道明尼資源 (D) 2005 Q4 法說會逐字稿

Good morning, ladies and gentlemen and welcome to Dominion's fourth quarter earnings conference call.

We now have Mr. Tom Chewning, Dominion's Executive Vice President and Chief Financial Officer in conference. [OPERATOR INSTRUCTIONS] I will now turn the conference over to Mr. Tom Chewning, sir you may begin.

Good morning and welcome to Dominion's 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 will 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 1, 2005, through December 31, 2006 to the outlook we had discussed during our last call with you on November 3, 2005.

Before answering your questions, we will offer our current perspective on the drivers that will create a significant uplift on Dominion's earnings in 2007 and beyond.

Concurrent with our earnings announcement this morning, we 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 10-K and quarterly report on Form 10-Q 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 differ from those recognized by GAAP.

You can find the reconciliation of these non-GAAP measures to GAAP on our investor relations website under GAAP reconciliation.

We are 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 results in a $0.38 per share benefit to earnings.

Following the hurricanes, we forecasted fourth quarter production delays 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 of production, we recorded a $0.23 per share non-cash, mark-to-market gain on hedges that would be designated in the third quarter due to the hurricane.

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 the fourth quarter were $0.74 per share.

The difference in the quarter, between GAAP and operating earnings, is primarily attributable to a $51 million impairment of a note receivable, related to the 1998 sale of merchant generation facilities to Calpine and a $14 million 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 fourth quarter actual to guidance.

GAAP earnings for 2005 were $3 per share.

In addition to the fourth quarter 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 a 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 31, 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 the third quarter.

Our available liquidity was $2.2 billion.

Now I'll turn the call over to Tom Farrell for his comments.

Tom.

Thank you Tom and good morning, everyone. 2005 operations and results net worth exceeded the goals we established at the beginning of the year, except for oil and gas production delays, resulting directly from Hurricanes and 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 megawatt hours, compared to the previous record of 28.3 million megawatt hours, 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 1 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.

That's 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 the fourth quarter, 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 the 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 MCFB.

That brings our total reserves at year end to 6.3 TCFE, compared to 5.9 TCFB 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 or extended new production wells at a variety of locations.

Some of the highlights include Spiderman Well Number 3, our discovery at Q, West Cameron 130, West Cameron 100.

Devil's 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 [Andadarco] 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 carry over 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 about 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 9 BCFE from our own account because higher prices are causing a phase-out of U.S.

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 restored to service until the end of February.

Lower 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 in 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. he differentials cost us about in the fourth quarter of 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 thought are reverting to the norms we have seen for many years as infrastructure in the Gulf is returned to service.

We are 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 the first quarter of 2006 at Dominion Energy through optimization of our storage and pipeline assets and capacity positions.

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 5 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 Volumetic 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; schedules 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 Devil's Tower will achieve peak production during the 2006, 2008 period.

While Front Runner has cost us some production in 2006, as I have 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 '06, but more in '07 and '08 than originally planned.

The eastern Gulf of Mexico wells we have previously announced, including Spiderman, San Jacinto, and Q will come online during 2007.

These wells and their related infrastructure are on their original schedules.

Thunder Hawk will come online in late 2008 or early 2009.

And 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 unhedged 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 grass 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 yesterday's forward strip.

While 2006 has seen for 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 10 of the guidance kit, our average pricing at Millstone for the 93%, which is hedged in 2006, grows to $55.13 on average of megaWatt hour compared to the $40.87 which was received on average in 2005.

We continue to see a higher price curves 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 per 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 1, 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 AEP 100% of its fuel rate increase.

The increase in their factor was from $0.0142 to $0.01785 per kilowatt hour resulting in over a 6% increase in the average overall monthly residential fill.

We have no reason to believe we will be treated any differently.

As we have 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 we mains 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 earnings per share, 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 am new to the job title, I am 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 over our existing assets, to insure that we are 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.

I'm going to turn the call back over to Tom, who will discuss specifics of our 2006 earnings guidance.

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-month operating earnings for 2005 and 2006 will be $9.58 to $.9.78 per share.

Page Four of our 2006 Earnings Guidance Kit reconciles this range to our 24-month outlook discussed during our last call with you on November 3, 2005, which was based on our May 2005 assumptions.

We projected total operating earnings of $10 to $10.35 per share, less the loss income experienced during our business interruption and 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 would be recognized either through physical production or through business interruption insurance.

We now calculate that the lost income during the deductible period was $0.25 per share.

You can see that we benefited from higher commodity prices and realizing market price on volumes of oil and gas be designated as a result of Hurricanes Katrina and Rita.

Offsetting much of this gain have been large increases in locational basis differentials.

The potential oil and gas production for 2006 has been reduced by a phase out of royalty release, a longer decline curve for production at Front Runner, and continued delay production as a result of hurricanes Katrina and Rita.

Business interruption and insurance costs have grown as a result of the loss experienced 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.

Finely, please recall that our original 2006 guidance range the upside 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 national gas reserves.

We integrate into PGM, effective May 1, 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.

We have not been successful in negotiating a swap of offshore reserves for onshore reserves.

Proactively speaking, we are not pursuing this option any longer.

Due to the uncertainty of the receipt and recognition of business interruption proceeds and the quarterly mark-to-market of hedge volumes, we are 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 22, when we share our initial guidance for 2007, you will see that the company's future earnings power is indeed very strong.

Certainly, there has 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 22 meeting.

For 2006 earnings guidance, we have 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 ratings 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 the resulting after-tax proceeds will 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 asset or not in 2006, we will not sell additional equities 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 are happy now to take your questions.

Kenny.

Yes. [OPERATOR INSTRUCTIONS] The first question comes from Greg Gordon.

Hi, thanks.

Good morning, guys.

Good morning, Greg.

Morning.

On the, - - just to make sure I heard it right, you guys did actual production in the fourth quarter of 95 Bs, correct?

That's correct.

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

Yes, Greg, this is Duane, yes.

I don't understand 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 the pre-Katrina, pre-Rita expected production.

What you're doing, - - and you're absolutely correct in the fourth quarter that would have added up close to 140 Bs, but that would have been peak production.

It doesn't,- - we don't ever keep those Gulf of Mexico wells, - - they decline relatively rapidly, you're looking at the peak and taking it times 4.

When you look at the average production, it would have been substantially less than that and into our forecast.

What we've essentially done, and you were, I know, in some of your analysis, had looked at it and said you had expected more than 5 to 6% in '06.

What really happens is, because of the delays, that all moves to '07.

Okay.

It's a timing issue then.

Understood.

We have additional questions.

Actually Faisel Kahn's got a few questions.

Faisel.

Duane, do you have an updated reserve amount for your prove, probable, and possible reserves?

And can you talk about where most of your prove reserve growth came from for the year and what's your prove developing to pod ratio?

Sure.

Let's first of all talk, - - I don't have the probable, possible window.

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 of years ago.

We've normally only done it every couple of years, but it'll be probably over 4 Ts 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.

Earlier we booked a lot of the Front Runner, Devil's Tower reserves.

We spent the money last year on 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.

Okay.

And can you just talk about these deep wells in ?

How big are these wells?

What kind of reserves are you talking about?

It's a program we started about 18 months ago in the deeper [Anadarco].

We current have four rigs, we've been accumulating a lot of acreage, so we haven't said anything.

But we have four rigs running there.

And a typical well is $4 to $8 million and we're talking 5 to 10 Bcf, but we have quite a bit of acreage there.

It's been quite a successful program for us.

Thank you.

Thank you.

Thank you.

Our next question comes from Steve Fleishman with Merrill Lynch.

Hi, guys

Hey, Steve.

Morning, Steve.

Couple of questions.

First, on the locational basis differential, sound like you expect kind of the same impact '06 versus '05.

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 went away versus Henry Hub.

Should we assume there's going to be some ongoing basis differential?

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.

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.

Okay.

And then, secondly, the market price on the designated hedge volume number, the dollar over the two years, how does that break out between '05 and '06?

It's not really mentioned as a factor in the '06 to '05 differential.

Steve, this is Joe.

We haven't recomputed 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 yet 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.

One of the things, obviously, that we did have a gain this year, not only a 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.

Is already in there?

For 2005.

And we've accounted for it in terms of our prices received in '06.

So it reconciles for the 24 months.

You also do see it in price from the early return of production in 2005.

Okay.

Those three pieces.

Okay, thank you.

Thank you.

Thank you.

Our next question comes from Hugh Wynne with Sanford Bernstein.

Hi.

Hey, Hugh.

Just a quick question, if I could on the page 8 of your 2006 Earnings Guidance Kit with 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?

Correct.

Okay.

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

It's not all BI.

It is 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 '06 versus '07 as we can reconcile, and we will May, in terms of mainly a production uplift.

As we mentioned earlier, we do have a significant uplift in production in '06 versus '0, in addition to collecting some of the BI insurance claims.

So that number - -

So what is the breakdown?

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

Is there a figure beyond which the insurance underwriters wouldn't even considering cutting a check that we could perhaps use here to figure out the portions of the increases that [inaudible].

Probably.

All right.

I'll call back later.

Thanks.

Thank you.

The next question from Dan Eggers from Credit Suisse First Boston.

Good morning.

Morning, Dan.

First question, on the hedging philosophy going forward, if you could give a little more color, obviously you guys didn't add the hedges anywhere in the fourth quarter.

How are 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 do you think about on future investment in those businesses?

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.

We're hedged about where we thought we would be for '06, '07 and '08.

As we go through the year, we'll 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 investment capital and that's why, one of the reasons why we're looking at all of our assets to see what's dragging on our return on vested 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.

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?

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, L&G importation facilities, that business plan didn't, - - 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 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, midterm are certainly for a course of many months.

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

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.

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'd seen one in Florida seeking a 20% increase, ours are not going to be anywhere near that order of magnitude.

And also, I recall in Virginia, the average monthly bill, including fuel, today, is only about $85 a month.

Got it.

Thank you.

Thank you, Dan.

Thank you, the next question comes from Paul Fremont with Jefferies.

Hey, Paul.

A couple of questions.

The first relates to, it looks as if there's a fairly significant increase in the amount of spending CapEx spending you plan on doing in the E&P business.

If I take Tom Chewning's earlier comment, should we assume that that additional spending will all be debt financed in terms, - - it looks like about a $500 million increase.

Yes, Paul.

I'd like to, - - if you give me a minute, allow me a minute, I know people have already taken a look and said, you have negative cash flow in '05 and you still have it in '06.

And 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 are two areas of capital spend, maintenance and growth.

And we must continue a fairly high level of maintenance CapEx.

As we design 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 capitol 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 begin to work out a half of that in '07 and the other half in '08.

And then thirdly, part of our growth CapEx the next few years is for Cove Point expansion which doesn't return any cash flow until mid-year or later in '08, as well as increased spending at Dresden, another plant that doesn't come online 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 capital expenditure decision based upon a short-term goal of being cash flow positive, although, it is certainly our goal.

We would expect to be about break even in '07 and very positive in '08 as a result of higher cash flows and some lower growth CapEx figures.

Okay.

And then, the second question is, in terms of the hedging gains, I just want to understand in terms of the the accounting, is a significant amount of that showing up as a FAS133 hedge in effectiveness credit you're showing under -- I guess as a credit to O&M in the E&P business?

Or is that something else?

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

I guess it's page 14.

Looks like it's a 60 million benefit from '04 to '05.

That must be it.

I believe that's a line item where it would be, yes.

And just to understand you, when I look at '06, there'll be a similar amount of credit in roughly, - - in '06 as there was in '05?

Could you ask that question again?

Should we expect a similar credit to O&M in '06 based on your guidance of that expected benefit that you plan on recognizing of a $1.00 over two, - - I think of over the two-year period.

Hey, 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 took it offline.

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 were for the non-regulated businesses were being booked in VEPCO and I just don't understand the rational there.

VPM.

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

Okay, so those would only be then generation hedges?

Those would not be for any of the other businesses?

It was 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 significantly improved both debt and equity for Virginia Power and net income as well.

So on a going forward basis, Virginia power financial statements won't show significant activity for hedges?

That's correct.

Thank you.

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

Okay, hey David.

Good morning.

Couple of questions.

Could you give me an idea what the capacity factors were for both the generation nuclear units and the utility nuclear units?

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 units, capacity factors were about 72%.

Okay, great.

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

No.

Okay.

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

We'll let Burke resolve it.

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

Okay, great.

Thank you.

Ladies and gentlemen, we have reached the end of our allotted time.

Mr. Chewning, do you have any closing remarks?

Thank you, Kenny.

I'd like to thank everybody for joining us this morning.

Just a couple of notes.

We expect to file our Forms 10-K with the SEC on Mar 1.

Our first quarter earnings conference call is scheduled for 10 a.m. on Wednesday, May 3.

And let me give you one more reminder of our spring analyst meeting to be held in Boston.

It'll be held on Monday May 22.

Please enjoy the rest of your day, good morning.

Thank you, that does concluded today's teleconference, you may disconnect your lines at this time and have a wonderful day.