty, at least one counterparty from Japan.

Okay, one last question. Just retail did a lot better this quarter but it seemed like the volumes were flat. Are you just seeing better margins in retail?

Paul Koonce will take care of that.

Yes, Steve, just lower supply cost. We've seen obviously wholesale power prices are down, natural gas prices are down and that's coming through in the form of higher margins at retail.

Our next question comes from Nathan Judge with Atlantic Equities.

Just wanted to ask what your thoughts were on the potential expansion of North Anna now that you have this contract signed.

For the expansion of North Anna 3?

Yes.

Talking about building North Anna 3. And I assume you're -- implicit in that question, Nathan, I'm not trying to ask your question for you. Implicit in that is that there's large capital costs associated with 2 projects.

Yes, also and just more of a general concept of what your view of building a new nuclear given the natural gas price environment as well, just as a concept?

Okay. We will -- we're pursuing the combined operating license, and MHI is pursuing the design approval. We expect those to occur early '15. We will continue to pursue those. We are -- we believe we will receive both. MHI will get the design approval, we will get the COL. At that time, we're going to assess where we are. Now, I would say this though on a broader basis, if we were contemplating -- if we had been contemplating building a merchant nuclear power station, I think I would have been able to give you a much shorter answer to your question about North Anna 3. But we're not. We believe that it is best for our customers for the long term to have a balanced fuel mix. And by long term, I'm talking over the next 50 or 60 years. Having 4 nuclear power stations in Virginia is one of the reasons why we have among the lowest rates in the United States, and among the lowest on the East Coast. So we think it's important to keep all that in context as you make those kind of decisions. I believe North Anna 3 will be built by our company. I don't know if it will be in 2015 or 2018 or 2020. But we will -- North Anna and Surry's existing units will have to retire in 2030 through that decade. And we're going to need to have nuclear power in the state to keep a balanced portfolio. So I would give you 2 different answers. One, if we were a merchant, I would have just said what's North Anna 3? I don't know what you're talking about. But we're not. We're in a regulated environment where it's important for our customers to have a balanced fuel mix.

Just as it relates to capital constraints, if you were indeed building, as you mentioned, the LNG facility around 2014. Perhaps you started to spend capital on North Anna. Is there actual enough capacity to then add on offshore wind?

Well, that's also a good question. Probably offshore wind and North Anna probably would not go forward at the same time. I think that's unlikely.

Do you have a better sense of when the offshore wind could come to fruition if it does?

I think that's going to be a long permitting process. They haven't even done the lease sales yet but it's one that we're going to continue to observe and participate in. But I think it's a long process.

Our next question comes from Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: On the Sierra Club and their complaint against you guys, I guess there's some confusion over what their -- what the agreement originally was and if you can just kind of share how you think you can work around their complaints, as they see them today?

Well, I don't think there's any confusion about it. The agreement -- there's an agreement that was entered into I think in the 1990s that has sort of carried through this process with the Sierra Club. We've had a very cooperative relationship with the Sierra Club all through that time. We've been very good partners with each other. We hope to continue to be, as we move into the liquefaction. I'll let them speak for themselves but the agreement allows us to use the existing footprint and we're carrying on LNG operations to perform liquefaction exercises and to deliver liquefied natural gas for the terminal. So I don't think there's really a lot of confusion about it. It's pretty clear in black and white. I'll let them speak for themselves. We would much rather, as we do with all folks -- all stakeholders in which we're going to have an impact. We like to work out cooperative arrangements. We always have with the Sierra Club. We hope that we can as we go along here but we have the right to build it and we're going to proceed accordingly.

Thank you, ladies and gentlemen. We have reached the conclusion of our call. Mr. McGettrick, do you have any closing remarks?

Yes, thank you. I appreciate everybody tuning in today and just want to remind everybody our second quarter earnings release is scheduled for August 1. And our first quarter Q will be distributed today. Thank you very much.

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