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Dominion Resources Inc (NYSE:D)

Q4 2005 Earnings Conference Call

January 26th 2006, 10:00 AM.

Executives:

Thomas F. Farrell, President and Chief Executive Officer

Thomas N. Chewning Executive Vice President and Chief Financial Officer

Duane C. Radtke EVP and EVP, Consolidated Natural Gas Company

Analysts:

Greg Gordon

Faisel Kahn

Steven Fleishman, Merrill Lynch

Dan Eggers, Credit Suisse First Boston

Paul Fremont, Jefferies

David Schanzer, Janney Montgomery Scott

Operator

Good morning ladies and gentlemen, and welcome to Dominion Fourth Quarter Earnings Conference Call. We now have Mr. Tom Chewning Dominion Executive Vice President and Chief Financial Officer in conference. Please be aware that each of your line is in listen only mode. At the conclusion of Mr. Chewning’s presentation, we will open the floor for question. At that time instructions will be given as procedure to follow, if you would like ask a question. I’ll now turn the conference over to you Mr. Tom Chewning, sir you may begin.

Thomas N. Chewning, Executive Vice President and Chief Financial Officer

Good morning and welcome to Dominion fourth quarter 2005, earnings call. Joining me this morning are Tom Farrell our President and CEO and other members of our management team. This morning I’ll first review actual fourth quarter and full 2005 earnings. Tom Farrell will give his review of 2005 operations, as well as offer his perspective on Dominion's focus for 2006. Following Tom's remarks, I will provide 2006 earnings guidance and reconcile the 24 month period from January 1st, 2005, to December 31st, 2006, to the outlook we had discussed during our last call with you on November 3rd, 2005. Before answering your questions, we will offer our current perspective on the drivers that will create a significant uplift in Dominion's earnings in 2007 and beyond.

Concurrent with our earnings announcement this morning, we've published several supplemental schedules on our website. We ask that you refer to those exhibits for certain historical quantitative results as well as earnings guidance detail. From time to time during this call we will refer to certain schedules included in our quarterly earnings release or to pages from our 2006 earnings guidance kit, both of which were posted this morning to Dominion's website. That website address is www.dom.com/investors

Let me start by providing the usual cautionary language. The earnings release and other matters that may be discussed on the call today 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 10K and quarterly report on Form 10Q, for 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 about our company's performance that differs from those recognized by GAAP. You can find a reconciliation of these non-GAAP measures to GAAP on our Investor Relations website under "GAAP Reconciliation."

We're very pleased with our fourth quarter operating earnings of $1.02 per share. This compares to our fourth quarter operating earnings guidance of $0.60 to $0.70 per share. Exceeding our quarterly guidance is directly related to the earlier than expected resumption of hurricane delayed gas and oil production in the Gulf of Mexico. This early return of production resulted in $0.38 per share benefit to earnings. Following the hurricanes, we forecasted fourth quarter production delay totaling 66 Bcf equivalent.

About 23 Bcf equivalent was resumed ahead of our initial projections resulting in a fourth quarter delay of 43 Bcf equivalent. In addition to the early return to production, we recorded a $0.23 per share non-cash market to market gain on hedges that would be designated in Q3 due to the hurricanes. The positive mark is due to lower 2006 gas and oil prices as of December 31st compared to those prices on September 30th. These positives were offset by lower than expected natural gas prices and increased locational basis differentials net of basis hedges. This reduced potential income by $0.17 per share.

GAAP earnings for fourth quarter were $0.74 per share. The difference in the quarter between GAAP and operating earnings is primarily attributable to a 51mm dollar impairment of a note receivable related to the 1998 sale of merchant generation facilities to Calpine and $14mm book loss primarily from the sale of the company's equity interest in certain non-core merchant facilities. Full year operating earnings of $4.53 per share exceeded our updated guidance of $4.11 to $4.21 per share provided in November. The difference between actual and guidance is explained by the same factors that reconcile our Q4 actual to guidance. GAAP earnings for 2005 were $3 per share. In addition to Q4 items excluded from operating earnings, the primary difference between GAAP and operating earnings is attributable to the effects of Hurricanes Katrina and Rita discussed on our November call. A reconciliation between quarterly and annual GAAP and operating earnings can be found in Schedule 2 of this morning's earnings release

For the 12 months ended December 31st, 2005, funds from operations to interest coverage was 3.7 times. At December 31st, adjusted debt to total cap ratio was 58.1% compared to 59.5% at the end of third quarter. Our available liquidity was $2.2 billion. Now I’ll turn the call over to Tom Farrell for his comments. Tom?

Thomas Farrell, President and Chief Executive Officer

Thanks Tom, and good morning everyone. 2005 operations and results met or exceeded the goals we established at the beginning of the year, except for oil and gas production delays resulting directly from hurricanes Katrina and Rita. During 2005 we successfully integrated an additional 3,300 megawatts into our generation fleet, an increase of 13%. This includes Dominion New England with units at Brighton, Manchester, and Salem, as well as the Kewaunee nuclear plant in Wisconsin. It made us the largest generator of electricity in New England. Our nuclear fleet had an outstanding year in 2005, achieving a capacity factor above 92%. In Virginia we achieved record nuclear generating performance of 28.6 million MWh compared to the previous record of 28.3 million MWh accomplished five years ago. All of our merchant nuclear plants exceeded expectations

Our fossil units performed extremely well during our first year in PJM, achieving a peak season equivalent availability of 96%, the highest since 2002. At Energy, we successfully integrated into PJM effective May 1st, and met 15 new peak days without any operational incidents. We received approval for new rate structure at Dominion Transmission for a five year period, and mitigated the financial impact through operational efforts, including producer services and near record results in the gathering and by products businesses.

The Delivery business in 2005 connected over 75,000 new electric and gas customers, set four new electric load peaks on its system, and saw its four year average annual growth in electric demand increase to almost 4.7%. Virginia continues to have a thriving economy. While meeting this increase in demand we were also able to improve our electric service reliability by 8%.

Turning now to our E&P business. During Q4 we were able to restore Gulf of Mexico production from a pre-hurricane level of 435 million cubic feet equivalent per day to over 500 million a day yesterday, utilizing both permanent and temporary repairs. This still leaves about 80 million a day unavailable because of third party infrastructure, but we expect those repairs to be completed by the end of second quarter. We expect additional volumes to come in over the course of the next two quarters and reach a peak rate of about 550 a day by the end of June. During 2005, we had a reserve replacement ratio of 200% at a finding and development cost of $2 in Mcfe. That brings our total reserves at year end to 6.3 Tcfe compared to 5.9 Tcfe at the end of 2004. These reserve levels have been fully reviewed by Ryder Scott, which is the independent auditor for our entire E&P program.

During 2005 we drilled 955 net wells in the United States, a new record for Dominion. In 2004 we were the nation's leader in drilling activity. During late 2005 and early this year we have added discoveries for extended new production wells at a variety of locations. Some of the highlights include, Spiderman Well No. 3, our discovery at Q, West Cameron 130, West Cameron 100, Devils Tower is now producing greater than 37,500 barrels of oil equivalent per day net to Dominion. And we have had multiple discoveries in the deep Anadarko Basin in Western Oklahoma.

Our plans for 2006 remain unchanged from what we have said on our last three quarterly calls. We will continue to concentrate on operations, particularly fuel management, as well as oil and gas production. We are setting our E&P production guidance for 2006 in a range of 445 to 455 Bcfe, which compares to 383 Bcfe produced in 2005. The 2005 figure was obviously affected by hurricanes Ivan, Katrina and Rita. There are several factors that keep 2006 forecasted production growth from being even higher. These issues other than perhaps royalty relief will be resolved this year and will not carryover to 2007.

They include as I said a moment ago Rita and Katrina, third party infrastructure issues reduce our daily Gulf of Mexico production by about 80 million a day for a total of 10 Bcfe during 2006. All of which we believe is covered by business interruption insurance. Based on the December 31, 2005 strips, we expect to lose about nine Bcfe from our own account because higher prices are causing a phase out of US Government royalty relief. In other words, the oil and gas will be produced, but nine more Bcfe must be credited to Uncle Sam's account to satisfy our royalty obligations. The reduced royalty set aside we enjoyed at lower prices disappears at current price curves. One remaining issue from Ivan will cost us about 4 Bcfe. The main pass oil pipeline will not be finally restored to service until the end of February.

Oil performance at the Front Runner wells net of improved production from our onshore gas factories is causing us to reduce our original plan by about 9 Bcfe. As we told you in November, the shape of the Front Runner production has flattened from our initial forecast resulting in lower 2006 results, but increasing our 2007 and 2008 projections. In other words, while less oil will be produced by Front Runner 2006, more will be produced in 2007 and 2008 than we had planned.

Tom Chewning mentioned the financial impact on our 2005 results of the basis differentials being experienced by the entire E&P industry. 2005 hurricane season caused the greatest amount of damage to supporting infrastructure in transportation in the history of the Gulf of Mexico. That infrastructure has still not fully recovered. The loss of the infrastructure has caused very significant discounting across a variety of basins as producers compete for limited transportation capacity by reducing their pricing. The differentials cost us about $0.40 in fourth quarter 2005. And the issue is lingering into 2006. Sitting here today, we see as much as $0.30 to $0.40 impact over the course of the entire year. The $0.40 in quarter four of 2005 and maybe as much as $0.40 over the course of all of 2006. The differentials, though, are reverting to the norms we have seen for many years as infrastructure in the Gulf is returned to service. We're confident that the regional pricing differences will be eliminated by year-end.

Because of our unique set of assets, we have been able to make up some ground in first quarter 2006 at Dominion Energy through optimization through our storage and pipeline assets and capacity position, in other words being on the other side of some of this discounting. I'd like to turn to 2007, 2008 and 2009. For those years all of the structural drivers we have discussed over the course of 2005 remain unchanged. I want to review several of the most important that will occur as the calendar turns in 11 months.

First, our oil and gas production will grow five to 6% annually on average from 2006 through at least 2008. The growth in 2007 over 2006 will exceed that average at a pace of over 10%. The growth drivers are in place and include the expiration of the three volumetric production payment agreements we executed in 2003, 2004 and 2005, returning a total of 43 Bcfe to our own account by the end of 2008. Schedule showing that detail is on our website. But for order of reference, 8 Bs will come back to us in 2006 and 23 Bs will come back to us in 2007. Front Runner and Devils Tower will achieve peak production during the 2006-2008 periods. While Front Runner has cost us some production in 2006, as I said because of the flattening of the curve, we will have a higher production than expected from those eight wells in 2007 and 2008. The 2005 hurricanes have also impacted the service industry in the Gulf. Delays in rig and completion equipment will result in less growth in 2006, but more in 2007 and 2008 than originally planned.

The Eastern Gulf of Mexico wells we have previously announced, including Spiderman, San Jacinto, and Q, will come on line during 2007. These wells and their related infrastructure are on their original schedules. Thunder Hawk will come on line in late 2008 or early 2009. We will, of course, have continued onshore expansion. Because of all of this activity, we forecast that our production in 2007 will be in a range of 500 to 515 Bcfe and 520 to 535 Bcfe in 2008. We have taken Uncle Sam's increased royalty set aside caused by present pricing into account in estimating these ranges. So E&P's production potential remains unchanged from earlier forecasts. Second, along with the continued production growth, we will have much higher price realization in 2007, 2008 and beyond.

As shown on page 9 of the 2006 earnings guidance kit, our average realized price for hedge volumes grows from, $4.65 per Mcfe in 2006 to $5.60 in 2007 and to $7.11 in 2008. The un-hedged volumes grow from about 145 Bcfe in 2006 to over 440 Bcfe in 2008. The December 30, 2005, calendar strips for gas were $10.75 per Mcf in 2006, $10.26 in 2007, and $9.37 in 2008. Now, if you compare the December 30, 2005, oil and gas strips for 2007 and 2008 to yesterday's closing strips for the same periods, you'll see that gas is down slightly in 2007, but up slightly in 2008. Oil is actually up significantly in 2007 from what was $64 a barrel at year-end to $68 a barrel on yesterday's 2007 strip, and up from $62.73 for 2008 at year-end to $66.40 on yesterdays forward strip. While 2006 has seen more downward movement, it makes little difference to Dominion because of our hedge positions. So, despite recent movements in the forward curves, all of the E&P growth revenue factors remain unchanged. Third, the average realized price for New England generation will show significant growth over the period. As shown on page ten of the guidance kit, our average pricing at Millstone for the 93% which is hedged in 2006, grows to $55.13 on average a megawatt hour compared to the $40.87 we received on average in 2005.

We continue to see a higher price curve for Millstone and our other New England assets in 2007 and 2008. The December 30, 2005, forward curve in NEPOOL for 2007 was $91.83 a megawatt hour and $83.53 in 2008. Also, in New England we expect a significant lift from LICAP in 2007 and beyond. We should be able to give details on LICAP during our May analyst meeting in Boston. In short, the generation revenue growth factors remain unchanged. Fourth, we will reset our fuel recovery factor effective July 1st, 2007. We will enjoy one half year benefit that year with a full year in 2008 and beyond. I would note that last Friday the Virginia State Corporation Commission awarded ADP 100% of its fuel rate increase. The increase in their factor was from $1.42 to $1.785 per kilowatt hour resulting in over a 6% increase in the overall average monthly residential bill. We have no reason to believe that we will be treated any differently. As we've said before, the Virginia Commission has over 30 years of fuel case precedent. These precedents were applied to AEP, and they will be applied to us. The fuel reset growth driver remains unchanged.

Finally, in 2008 we should see uplift from at least one half year of the Cove Point expansion with a full year impact in 2009, while the timing of each factor may vary from one quarter to another depending upon when each element occurs. It is highly likely that Dominion's earnings will grow at a very accelerated double digit rate in 2007 over 2006 and beyond. We are confident not only in growth and EPS, but also in cash flow. As a result, the board voted this week to increase our quarterly dividend to $0.69 per share effective this quarter bringing our annual rate to $2.76. This of course is my First Call as Dominion's CEO. While I'm new to the job title, I'm not new to Dominion, its asset base or its business plan. Our strategy, diversifying across geographic regions and the energy chain, was conceived and implemented by our entire senior leadership team. We are pleased with where we are, while recognizing that we can continue to improve. We are making some internal changes that will not be visible to the investment community, but will help us manage our asset base more effectively. You should not expect any dramatic change in Dominion's plans in the near or medium term future. You should expect us to continue to complete our review of our existing assets to ensure that we're delivering premium returns on your invested capital. You should also expect us to continue to achieve best in class or near best in class operational performance. We are intent on delivering earnings and cash flow growth in 2006 and perhaps more importantly 2007, 2008 and 2009. We look forward to working with all of you over the years ahead. Now I will turn the call back over to Tom, who will discuss specifics of our 2006 earnings guidance.

Thomas N. Chewning, Executive Vice President and Chief Financial Officer

Thanks Tom. Our guidance for 2006 is $5.05 to $5.25 per share. When added to the $4.53 per share of actual earnings in 2005, the total 24 months operating earnings for 2005 and 2006 will be $9.58 to $9.78 per share. Page 4 of our 2006 earnings guidance kit reconciles this range to our 24 months outlook discussed during our last call with you on November the 3rd, 2005, which was based on our May 2005 assumptions. The projected total operating earnings of $10 to $10.35 per share less the lost income experience during our business interruption insurance deductible periods. Implicit in our projection is the assumption that other than the deductible periods, earnings related to our pre-hurricane gas and oil production forecast will be recognized either through physical production or through business interruption insurance. We now calculate that the lost income during the deductible periods was $0.25 per share. You can see that we have benefited from higher commodity prices and realizing market prices on volumes of oil and gas de-designated as a result of Hurricanes Katrina and Rita. Offsetting much of this gain have been large increases in vocational basis differentials.

As Tom Farrell mentioned earlier, the potential oil and gas production for 2006 has been reduced by phase out of royalty relief, a longer decline curve for the production at Front Runner, and continued delayed production as a result of Hurricanes Katrina and Rita. Business interruption insurance costs have grown as a result of the loss experience of our offshore underwriters. The company has lowered the discount rate used in our pension and benefit calculations, which causes an increase in this expense.

Finally, please recall that our original 2006 guidance range incorporated upside potential from three drivers integration into PJM, the benefit of the establishment of a LICAP market in New England, and the potential swap of deep water offshore reserves in exchange for onshore natural gas reserves. We integrated into PJM effective May the 1st, so that remains in our 24 month outlook. We've calculated the impact of the delay of LICAP implementation in New England from our previous assumption until October of this year. And we've not been successful in negotiating a swap of offshore reserves for onshore reserves. Practically speaking, we're not pursuing this option any longer. Due to the uncertainty of the receipts and recognition of business interruption proceeds and the quarterly mark-to-market of de-designated hedge volumes, we're not offering quarterly earnings guidance, we will however provide quarterly earnings drivers, you can find these in the 2006 earnings guidance kit on page 7, as we said several times in 2005, Dominion's 2006 would not be a year of earnings growth due to the constraints of legacy hedges and our fixed fuel factor in Virginia.

On May 22nd when we share our initial guidance for 2007, you'll see that the company's future earnings power is indeed very strong. Certainly there's been more concentration on 2007 and beyond in the investor community as we get closer in time to those years. Although we normally steer clear of commenting on particular analyst views or market speculation, today we offer Dominion's perspective on a few items of interest. First, in developing our five year financial plan, we have included substantial increases in operating costs for our oil and gas production. To exclude a rising cost structure for E&P, would be to ignore recent experience as well as evidence that links rising prices received with both variable and fixed price increases. We will supply you with our specific assumptions for E&P price increases for 2007 in our May 22nd meeting.

For 2006 earnings guidance, we've included increased lifting costs of 20% over those experienced in 2005. Further, we have included a 15% increase over 2005 in finding and development costs for 2006. The market rumors have it that we are selling assets and that we are doing so to avoid selling equity. It is our continued practice to not address specific market rumors, nor to discuss either the sale or purchase of assets except at the point when an agreement has been finalized by all parties. We will continue to purchase assets when our expected return criteria are met, the financial metrics of the investment meet rating agency ratios for the perceived risk, and the resulting income is accretive to our earnings. On the other hand, we will seek to sell assets when we feel that the resulting after-tax proceeds would be sufficient to maintain or improve our financial metrics and result in earnings accretion when compared to future earnings forecast.

The company stated recently that we have no intention of issuing additional equity in a response to a recent downgrade of our securities by one rating agency. However, it is not correct to link any potential asset sales to this statement. We have no commitments to any rating agency to issue equity or to reduce debt by any specific date. Whether the company sells assets or not in 2006, we will not sell additional equity to support our 2006 planned CapEx and dividend requirements. Of course if we do acquire incremental assets outside of our present portfolio, we model these purchases with appropriate additional equity. This concludes our prepared remarks and we will happy to undertake your questions.

Questions-and-Answer Session

Operator

At this time we will open the call for questions. If you would like to ask a question please press the “*” followed by the “1” key on the touchtone phone now, if any time you would like to remove yourself from the questioning queue please press “*”, “2”.

The first question comes from Greg Gordon.

Q - Gregory Gordon

Hi good morning guys.

A - Duane Radtke

Good morning Greg.

Q - Gregory Gordon

Good morning. On the, just sort of make sure I heard it right. You guys did actual production in Q4 95 Bs; correct?

A - Duane Radtke

That's correct.

Q - Gregory Gordon

And you indicated that you had 43 Bs of production interrupted. Am I recalling that correctly as well?

A - Duane Radtke

Yes. Greg, this is Duane. Yes.

Q - Gregory Gordon

So I still don't understand exactly how we reconcile that with your production forecast if we assume that you're back to your prior level of forecasted production by fiscal year ‘07, that would be a run rate still significantly in excess of your 5 to 515 Bcfe production forecast today. You did indicate in your comments, Tom that you were backing off or netting against your production forecast, the royalty reduction impact. But can you reconcile why the forecast doesn't seem to, seems to be conservative relative to sort of the pre Katrina pre Rita expected production?

A - Duane Radtke

Sure Greg. What you’re doing and you're absolutely correct, in fourth quarter that would have added up to close to 140 Bs, but that would have been peak production. I mean, we don't ever keep, those Gulf of Mexico wells, they decline relatively rapidly. So you're looking at the peak and taking it times four. When you actually look at the average production, it would have been substantially less than that and into our forecast. What we've essentially done and you in some of your analysis had looked at it and said you had expected more than 5% to 6% in 2006. What really happens is because of the delays, that all moves to 2007.

Q - Gregory Gordon

Okay, thanks.

A - Duane Radtke

It's a timing issue then.

Q - Gregory Gordon

Understood. We have additional questions. Actually Faisel Kahn has got a few questions. Faisel?

Q - Faisel Kahn

Yeah, Duane, do you have an updated reserve amount for your proof probable on possible reserves? And can you talk about where most of your proved reserves growth came from for the year, and what's your peak proved developed producing to PUD ratio?

A - Duane Radtke

Sure. Let's, first of all talk, I don't have the probable, possible. We're in the process of finalizing it, but it should be somewhere similar or a little bit larger than what we had a couple years ago. We've normally only done it every couple of years, but it would be probably over 4Ts probable and possible, in that range. And on the reserve additions it was pretty much across the board except in the Gulf of Mexico, and that's due to timing of when you book the reserves. You know, earlier we booked a lot of the Front Runner, Devils Tower reserves. We spent the money last year and some of it this year. So that's just a timing issue. But the programs across the board have done very, very well. We can get you the undeveloped to do, but it was somewhere in the 25% to 30% range which I think will put us certainly below the midpoint of most of the companies.

Q - Faisel Kahn

Okay. And then can you talk about these deep wells in Oklahoma? How big are these wells? What kind of reserves are you talking about with these wells?

A - Duane Radtke

Yeah. It's a program we actually started about 18 months ago in the deeper Anadarko. We currently have four rigs. We've been accumulating a lot of acreage, so we haven't said anything. But we have four rigs running there. A typical well is four to $8 million, and we're talking five to ten Bcf, but we have quite a bit of acreage there. It's been a very successful program for us.

Q - Faisel Kahn

Thank you.

A - Duane Radtke

Thank you.

Operator

Thank you. Our next question comes from Steven Fleishman with Merrill Lynch.

Q - Steven Fleishman

Hi guys.

A - Thomas Farrell

Hi, good morning, Steven.

Q - Steven Fleishman

A couple of questions. First, on the locational basis differential, sounds like you expect kind of same impact 2006 versus 2005. I’d be curious, though, how much are you, how can you be confident that there isn't going to be some ongoing basis differential? We used to model one in a year or so ago for your E&P, and then it kind of had went away versus Henry Hub. Should we assume there's going to be some ongoing basis differential?

A - Thomas Farrell

Steve, we think it's going to stay through the course of the year and decrease in pieces and parts as it goes along as more infrastructure comes online resulting from last year's hurricanes. There's, as I said, we saw $0.40 in the fourth quarter, and we're looking forward. We think it will be somewhere between $0.30 and $0.40 total for the year. So obviously it will be decreasing as we go along. We believe, we can't guarantee, but we believe that the differential will revert to the norms that you see traditionally by the end of the year.

Q - Steven Fleishman

Okay. And then secondly, the marketplace on de-designated hedge volume number, the dollar over the two years, how does that break out between 2005 and 2006? It's not really mentioned as a factor in the 2006 to 2005 differential.

A - Joe

Steve, this is Joe. We haven't de-computed what the benefit of the early return to production; say from at market price was in 2005 versus what we'd expect in 2006. And because the business interruption insurance claims are not final yet, we just haven't parsed that amount out between either year or claims versus early return to production. It's just we expect to recognize the de-designated amount in both of those fashions?

A - Thomas Chewning

One of the things obviously that we did have a gain this year not only in mark-to-market at year end, but part of it also was marked in October, November and December from the mark. So somewhere in the neighborhood of about half of it, Steve.

Q - Steven Fleishman

Is already in there, okay.

A - Thomas Chewning

For 2005, and we've accounted for in terms of our prices received in ‘06. So it reconciles to the 24 months.

A - Thomas Farrell

That's right. You also do see it in price from the early return to production in 2005.

Q - Steven Fleishman

Okay.

A - Thomas Chewning

Those three pieces.

Q - Steven Fleishman

Okay thank you.

A - Thomas Chewning

Thank you.

Operator

Thank you. Our next question comes from Hugh Wynne with Sanford Bernstein.

Q - Hugh Wynne

Hi.

A - Thomas Chewning

Hi, Hugh.

Q - Hugh Wynne

Hi, Just a quick question, if I could, on page 8 of your 2006 earnings guidance kit of the reconciliation of 2005 operating earnings to the 2006 guidance range. The line for E&P production and BI insurance is about $0.95 to $1.05. I guess it's correct to say that this is your collection of business interruption insurance in 2006 in excess of production losses in 2006. In other words, it's collection of BI insurance for production lost in 2005?

A - Thomas Chewning

Correct.

Q - Hugh Wynne

Okay. So when we subtract that out from the 505 to 525 guidance range to come up at what you might think of ongoing earnings power in the absence of BI insurance collections, we're down then to something closer to $4.25.?

A - Thomas Chewning

It’s not all BI. It's production growth and BI. I don't think that model is going to work, Hugh. I think we can work with you offline, but I think 2006 versus 2007 that we can reconcile and we will in May in terms of mainly a production uplift. We do, as we’ve mentioned earlier, we do have a fairly significant uplift in production in ‘06 versus ‘05 in addition to collecting some of the BI insurance claims. So that number.

Q - Hugh Wynne

Okay. So what is the, what is the breakdown?

A - Thomas Chewning

We didn't want to break that down. You can appreciate the fact that we still have negotiations in front of us with insurance underwriters. So we deliberately lump those together.

Q - Hugh Wynne

Okay. Is there, is there a figure beyond which the insurance underwriters wouldn't even considering cutting a check that we can perhaps use here to figure out what portion of the increase is…

A - Thomas Chewning

Probably.

Q - Hugh Wynne

Alright, I will call back latter.

A - Thomas Chewning

Thanks.

Operator

Thank you. The next question is from Dan Eggers with Credit Suisse First Boston.

Q - Daniel Eggers

Hi good morning.

A - Thomas Farrell

Good morning Dan.

Q - Daniel Eggers

First question is on, hedging philosophy going forward, if you could give a little more color. Obviously you guys didn't really add the hedges anywhere in the fourth quarter. How were you thinking about what the right hedge percentages need to be for E&P for the merchant generation business, and then along those lines what kind of imputed or implied returns on capital do you guys want to target as you think about future investment in those businesses?

A - Thomas Farrell

Hugh, I'm sorry. I apologize, Dan. We don't plan on changing our previously announced hedging policy. If you look at the percentages, as you go out into the future, we're hedged at about levels right about the levels we said we would be as we exited one year going into the other when you take into account the internal hedges. So we're hedged about where we thought we would be for ‘06, ‘07 and ‘08. And as we go through the year we will continue to roll into more hedges. We're going to probably shape them a little bit differently than we have in the past, but the percentages will fall in those categories that we've talked about previously. Returns on invested capital will vary from business unit to business unit depending upon what the risks are that we're looking at. But all of them are going to be seeking, anything we do, anything we invest in is going to be seeking to increase the returns on invested capital, and that's one of the reasons why we're looking at all of our assets to see what's dragging on our return on invested capital. And if they are drags, then we're looking at disposing of them. But giving you a specific target number, I'm not sure we'll do that in this morning's call. We're not interested in investing something that's not going to improve the return on vested capital unless it's obviously maintenance related.

Q - Daniel Eggers

When you talk about, no major shifts or no asset sales in the short or near term, I think is what you said, any handle on what near term can be translated into meaning?

A - Thomas Chewning

I didn't, first, I don't believe I said there wouldn't be any asset sales in the near term. We're not commenting one way or another on anything we're looking at selling or anything we're looking at buying. What I was trying to convey was that the business model that Dominion has and has developed over the last ten years, our geographic region focus, not different assets scattered around the world or in widely disparate regions of the United States, fully integrated across the energy chain from E&P, pipelines, distribution systems, generating assets, electric transmission, gas storage, LNG importation facilities. That business plan wasn't dreamed up by a single individual or implemented by a single individual. It was carried out, it was thought up and carried out by a group of folks all of whom are still here or most of whom are still here. We intend to continue forward with that plan. As we go along, there are certain aspects of it that we are thinking about whether it should be, we should shade them differently or do something a little bit differently. But we're not going to do anything about that in the near term. I think I'll just leave the definitions up to you, but the near mid-term are certainly for a course of many months.

Q - Daniel Eggers

Got it. And then not taking too much time, but one last one. You mentioned AEP's success with their Virginia fuel clause. Given that it's been pretty contentious in other states with the transition and passing on rate increases for the first time in a number of years, which you guys will be facing, how are you going about dealing with the commission, dealing with your various stakeholders to brace people for the increases coming?

A - Thomas Farrell

Well, we have met with lots of people. We have kept the staff informed, the staff of the commission informed about the programs that we are implementing on coal purchases and other things. They're kept informed of the performance of our generating units over the period. They're kept informed of the growth we have. They see the actual fuel expense. So everybody, everybody is kept very well informed on these issues. We need to keep all this in orders of magnitude. The electric customers in Virginia aren't going to see anything near what's happening to gas customers here and in other states. Some of the fuel requests that we saw I think we mentioned in the third quarter call, I had seen one in Florida seeking a 20% increase. I mean, ours are not going to be anywhere near that order of magnitude. And also recall in Virginia the average monthly bill, including fuel today, is only about $85 a month.

Q - Daniel Eggers

Got it, thank you.

A - Thomas Farrell

Thank you, Dan.

Operator

Thank you. The next question comes from Paul Fremont with Jefferies.

A - Thomas Chewning

Hi, Paul.

Q - Paul Fremont

A couple of questions. The first, I guess, relates to, it looks as if there's a fairly significant increase in the amount of spending, CapEx spending, that you plan on doing in the E&P business. If I take sort of Tom Chewning's earlier comment, should we assume that additional spending will all be debt financed, it looks like about a $500 million increase?

A - Thomas Chewning

Yes, Paul. I'd like to, if you give me a minute or around a minute. I know people have already taken a look and said you had negative cash flow in 2005 and you still have it in 2006. First it's always desirable to run a company to be free cash flow positive after CapEx and dividends, and we're committed to doing that. Obviously there's two areas of capital expend, maintenance and growth. We must continue a fairly high level of maintenance CapEx. As we define maintenance CapEx, part of that is replacing lost production, and as you know, the cost of replacing that production has risen significantly in the last couple of years. The interesting phenomenon for us is that because of our legacy hedges we're not able to receive the cash flow that's commensurate with the market prices and yet we're paying the capital costs to drill at current market rates. That's not a good thing for us, but we will wear out of that in ‘07 and ‘08. Also, it's interesting that our cash flow has been impacted by the fuel factor in Virginia. We began to work out of half of that in ‘07 and the other half in ‘08. And then thirdly, part of our growth CapEx next year is the Cove Point expansion, which doesn't return any cash flow until mid year or later in 2008, as well as increased spending at Dresden, another plant which doesn't come on line until ‘07. So Paul, we would be foolish to tell you that we don't, we won't be spending at these capital levels. We will not make a long-term CapEx decision based upon a short-term goal of being cash flow positive, although it is certainly our goal, we would expect to be about breakeven in 2007 and very positive in 2008 as a result of higher cash flows and some lower growth CapEx figures.

Q - Paul Fremont

Okay. Then the second question is, in terms of, in terms of the hedging gains, I just want to understand, in terms of the accounting, is, is a significant amount of that showing up agency the FAS 133 hedge ineffectiveness credit that you're showing under, I guess as a credit to O&M in the E&P business, or is that something else?

A - Thomas Farrell

Paul, can I ask you what schedule you're referring to?

Q - Paul Fremont

I guess it's page 14. It looks like it's a 60 million benefit from 2004 to 2005.

A - Thomas Chewning

That must be it. I believe that's the line item where it would be, yes.

Q - Paul Fremont

And just so I understand you, when I look at 2006 there will be a similar amount of credit in roughly in 2006 as there was in 2005?

A - Thomas Chewning

Could you ask, ask that question again.

Q - Paul Fremont

Should we expect a similar credit to O&M in 2006 based on your guidance of that expected benefit that you plan on recognizing $1 over I think, over the two year period?

A - Thomas Farrell

Hi, Paul. Would you please, I will call you back after the call and try to go through the details of that question. It's just not clear. So I think it would be more productive if we just took it offline.

Q - Paul Fremont

Okay. And then the last question I have is, generally I'm not sure I understand, it looks like a lot of the hedges in 2005 for the non-regulated businesses were being booked in VEPCO. I just don't understand the rationale there.

A - Thomas Farrell

Paul, I don’t know if you're talking about some of those hedges being done at VPEM, and if you are, that was causing a large negative market in Virginia Power, but not at Dominion consolidated.

Q - Paul Fremont

Okay. So those would only be then generation hedges? Those would not be for any of the other businesses?

A - Thomas Farrell

There's a lot of generation, but it doesn't mean it's all generation. Importantly VPEM was moved out of Virginia Power and into Dominion at the end of the year and we filed an 8-K giving details. It's significantly improved both debt and equity for Virginia Power and net income as well.

Q - Paul Fremont

So at least, on a going forward basis the Virginia Power financial statements won't show significant activity for hedges?

A - Thomas Farrell

That is correct.

Q - Paul Fremont

Thank you.

Operator

Thank you the next question is from David Schanzer with Janney Montgomery Scott.

A - Thomas Farrell

Okay, Hi David.

Q - David Schanzer

Hi, good morning. Couple of questions. Could you give me an idea of what the capacity factors were for both generation nuclear units and utility nuclear units?

A - Thomas Farrell

The nuclear capacity factors were 92% in 2005 for the nuclear units. And on the fossil units, equivalent availability is probably a better indicator; it’s about 96% as Tom said, in the peak season. If you look at the big coal units for the utility, capacity factors were about 79% and if you look at the small coal unit’s capacity factors were about 72%.

Q - David Schanzer

Okay, great. Also, has there been any attempt at resolving the dispute between Dominion and WGL with regard to the negative impact of unblended LNG as it goes through their pipes?

A - Thomas Farrell

No.

Q - David Schanzer

Okay. You don't have a schedule for resolving that, I take it, or you're not just addressing it?

A - Thomas Farrell

We'll let FERC resolve it.

Q - David Schanzer

Okay.

A - Thomas Farrell

We're not going to resolve it with Washington Gas Light.

Q - David Schanzer

Okay great, thank you.

Operator

Ladies and gentleman we have reached the end of our allotted time and Mr. Chewning do you have any closing remarks.

Thomas N. Chewning Executive Vice President and Chief Financial Officer

I would like to thank everybody for joining us this morning. Just a couple of notes, we expect to file our form 10-K with the SEC on March 1st. Our first quarter Earnings Conference Call, is scheduled for 10:00 AM Wednesday, May the 3rd. And let me give you one more reminder of our Spring Analyst Meeting to be held in Boston. It will be on Monday, May 22nd. Those who’ll be for rest of the day good morning.

Operator

Thank you. That thus concludes today’s teleconference. You may disconnect your lines at this time and have a wonderful day.

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Source: Dominion Resources Inc Q4 2005 Earnings Conference Call Transcript (D)
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