道明尼資源 (D) 2002 Q4 法說會逐字稿

Good morning, my name is Terry and I will be your conference facilitator today.

At this time, I would like to welcome everyone to Dominion fourth quarter 2002 earnings conference call.

All lines have been placed on mute to prevent any background noise.

After the speakers remarks, there will be a question-and-answer period.

If you would like to ask a question during this time, simply press star, then the number 1 on your telephone keypad.

If you would like to withdraw your question, press the pound key.

Thank you.

Mr. Chewning, you may begin your question.

Good morning.

Thank you for joining us for our fourth quarter 2002 earnings conference call.

The earnings release and other matters that may be discussed on the call today contain forward- forward-looking statements and estimates that are subject to various risk and uncertainties.

Please remember refer to our SEC filings, including our most recent annual reports on Form 10-K and quarterly reports on form 10-Q for discussion of factors that may cause results to differ from management's projections, forecasts, estimates and expectations.

Joining me on the call this morning are Steve Rogers, Vice President and Controller and Tom Wohlfarth, Director of Investor Relations.

I'll begin by reviewing highlights from 2002 and then Steve Rogers will review the fourth quarter and full year results in more detail.

After Steve is finished, I will review the 2003 and 2004 financial outlook.

Then we'll answer your questions questions.

In the fourth quarter of 2002, Dominion posted operating earnings of $1.13 per diluted share, 27% above the $.89 per share earned in the fourth quarter of 2001.

Results for the full year were impressive as well.

Dominion posted operating earnings of $4.83 per diluted share for the full year 2002.

Nearly 16% above the $4.17 per share earned in 2001.

Adjusting for the $.05 per share timing impact of the corporate hedge we put in place on 2003 natural gas production, earnings would have been $4.88 per share.

This is purely a timing item, as the impact will reverse in 2003 when we produce and sell the associated natural gas.

Reported net income for the fourth quarter of 2002 was $1.12 per share, compared to a loss of $.45 per share in the fourth quarter of 2001.

While reported net income for the full year of 2002 was $4.82 per share, compared to $2.15 per share in 2001.

Operating earnings for the fourth quarter and full-year 2002 exclude an after-tax charge of $.03 per share, related to a Dominion capital asset impairment, partially offset by the effect of a $.02 per share after tax adjustment to restructure liabilities accrued in 2001.

Reflecting a reduction in the amount originally expected to be incurred.

These two items combined resulted resulted in a net after-tax charge of $.01 per share.

Fourth quarter 2001 operating earnings excludes special after- after-tax charges of $.30 per share, resulting from Dominion's estimated Enron exposure, $.27 per share in restructuring charges associated with the senior management restructuring initiative and other restructuring costs and $.70 per share for a write-down of Dominion capital assets.

Operating earnings for the full year 2001 exclude the fourth quarter items I just reviewed, plus $.54 per share related to the buy out of purchase contracts and non-utility generating units previously serving the company under long- long-term contracts and $.10 per share associated with the divestiture of capital.

Dominion also produced strong operating cash flow in 2002 and made significant progress towards strengthen strengthening the bs.

Dominion produced $2.45b, also called operating cash flow in 2002, compared to $2.4b1 in 2001.

While the operating cash flow was in line with our expectations of $2.5b, the year-over-year change [inaudible] of Dominion’s cash flow.

The timing of cash flows associated with marginal [inaudible] on hedges, for instance, negatively impacted 2002 cash flow.

These cash flow impacts are purely purely timing in nature, however however, reversing as physical gas is produced and sold in the subsequent periods.

Another pure timing item that can shift cash flows between periods is receivables and payables.

In 2002, these items hurt cash flow due to strong sales late in the year.

These types of cash flow requirements do not require capital markets financing as we cover these needs with working capital and other liquidity facility.

Excluding short-term working capital changes, Dominion Dominion's operating cash flow was $2.8b.

In 2002, we also made significant progress towards strengthening the bs.

Debt to capitalization on a GAAP basis improved 60.8% at the end of 2001 to 55.6% at the end of 2002.

Adjusting the GAAP basis bs to adjust for off bs financing and to give equity treatment to securities, the ratio improved from 62% at the end of 2001, to 57.2% at the end of 2002.

We're committed to maintaining our current strong investment grade ratings and our actions to date have clearly demonstrated that.

We issued about $2b in equity and equity linked equity securities in 2002, and over the past year, we've cut hundreds of millions of dollars from our future capital spending plan.

In addition, Dominion's fixed charged cover ratios have improved markedly over the past year.

We have enhanced the company's liquidity position.

Today we announce further reduction to our capital spend spending plans for 2003 and 2004, resulting in a significant improvement in our free cash flow outlook for these years.

Note that we define free cash flow as operating cash flow minus net capital investments and minus dividends.

We are reducing our planned net capital investments for the next two years by about $300m per year, compared to the plan last communicated to investors.

We now project net capital investment of about $2.5b and $2.2b for 2003 and 2004, respectively.

Under this new plan, we expect Dominion to be free cash flow negative in the range of $100m to $300m in 2003.

We expect to be $300m to $500m free cash flow positive in 2004.

In addition, we anticipate raising about $160m in equity per year through our dividend reinvestment and 401(k) plans which will cover financing needs in 2003 and will enhance the projected positive net cash flow position in 2004.

The spending cuts have occurred principally in Dominion energy and Dominion E and P units and relate to reductions in discretionary and developmental capital planned for generation development and oil and gas exploration and production projects.

Note that the new capital investment plan includes the cost of accelerating the replacement of the vessel heads for North Anna Unit One and Shore Units 1 and 2 into 2003.

We have successfully replaced the North Anna Two vessel head and have decided to accelerate the head replacement on the other three units.

Accelerating these replacement projects is positive because it will allow dominion to get the necessary replacement projects behind us, saving dollars that would have otherwise been spent inspecting and repairing these units.

One final note, I am sure many of you are happy to see that we've begun the process of removing the debt triggers associated with the Dominion [inaudible] notes.

We never considered the triggers a real liquidity risk to Dominion but we decided to go ahead and remove the triggers to eliminate the headline risks that have occasionally caused our shareholders angst.

Now let me turn the call over to Steve Rogers to review the 2002 earning results.

Thanks, Tom.

Dominion energy manages electric generation, natural gas pipeline and storage business and the Dominion energy clearinghouse.

Dominion energy posted earnings of $.61 per share in the fourth quarter of 2002 as compared to $.49 per their in the fourth quarter of 2001.

Higher sales volume from customer growth in our Virginia and North Carolina electric franchise service areas provided an increase of $.02 per share share.

Higher sales volume from colder than normal temperatures in the electric franchise service areas boosted areas by $.15 per share.

There were 44% more heating degree days during the fourth quarter of 2002, as compared to 2001.

Real realized gains related to the corporate hedge on 2002 natural gas production improved earnings by $.01 per share.

The impact of market to market losses related to a corporate hedge on 2003 natural gas production, decreased earnings by $.04 per share.

Lower tax expense improved quarterly earnings $.04 per share.

Other factors increased earnings $.04 per share in the fourth quarter of 2002, versus 2001.

And share delusion reduced fourth quarter 2002 earnings $.10 per share as compared to the fourth quarter of 2001.

On a year over year basis, Dominion energy posted earnings of $2.72 per share in 2002, compared to $2.86 per share in 2001.

Higher sales volume from customer growth in our Virginia and North Carolina electric franchise service areas provided an increase of $.10 per share.

Weather, in the electric franchise service area resulted in an improvement in year-over- year-over-year earnings of $.33per share.

There were 31% more cooling degree days and 2% more heating days in 2002 as compared to 2001 2001.

The 2002 results at the Dominion energy clearing hours were $.02 per share below 2001.

This can be primarily attributed to lower market to market earnings due to changes in accounting rules on non-derivative energy trading contracts and reduced sparks spreads.

These factors were partially off offset by increased deal flow in our gas trading business and higher margins in our oil trading business, which was new for 2002.

These results exclude realized losses and market to market effects of corporate hedges in 2002 and 2003 natural gas production.

Realized losses from the settlement of positions related to the corporate hedge of 2002 natural gas production reduced earnings by $.12 per share.

The timing impact of market-to- market-to-market losses related to a corporate hedge on 2003 natural gas production reduced 2002 earnings $.05 per share, as compared to 2001.

Lower tax expense improved 2002 earnings, $.06 per share.

Other factors resulted in an 11% reduction to year over year earnings.

Finally, share delusion reduced 2002 earnings $.33 per share as compared to 2001.

Moving now to Dominion delivery, Dominion delivery is the company's electric and gas distribution, electric transmission and customer service business.

Effective January 1, 2003, the electric transmission business was transferred to Dominion Energy, however these 2002 comparative results have not been adjusted to reflect that change.

Dominion delivery posted earnings of $.41 per share in the fourth quarter of 2002, as compared to $.36 per share in the fourth quarter of 2001.

Customer growth principally in the electric franchise service area added $.01 per share to earnings.

Lower than normal temperatures in the electric franchise service areas boosted earnings by $.07 per share.

There were 44% more heating degree days during the fourth quarter of 2002, as compared to 2001.

Lower than normal temperatures in the gas franchise service areas boosted earnings by $.10 per share.

There were 32% more heating degree days during the fourth quarter of 2002, as compared to 2001.

Increased service restoration expenses resulting from fourth quarter ice storms negatively impacted earnings $.01 per share as compared to the fourth quarter of 2001.

A $.04 per share reduction in earnings resulted from lower bad debt expense in the fourth quarter of 2001 as compared to the fourth quarter of 2002.

Other factors including share delusion reduced earnings in the fourth quarter of 2002 by $.08 per share.

On a year-over-year basis, Dominion delivery posted earnings of $1.61 per share for the full year of 2002, as compared to $1.45 per share in 2001.

Customer growth added $.04 per share to earnings.

Weather in the electric Fran franchise service area drove an improvement of $.15 per share.

There were 31% more cooling degree days and 2% more heating degree days in 2002 as compared to 2001.

Lower than normal temperatures in the gas franchise service areas boosted earnings by $.07 per share.

There were 4% more heating degree days during 2002 as compared to 2001.

Reduced O & M expenses improved 2002 earnings by $.09 per share as compared to 2001.

Increased service restoration expenses negatively impacted 2002 earnings by $.01 per share as compared to 2001.

A $.02 per share reduction in earnings resulted from lower bad debt expense in 2001.

Lower tax expense improved earnings $.02 per share.

In other factors, including share delusion, reduced earnings of 2002 by $.18 per share.

We will now review the Dominion exploration and production segment.

Dominion E & P is the gas and oil exploration and production business.

Dominion exploration and productions earnings were $.36 per share in the fourth quarter of 2002 compared to $.33 per share in the fourth quarter of 2001.

A 16% increase in equivalent gas and oil production improved quarter or quarter earnings by $12. per share.

Lower averaged realized gas and oil prices reduced earnings by less than $.01 per share.

Averaging equivalent realized prices were $3.63 per MCFE in the fourth quarter of 2002 as compared to $3.64 per MCFE in the fourth quarter of 2001.

Increased expenses reduced earnings by $.02 per share, and share dilution reduced earnings by $.06 per share.

On a year over year bases, Dominion exploration and productions earnings were $1.34 per sure in 2002 compared to $1.27 per share in 2001.

A 35% increase in equivalent gas and oil production improved year over year earnings by $.68 per share.

Lower average realized gas and oil price reduced earnings $.35 per share.

Average equivalent realized prices were there are $3.46 per MCFE in 2002, compared to $3.80 per MCFE in 2001.

These prices exclude the effects of the corporate hedge, which are accounted for in the Dominion energy unit.

Increased expenses reduced earnings by $.10 per share and finally, share dilution reduce the earnings by $.16 per share.

The corporate cost center consists of interest expense on corporate level debt and certain unallocated general and administrative corporate costs.

It also includes Dominion capital results reflecting the performance of its remaining as assets.

The corporate and other segment yielded an improvement of $.04 per share to a net expense of $.25 per share in the quarter of 2002 compared to a net expense of $.29 per share in the fourth quarter of 2001.

The elimination of good will amortization expense resulting from the implementation of new accounting rules improved earnings $.08 per share, quarter over quarter.

Dominion capital earnings were $.02 per share lower in the fourth quarter 2002, compared to the fourth quarter of 2001.

In other factors including their of dilution, reduced earnings $.02 per share.

Year over year, the corporate segments showed an improvement of $.57 per share to a net expense of $.84 per share in 2002, compared to a net expense of $1.41 per share in 2001.

The elimination of good will amortization expense improved earnings $.35 per share for the year.

Lower taxes improved earnings $.07 per share.

Capital increased $.10 in 2002 as compared to 2001.

In other factors including share dilution improved earnings $.05per share.

That concludes our earnings reconciliation and now let me turn the call back over to Tom Chewning.

Now we will review earnings guidance for 2003 and 2004 and then we'll take your questions.

We are reaffirming our earnings guidance $4.60 to $4.[inaudible] per share in 2003, and 5% to 7% growth after 2003 as outlined on the third quarter of conference calls.

The drivers of 2003 expected earnings change over 2002 are as follows.

We expect about a $75m to $85m increase in earnings resulting from higher realized natural gas and oil prices and production growth at Dominion E & P, including the impact of the corporate hedge on consolidated dominion results.

Realized prices in 2002 were $3.29 per MCF equivalent, including the corporate hedge.

In 2003, we expect average realized prices of about $3.55 per MCF equivalent.

We have lowered the production growth forecast from about 10% to about 5% as a result of reduced spending on production drilling, which we forecast will have about a 20 to 25BCF negative impact.

In addition, a delay in the Devil's Tower project from the fourth quarter of 2003 to the first quarter of 2004 will reduce expected 2003 production of additional 7BCF, which we expect to offset with other production gains.

Mill Stone's earnings contribution is expected to improve about $55m in true 2003 compared to 2002, due to stronger knee pool prices, one less outage this year compared to last, and lower O&M expense at the plant.

Growth in the company's franchise service territories will add about $35m to year over year earnings.

Cove Point is expected to add $5m to $10m.

Other factors principally Six Sigma savings are projected to contribute $20m to $40m to earnings.

On the negative side, coming off 2002, we assume normal weather in 2003, and therefore, we removed $45m in earnings help that positively impacted 2002.

Pension expense is expected to have a $30m to $40m negative impact on earnings, as we have changed the assumed return on plant assets from 9.5% to 8.75%, and we change the pension discount rate from 7.25% to 6.75%.

With the exploration and section 29 tax credits, we are losing about $35m in earnings.

Finally, we have budgeted an average share count of 310 million shares in 2003, compared to an actual average of 280.6 million shares in 2002.

There were 308.1 million basic shares outstanding at year-end 2002.

For the first quarter of 2003, we are providing guidance of $1.20 to $1.30 per share, compared to $1.20 per share in the first quarter of 2002.

Looking out to 2004, we expect to be in a position to resume modest earnings per share growth of 5% to 7% over 2003, driven by growth and oil and gas production, recurring franchise growth, a full year of contribution from Cove Point and continued contribution from Six Sigma and other cost reduction efforts.

We'll now open the call to your questions.

Thank you.

At this time, I would like to re remind everyone, if you would like to ask a question, please press star then the number 1 on your telephone keypad.

We'll pause for just a moment to compile the Q & A roster.

Your first question comes from Raymond Niles of Solomon Smith Barney.

Good morning, thank you.

I have two questions.

First, with your E & P forecast, can you give us what the spot price of gas assumption is you are using?

We're --

For 2003.

We're using for the Nimex spot, $3.80.

So working with Nimex.

In terms of Capex productions can you provide specificity with the type of projects that are being scaled back, just give us a flavor for that for '03 and '04.

Generally, it's related to exploration and production in drilling.

That's reflected in the reduced forecast.

We've cut this year's forecast about from 10% growth to about 5%, and we cut the 2004 growth expectations from previous 15% to 20% down to 10% to 15%.

In the E & P area, it is in the discretionary capital that's there for them to go after exploration and production drilling.

And then in Dominion energy, generically, it was capital that was earmarked for generational development projects, and specifically, we've negotiated a cancellation of 10 turbines with GE.

And so it's capital that was earmarked for development of generation projects that were largely associated with those turbines that were cancelled and we delayed the Dresdon project, Mind Cycle project from this year to 2004.

Can you give us a sense of how much the cost was to cancel the turbines?

Zero.

And then -- and then one last thing.

On your E & P, I mean, is this just undifferentiated capital not associated with any specific spending or are you cutting back in certain regions like deep water versus different areas that you are specifically cutting back on?

We're going to ask Duane Radtke to answer that question.

Duane Radtke Yes, thanks, Tom.

You are exactly right.

We're cutting back in some of the areas that are not very capital efficient.

In other words, the deep water and some of the long lead time things that don't generate production and earnings over the next couple of years.

Okay, great, thank you.

Thank you, Ray.

Your next question comes from Kit Konolige of Morgan Stanley.

Hi, Kit.

Just a little follow-up on the E & P with respect to your gas hedges and hedging policy.

I know that you guys have suggested in the past that there might be a point at which gas prices will get high enough that you just go ahead and hedge fairly aggressively out into future years, let's say ' '04 at this point.

Is that any kind of possibility?

Can you just update us on hedge for ‘03 at this point?

We have hedged about 80% of E & P production for 2003, about 55% for 2004, and about 45% of gas in 2005.

On oil, about 80% for next year and 45% in 2004.

So if you take a look at the a weighted combination of those two, 80% for 2003 and 55% for 2004 in the F equivalent and 30% in 2005.

And what would it take to go ahead and hedge the remainder of '04 or is your thinking now that that's too problematic in terms of a market to market effect in '03?

I would expect us to be hedging more of 2004 production in the not too distant future.

And finally, can you give us more detail in a look at '04 about Millstone, how much you have sold coming out of Millstone for how far going forward?

We have Thomas F. Farrell II here and he will answer that question.

All of Millstone is sold forward in 2003, 100%.

And it declines a little bit from that in '04 and a little bit more in '05.

But Millstone is spoken for in a very small amount is open to the markets in '03 and it's largely spoken for in '04.

And is there -- is this an environment where you can get it and would you even want to get it sold forward, even beyond, say, '04 and '05?

We're always, I think it's our policy with respect to electric sales is the same as our policy with respect to oil and gays sales, when we see a number, a market price that we find, we hedge it.

So we're constantly in the market looking to hedge Millstone and the rest of our electric fleet.

Can I ask one other unrelated question?

The -- I've seen references to a review of competition in Virginia.

Can you give us an idea of what is under consideration there and maybe some sense of timing and possible outcomes?

I know at the time that there were bills introduced in the legislature as well.

Tom Farrell will answer that as well.

There is no bill that ‘ undertakes any review of competition, Kit.

There is always a lot of discussion around that.

The bill deadlines were last Friday and there is no bill that does anything like that.

Okay, how about at the commission level?

Is there anything going on with respect to looking at the level of competition?

The commission is required to report to the general assembly on an annual basis on what the status of competition is in the state.

They have done that.

That may be what you're referring to.

Uh-huh.

They do that on an annual basis.

Uh-huh.

As you, I'm sure, recall, that whole issue has been left exclusively with the general assembly.

Uh-huh.

Okay.

All right.

Thank you.

Your next question comes from Michael Worms of GKM.

Good morning and congratulations on a solid year, guys.

Two questions.

One would be in the past you talked about a cost associated with taking out the triggers of about $10m or $15m.

Can you sort of confirm that?

We don't want to present any cost at this point.

We've got a tender out there, and we're not presumption with us as to the final cost.

We don't want to be getting into that.

I will say that the cost range that we have is certainly digestible, and I think I ought to leave it at that, because there is a tender in the market.

Fair enough.

Secondly, you talked about reduced taxes.

Can you kind of give us a little flavor as to what happened on the tax rate?

Sure, this is Steve Rogers.

For the year, you know, in the third quarter, we had a tax benefit related to the reversal of some reserves that were recorded related to Virginia taxes, and then due to some events we had in the third quarter, we no longer needed to have those reserves on there.

That's primarily the reason for the reduced taxes during the year.

And we also have, ordinarily every year we have return to accrual kind of adjustments and some years they are negative, some years they are positive.

They are never huge dollars, but there are dollars related to it and this year they were positive positive.

Thank you very much.

Your next question comes from Tom Hamlin of Wachovia Securities .

Thomas Hamlin Yes, good morning.

Hey, Tom.

Two questions on different items.

You mentioned for '03 guidance, one of the drivers was $20m to $40m from Six Sigma.

Can you identify what in '02 was attributable to Six Sigma?

It was approximately $100m.

Wow, okay.

And second is a follow-up with what Kit was talking about what's going on here in Virginia.

It seems the issues are whether you are joining PJM or not.

Can you address that, the positive and negative and where you're coming out on that?

Thomas F. Farrell II will handle that.

The positives and negative of joining PJM?

Yeah, it seems to be that the state or the commission is against …. saying that there is a threat to competition if you join PJM and where you come out on that?

We have, as you know, signed a letter of intent to join PJM, and we're presently working with PJM to pursue negotiations to see under exactly what terms we would join that RTO.

FERC has its standard market and design going on.

We want to see how all of that comes out before we make any final decisions.

PJM is sort of tried and true transparent market on the positive side, it's adjacent to us, obviously.

We're tide indirectly to it on the negative side it has relatively higher administrative costs than we would like to see.

So those are all things that we're working through, as we move along the path towards competition.

The transfer of transmission business from your group to the delivery business, is that symbolic or does that reflect the unregulated nature?

Can you comment on that?

Actually, Tom, it was the reverse of that.

We transferred electric transmission from delivery into Dominion Energy starting in '03.

When you see the segment, I assume it will be reported that way in the first quarter.

It was more to demonstrate -- to put it along the lines of assets that are in wholesale transmission of energy, gas and electricity would be jointly managed.

Okay.

Thank you.

Thank you.

Your next question comes from Steve Fleishman of Merrill Lynch.

Good morning, Tom.

Hi, Steve.

Couple questions.

First a follow-up on a comment you made on gas prices assumptions.

I think you said that for the un Un-hedged piece the spot Nimex assumption you're making is $3.80.

Is that how I should look at that?

Yes, at the Nimex, that doesn't include differentials, but the small amount of gas that we have and it's not all gas, that's un-hedged, if you drill down into it, would in our budget for the year would be $3.80, using Nimex as the point.

With a $.25 basis differential.

Okay.

Right.

And would it be fair to say that that's a similar range in your budget as you are commenting on '04?

Yes.

Okay.

Secondly, with respect to your bs, could you give us some sense, based on the current business plan you laid out where the debt to capital would be at the end of '03 or at the end of '04 on the fully loaded basis?

I'm going to ask Scott Hetzer, our Treasurer to talk about that.

Steve, you saw a lot of improvement in the numbers that Tom announced looking at the leverage to 12/31/01 to end of the year '02.

We'll expect to continue to make progress in '03 and '04, but quite honestly, I think there is a little bit of a shift with the rating agencies and in particular, S&P to focus more on cash flow coverage of interest.

There is so many adjustments that are being made these days with a-- and adjustments that are, you know, may have been made recently, that I think they are looking more at the coverage than they are the leverage.

But to answer your question, we expect that if we're at 55.6% on a GAAP basis at the end of the year, we'll bring that down into the lower 50s in each -- we'll make progress both '03 and '04.

Okay.

Maybe since you brought that up, Scott, could you comment on your cash flow interest coverages?

What they were in '02 and how they look out '03/'04.

They look very strong.

There has been a lot of improvement in the last two years.

If you look at adjusted FFO to interest, and that's the primary one we're looking at and the primary one that the rating agencies are looking at.

If you make the adjustments of adding back the synthetic leases and the telecom debt you get the FFO to interest coverage of 4.6 times for 2002.

Now, if you make all of the adjustments that S&P is making, you're looking back over the year it's 4.2 times.

Okay.

And I assume you -- in terms of debt market activity this year, I know you've refunded a lot of the maturity at the parent.

Any other -- it doesn't look like you're planning to do additional equity, any significant debt issuance.

That's correct.

As you know, we have $1b maturing January 31st at Dominion, and we issued $500m in December and escrowed $500m of that to cover half of that obligation.

We'll cover the other $500m from our CP balances.

We have a lot of liquidity that we're preserving for that.

That leaves a $1.1bof other re-financings through the year on the debt side well spread between the three legal entities that issue debt and well spread over the calendar for the balance of the year.

And you're correct on equity as well.

We obviously have the assumption of adding in $160m of new equity each year for the next couple of years for dividend reinvestment, customer stock purchase and our savings plan, and that takes care of the improvement that I was talking about.

Okay.

Finally, I don't know if you could give us a little more favor on the expected process of this consent and tender on the fiber venture bonds?

Sure.

As you saw, we announced that this morning.

It is a consent and tender that we're seeking.

Note holders have 10 days to make their decision on the consent.

The consent and tender are link linked for the 10-day period, and at the end of the 10 days, presumably we'll have an answer.

Steve, all we need is a simple majority.

We're looking for 51% approval from note holders.

Dominion owns a few of those bonds, but what we need is 51% of the bonds that we don't own.

After we get the 51% approval, and after the 10-day period, note holders will still have an opportunity to tender, but they will not receive consent fee if they do that.

Does that answer your question?

Yeah, that's helpful.

Thank you.

Your next question comes from Jay Yannello of UBS Warburg .

Good morning, with the weather we're having, can we have a flavor of the gas distribution division, system performance?

Are we breaking send-out records?

How does storage look and possibly more importantly, how is this pricing increase that we're seeing in various areas going to be passed onto customers and how does accounts receivables look going forward.

I'm going to ask Stewart Bolton who is the finance person for the gas side of the business to talk about throughput, and then we'll talk about some of the or the through general statements.

You can also cover the receive receivable side too, Stewart.

With regard to the weather, the weather is real good for the company both on the gas and electric side.

We have no problems at all meeting the increase in load.

With regards to the receivables, we've made significant progress over the course of the last year in collecting the outstanding receivables we had from 2001, and we would expect no problem in collecting those receivables.

This year, particularly after the weather breaks and turns warmer, we would aggressively pursue any customers that do not have current balances with the company.

The gas price increase, we just filed for an increase in the GCR in Ohio.

We're current with regards to current prices there.

And in Pennsylvania, we'll be filing shortly for an increase in the GCR there and we would expect to have no problems with the commissions approving those increases as filed for.

Yes, basically, what we have in our LDCs would be a pass-through of the supply cost, and we have done a much better job on collection and receivables in the gas area.

We actually reserve about, I believe, 7.9% of gas sales as a reserve on receivables and, of course, on the electric side, we historically have done much, much better than that, and we re reserve .7 of 1% and historically those numbers have been pretty solid for us.

Okay, thank you.

Your next question comes from Jay Dobson of Deutsche Bank.

Hey, Tom.

It’s Jay Dobson with Deutsche.

Hey, jay.

One clarification, when you were going the '03 reconciliation, you basically did $55m from Millstone there was a $35m piece that followed that that.

Could you clarify what that was?

Hold on a second.

That'll be franchise growth on the electric and the gas, mainly electric.

And we had that -- we've had that kind of experience for a number of years.

Including 2002.

That's great.

Could you give us a little more specificity around the revised schedule for the reactor vessel head replacements that'll finish up now this year?

Yes, Tom Farrell once again will answer that one.

Good morning, Jay.

Good morning.

When we decided to replace the vessel head on North Anna 2 in October of 2002, we announced we were going to do that and that we would replace the remaining vessel head at North Anna and the two Surry vessel heads starting in '04 and '05.

We announced at that time that North Anna 2 will be up and running at full power by January 31st.

We -- as we worked through the process of installing the North Anna 2 vessel head, we realized that we know exactly what we're doing with this process.

We've gotten it down to lots of the engineering work has been done.

With we understand the processes and we decided to go ahead, in view of the fact that we were having a very successful operation, that we would go ahead, secure an additional three vessel heads and install those in 2003.

So, the other North Anna head will be installed this spring.

One of the Surry units will follow that in the spring.

We'll have all four operating in the summer and we'll take down the remaining Surry unit in the fall of this year.

Those are coincident with already scheduled refueling outages.

There is not any additional out outage that will occur.

There will be some additional days associated with what would have otherwise have been a refueling outage.

That's all accounted for in the earnings estimates we've given you for 2003.

And start to finish, those are running as far as days go about how long?

And just speaking of the RV8 replacement.

The North Anna 2 will take longer than the rest will take because we have to get our hands on the vessel head and get it modified.

We haven't previously announced this, but we have been working on modifications of the other three heads during the last three-month period.

We don't have that kind of a holdup.

So those -- what really will just be an extended refueling outage will take between 55 and 60 days total.

That will include installation of the heads.

Great.

Just two more questions, if I can.

On Six Sigma, I mean, you've had great success here obviously '02 and looking out into '034.

How should we think about this going forward, $100m, I think Tom said for '02 and $20m to $40m for '03.

I'm sure that's work that's never done but is that something that run rates out at $10m to $20m we should think of for '04?

I don't really think so.

I think we have ample number of opportunities in the company to to -- and we really are limited by the amount of Six Sigma resource we want to have in any one year, and we would expect it to be in the same range for 2004 that we've given you for 2003.

As you can tell, we got a lot done in 2002.

And so we've actually cut it back a good bit.

Some of the Six Sigma savings are kind of included in the budgets and in the projections of some of the units.

This is kind of over and above that.

So we think it cumulatively just keeps rolling and we have cut it back a good bit in terms of expectation but I frankly think Tom Capps would be upset if we didn't do better than what we've told you from Six Sigma.

Great, in answering someone else's question you mentioned you had reduced the E & P volume production growth in '04 to 10-15% from 15-20%.

I wanted to confirm that and also figure out what that would be at Devil's Tower.

How much of that is Devil's Tower, the 10 to 15%.

Duane Radtke, can you tell us what the impact will be?

In '04 almost all of that drop ofthe 5%.

The rest of the programs are right on spot.

And we would still expect the first 12 months of production to be about 60 BCFE equivalent.

Maybe I'm confused.

When we're talking about '04, we said Devil's Tower is being kicked into the first quarter.

We should get a whole production run in '04 from Devil's Tower.

My question is if we're doing 10% to 15% volume growth in '04, what would that be x Devil's Tower.

The first 12 months of full months of production, you have a ramp up when you start up.

Yeah.

That's why we lose the 15 to 20 Bs in 04.

We would expect the first full 12 months to be 60 BCFE.

Thanks so much.

That really explains it.

Some of it will move over to ’05, another words.

Great, thank you.

Your next question comes from Curt Launer of CSFB.

Good morning, Curt.

Good morning, can you hear me me?

Yes.

Sorry.

Just wanted to follow-up with some additional questions relative to the E & P side, the capital expenditure reduction brings to mind the reserve base, and I'd like to ask if the capital you have devoted to the business now is enough to be designed to keep the reserves out around the 6 TCF level or if you are looking for that to decline as well.

If you could add some sense of current percentages of where the reserves are, according to the basins in which you have interest.

I would appreciate that information as well.

Duane?

Sure, be glad to.

First, we need to look at the fourth quarter alone.

We had drilling-in results that added almost 400 BCFE equivalents and reserves and acquisitions of another hundred.

We had 400% replacement ratio.

For the year, we added 1.6, which is about 350% replacement ratio.

We had a good year across all of the basins.

The programs that we have in place, both in the on-shore and the off-shore, we had a very good program.

To answer the first part of your question, in the short-term, with the reduced capital expenditures, because we have spent so much capital up front on DT and Frontrunner, there is very little impact.

But obviously, in the outer years, as we grow, 900 or, a cut of capital, we would need more capital to sustain that production.

Okay.

And the basins in which you have interest on a percentage basis?

Again, I don't have the detail of where we added all of the reserves by basin, but the program in Sonora, which was from the Louis Drefus(ph) acquisition mainly, we expect to drill 400 to 500 wells this year.

We 400 wells this year.

We expect 200 wells in Appalachia, and continue to be active on the shelf where we've had good successes in the last year.

Thank you very much.

Your next question comes from Paul DeBoss(ph) from ValueLine.

How much off bs do you have off right now?

Scott, do you have that?

I assume you are talking about synthetic leases and the tele-com debt and that is a $1.3b on the synthetic leases and $665m on the telecom side.

So right around $2b.

Are those synthetic leases go on the bs this year?

No, we have seen, you know, what -- we have been watching carefully FASBE's action over the last few months and the guidance they came out with recently.

We're looking at alternatives which would allow us to keep them off bs and importantly preserve the flexibility that we have with those financings right now.

So it's too early to report, but we're watching it very carefully carefully, we're looking at a structure that would allow us to keep the same flexibility going forward.

Okay, and separately, with the loss of the Section 29 tax credits, what do you expect for the tax rate this year?

Probably around 38.

Thank you.

Your next question comes from Paul Ridzon of McDonald Investments.

Paul Ridzon Can you hear me?

I want to clarify that North Anna is done.

Is it running yet?

North Anna's replacement vessel head has been installed on the vessel and at this point, you only really left with coming out of what would otherwise be a normal refueling sequence.

We anticipate that the unit will be at full power as we said -- gave you the date in October, January 31st.

Did you tell us what the impact of coming off EITF9810 was, an update on the hedging on the power side?

And your guidance for the first quarter of 120 to 130 have you factored in weather year to date in that

I'll answer the first one -- the last one first, and that is the weather has not been impact impacted -- included.

The reason is because even though we obviously are experiencing extremely cold weather, we're very much impact impacted by February and March.

So I think the 23rd of January January, we don't want to call the end of the quarter today or extrapolate a number, but obviously, we've used normal weather in the first quarter as we always do in terms of giving you some sort of guidance.

Now, I'm going to ask Steve Rogers to cover some of your earlier questions.

Okay.

Coming off of '9810 for Non-derivative contracts, it's going to affect the timing of earnings recognition, but it doesn't effect the economics of the clearinghouse and that is built into our '03/'04 numbers that we're putting out there.

I couldn't tell you specifically what the delta is between the two, but it is built into the guidance we've given you.

In addition, we will be recording a cumulative effect related to that change in the first quarter quarter.

We expect that that will be a negative adjustment.

However, we'll also be recording the cumulative effect related to a new standard around asset retirement obligations.

Both of these numbers are being reviewed right now, but we expect the asset retirement obligation number to be positive and to at least offset the impact of the market to market cumulative effect we'll be recording.

You mentioned some new interest or new acquisitions in the am Appalachian basin.

There is continued assets for sale there.

Would you have any interest in looking at those?

Thomas N. Chewning I don't believe we specially mention acquisitions in the Appalachian region; we talked about drilling wells there.

We have a lot of property on which to drill.

Duane, am I correct in that?

That's correct, Tom, we did not make any acquisitions in the Appalachia.

Would you have any interest in making acquisitions there?

Not unless we asset sales that would free up money and we trade it off or swap or something like that.

We have, as you know, over 6 trillion cubic feet of reserves, so, you really don't need to have more, but sometimes we would balance, but it would be balance from a financial standpoint and kind of a trade- trade-off, either a swap or something where we liquefied one basin or part of a basin and switched in to Appalachia.

Just an update on the power hedging.

What precisely is your question?

How much unregulated megawatts are sold forward for '03/’04.

Of the total package, Tom will give you the latest number.

The total portfolio for 2003 is 96%.

And for the Merchant, it's 84%.

Paul Ridzon Any '04 numbers?

For 2004, 85%.

The Merchant is about half sold

for 2004.

And any views on near-term, intermediate term fundamentals for power pricing?

We expect prices to stay relatively stable for at least the next year and probably into 2004.

And then start to increase.

Okay, thank you very much.

Thank you, Paul.

Your next question comes from Douglas Distable(ph) of Ducane(ph) Capital Management.

Hey Doug, how are you?

Fine.

I wanted to follow up on an E & P question.

You talked about a potential for maybe swapping reserves from one basis to another, but have you considered now with [inaudible] of reserves and reduced Capex on the [inaudible] side, maybe even monetizing some non-producing reserves and just accelerating the improvement in the bs that way?

Well, certainly, Doug, as we've said before, we're always looking for opportunities like that.

We also have opportunities outside of the E & P to sell as assets, such as in Dominion capital.

We look at this as a port foal your probation and we don't ever project any asset sales in our numbers in improving our financial ratios, but that doesn't mean we take those out of our quiver in terms of being able to use it as a technique, and we take a look at our portfolio and decide whether we need to add generating units or add or subtract E & P or whatever, and we have a lot of interest from people who want to buy and sell us things from time to time and so everything is open, but it has to be very economic to us, you know.

We don't feel compelled to have to sell an asset in order to improve our bs.

It seems to be improving as we predicted it would.

As Scott pointed out, even more importantly, the ratios of FFO to interest have been very, very strong and probably a little bit ahead of where we thought we would be at this time.

I think it's from a position of strength that we take a look at it.

If someone really values properties to a greater degree than we do, and we can find an alternative use for the money either to reduce debt, if that was appropriate, or acquire other core assets.

We would consider it.

Thanks, Tom.

Ladies and gentlemen, we have reached the end of the allotted time for questions and answer.

Mr. Chewning, do you have closing remarks?

I want to thank everybody for being with us.

It's delightfully cold in Richmond today which gives us an uplift for the year.

We're very, very pleased with the progress we've made on a lot of fronts, and I hope that you are as well.

We're very optimistic that even through these choppy times that we're going to have a great 2003 and in looking ahead at 2004 and beyond, we expect to be right back in as a solid performer and a strong growth company in the years ahead.

So we -- we've been battered along with other people in the industry, but we're very, very optimistic here because our performance has stood the test of the tough times, and even though there's some more choppy waters ahead, we're very cost confident we'll be able to navigate through that.

We've got a great team and a great set of assets and we're very fortunate to be at Dominion and hope that you feel the same way.

Thanks very much for being with us this morning and we look forward to talking to you at the end of the first quarter.

Thank you, Mr. Chewning.

This concludes the conference call.

You may now disconnect.