道明尼資源 (D) 2004 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Dominion Resources second-quarter earnings conference.

At this time, all participants have been placed on a listen-only mode and the floor will be opened for questions following today's presentation.

It's now my pleasure to turn the floor over to your host, Tom Chewning, Chief Financial Officer of Dominion.

Please go ahead, sir.

Good morning, and thank you for joining us for our second-quarter 2004 earnings conference call.

Joining me this morning are Tom Capps, our CEO;

Tom Farrell, our COO; and numerous members of Dominion's management team.

Today we will present the usual cautionary language up front and then cover particular areas of interest related to our results, as well as the view going forward.

After our prepared remarks, we will respond to your questions and comments.

Concurrent with our earnings announcement, we have published several supplemental schedules to our website.

We ask that you refer to those exhibits for certain historical quantitative results, as well as earnings guidance detail, commodity hedge positions and prices.

Our website address is www.dom.com/investors.

Now for the obligatory 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 a discussion of factors that may cause results to differ from management's projections, forecasts, estimates, and expectations.

Dominion uses operating earnings as the primary earnings performance measurement for external communications with analysts and investors.

Operating earnings is a non-GAAP measure.

We define operating earnings as reported earnings adjusted to exclude the impact of certain items.

Examples include cumulative effects of changes in accounting rules, asset impairment charges, and nonrecurring events.

We do this because we believe that earnings as adjusted, or operating earnings, provide the most meaningful representation of the Company's fundamental earnings power.

We also use operating earnings for budgeting and reporting to the Board of Directors of Dominion, as well as for the Company's profit-sharing plan.

In addition to operating earnings, we will discuss some other measures of our Company's performance that differ from those recognized by GAAP.

You can find the reconciliation of non-GAAP measures to GAAP on our investor relations website at www.dom.com/investors.

This morning, we will review our second-quarter 2004 results, refresh our guidance for 2004, update cash flow and other financial forecasts, and discuss our plans for common stock dividends going forward.

Additionally, Tom Farrell will discuss what variables impacted our fuel expenses and how the integrated model under the amended Virginia law is performing as we expected.

Tom will also provide a review of second-quarter results and activities at the Dominion Energy Clearinghouse and update our forecast of this unit going forward.

Duane Radtke will give us an update on the NT business, including a progress report on Front Runner and the ramp up of production at Devil’s Tower, and will provide some details related to our upcoming analyst meeting on September 14th.

Dominion posted operating earnings of 81 cents per share in the second quarter of 2004, compared to 86 cents per share earned in the second quarter last year.

On a GAAP basis, we reported net income of 76 cents per share in the second quarter of 2004 compared to net income of 76 cents per share in the second quarter of 2003.

While our operating earnings were at the upper end of our guidance, there were 2 items that masked the actual strength of the quarter.

Included in the second quarter is a 23 million or 7 cent per share charge for fuel expenses incurred during the first quarter that are no longer recoverable under the new law.

Second-quarter 2004 operating earnings also included a negative 2 cent per share mark-to-market impact related to our corporate hedge on future 2004 natural gas production.

This expense is strictly timing in nature, and will reverse later this year when the positions are settled and the physical gas is produced and sold.

Adjusting for these 2 items, we would have produced operating earnings for the quarter of 90 cents per share.

Based on solid year-to-date results, and the performance of the Dominion integrated model in the second quarter, we are reaffirming our full-year 2004 earnings guidance for $4.75 to $4.90 per share.

We expect third-quarter results between $1.25 and $1.35 per share.

A schedule reconciling the third quarter of '04 to the third quarter of '03 can be found on our website at www.dom.com/investors.

Our key credit metrics are solid and are improving.

Our adjusted ratio of debt-to-total capitalization improved 200 basis points from 56.8% at the end of the first quarter to 54.8% as of June 30th.

For the 12 months ended June 30, funds from operations covered our interest expense about 4.3 times.

And this ratio is expected to show further improvement in the remainder of 2004.

Free cash flow for the first half of the year was $553 million, including the cash impact of our second VPP transaction, and is projected to be approximately $725 million for the year.

And available liquidity was 1.645 billion at quarter end, about 2 times our liquidity level at the end of the first quarter.

The improvement in liquidity is a result of additional credit facilities of $650 million, as well as a repayment of Fairless work construction costs to release financing, and proceeds from the VPP transaction.

We are pleased to announce that our Board has endorsed management's recommendation to increase our dividend by 2 cents per share in the fourth quarter of this year and by 8 cents annually thereafter.

Our integrated model is performing to our expectations, our cash flow is strong, and our credit metrics continue to improve.

Now we are happy to report that our dividend will be increasing as well.

The second quarter included some other noteworthy developments.

Corporately, we turned the page on the story of our integrated model following the signing of the law being (indiscernible) to Virginia Utility restructuring, which extends our cap rates through 2010 and locks in our fuel rate until mid 2007.

And we completed a sale of our Dominion telecom business and our interest in Epic Energy, an Australian natural gas pipeline.

At Dominion E&P, we registered the first production at Devil’s Tower; announced discoveries of the Gold Finger, San Jacinto and Thunder Hawk prospects; completed another volume metric production payment agreement, this one with Goldman Sachs for $413 million, representing the sale of 82.7 Bcf of natural gas production; and we celebrated the completion of the 2000th well drilled in Sonora.

At Dominion Energy, we signed a 20-year contract giving Statoil access to increased capacity at the Dominion Cove Point liquefied natural gas plant in Maryland.

Plans call for increasing the plant's capacity from 1 Bcf per day to 1.8 Bcf per day, and its storage capacity from 7.8 Bcf to 14.6 Bcf by 2008.

The project also includes associated pipeline and natural gas storage projects in Maryland and Pennsylvania.

At Dominion Generation, we placed into commercial operation the 1,180 megawatt Fairless Works combined cycle Generation facility, located in Pennsylvania along the Delaware River.

And we reached an agreement to purchase 2 non-utility generating facilities.

We also announced an agreement to sell our Dominion Cleveland thermal asset.

And at Dominion Delivery, we signed an agreement to privatize distribution facilities at 4 military bases in Virginia, and experienced over 22% customer growth at Dominion Retail and about 1% in our franchise businesses.

Concerning our commodity hedging, we've hedged approximately 93% of our Generation capacity in 2004, 92% in 2005, and 88% in 2006.

Using traditional means including swaps, collars and other securities, about 80% of our remaining 2004 oil and gas production is hedged, 62% of 2005 and 53% of 2006.

Adding to the mix, our expected consumption by a natural gas and oil fire generation in Virginia, we are 100% hedged in 2004, and about 82% in 2005 and 72% in 2006.

Approximately 95% of our 2005 coal needs and 35% of our 2006 coal needs have been contracted. 100% of our expected 2004 coal needs are hedged.

Further details regarding our hedge positions on natural gas, oil -- natural gas and oil and generation capacity are available on our website.

At this point, I'd like to turn the call over to Tom Farrell to review the factors that influence fuel usage and cost, as well as Dominion Energy Clearinghouse second-quarter performance and expectations for the remainder of 2004.

Tom?

Thank you and good morning.

Before the legislature convened this past January to consider extension of the cap-based tariff rates until the end of 2010, and adding the possibility of freezing our fuel factor, which had just been increased by record amounts in October of 2003, freezing that until July of 2007, we took a very hard internal look at how the dynamic of 3 different factors would work, depending upon weather.

We looked at what would happen to our base rates -- revenues if weather was higher than -- hotter than normal in the summertime; what would happen if it was lower than normal; what would happen to -- what units would we run; what would happen to commodity prices and how would that reflect itself in our fuel costs.

And then the third factor was, what could you predict would happen -- be happening to E&P prices, gas prices in particular, during -- with that same dynamic.

Based upon our review of that, we thought it was a good deal to work out the legislation with the Governor's office and the Attorney General's office, a good deal for our customers, and one we thought would work, at least neutral to us and perhaps to our benefit.

We explained that in some exhausting detail at our May 6th meeting, our analyst meeting last -- in May.

And we believe that the results in the second quarter not only demonstrated that we were correct in that, it demonstrated it under very difficult circumstances.

The second quarter weather and fuel and E&P and Generation usage was all about the month of May.

And I'll explain that in a second.

But in the second quarter, the offset -- the differential between the increase in our base tariff sale revenue numbers and our increased Virginia fuel expense was about $6 million.

So the net difference in increased revenue from tariff rates and net increase in -- and increase in expense netted out to about $6 million over the quarter.

That was offset by $6 million increase in our E&P earnings, caused by higher E&P prices because of the weather.

So in effect, the second quarter turned out to be flat on the dynamics of the 3 factors I discussed a minute ago.

Over the year-to-date, we were actually up about $7 million in that category.

We expect that to improve over the balance of the year.

Let me explain to you about May for a sec, why the second quarter was about May and why we are very encouraged by the results of how these dynamics work together in the second quarter.

April and June were about normal weather.

May in Virginia was the hottest May on record.

It was 141% of normal in cooling degree days.

Now, if you have a frozen fuel factor, that's an issue for you.

Particularly in our case, since we had several planned outages that would not have been planned if we had known at the time that they were set up that we would have the frozen fuel factor.

We had a 28-day refueling outage at North Anna, all of which took place in the month of May.

We had the largest coal unit in our fleet, our Chesterfield 6 -- 680-megawatt coal unit, was out for 15 days in May as we brought its pollution-control equipment up to speed that had been installed.

And we had a 7-day unforced outage at Surrey.

So our 3 lowest-cost units in the fleet were out of service for significant parts of what was the hottest May on record in Virginia.

And we ended up with a $6 million differential in costs offset by $6 million in E&P.

It's important also to note 2 other factors.

If this heat had occurred in June, not only would we have had those units available, we would have had a tail-block in our rates -- in our tariffs in Virginia, so that in the months of June, July, and August, our actual -- our tariff revenues actually increase because they're trying to reduce usage.

So as you go into the hotter days and our megawatt loads go up, the actual tariff per kilowatt hour increases.

We did not have that tail-block advantage in May.

We also, of course, have in 2004 more E&P hedge than we will have in the future years.

So all in all, we think that the second-quarter performance demonstrated that we were correct in our assessment of how the dynamic of our frozen fuel would work with our E&P business and the extension of our tariff-based rates -- a good deal for Dominion and a good deal for our customers.

Now, I'll turn to the Clearinghouse.

In the second quarter, excluding the effects of the corporate hedge, the Clearinghouse had a $17 million loss compared to a $2 million profit in the second quarter of 2003.

The year-over-year change resulted from a $9 million pre-tax negative gross margin this year, compared to a $18 million positive pre-tax gross margin last year.

The results this year were driven largely by 4 positions based on our view of market fundamentals.

Though the positions were based on sound analysis, geopolitical events in Iraq and elsewhere introduced a level of market risk with which we became increasingly uncomfortable.

As a result, we exited the positions by the middle of the second quarter, prior to their expiration, at a loss.

While the losses incurred in the second quarter and year-to-date have been very modest, losses of any size are unacceptable.

So during the second quarter, we conducted a thorough review of the organization's fixed costs and products.

We also took into account the opportunities presented by the new deregulation law passed this year, Senate Bill 651.

As a result of this review, and as we forecast at our May 6th analyst meeting, we have remissioned the Clearinghouse and pruned some areas of emphasis.

We have reduced the workforce by a little over 30 people, lowering the related fixed-cost burden about 15%.

More importantly, however, the Clearinghouse will take on a more internal emphasis, a sharpened focus on hedging, and optimizing Dominion's assets.

The Clearinghouse will continue proprietary trade, as Dominion's physical presence in MAIN-to-Maine offers a natural competitive advantage in both market knowledge and physical capabilities.

Proprietary trading never has been and never will be managed as a growth engine for Dominion's earnings.

Its percentage contribution to Dominion's overall earnings should actually decline as earnings at the other operating units continue to accelerate.

An inward focus on asset optimization with an element of trading is nothing new for the Clearinghouse.

In fact, it was for these reasons that the Clearinghouse was originally created.

As the Company has grown, so has the Clearinghouse, both in size and responsibility.

For instance, when we added the Millstone power station to the portfolio in 2001, Clearinghouse assumed the duty of selling the output and optimizing value by taking Millstone's flat blocks of power and creating a premium product by adding shape and services.

As E&P has continued to grow, the Clearinghouse has worked to hedge the growing production volumes and to develop different structures to optimize the positions.

Both are good examples of Clearinghouse's primary role.

The effort in risk management occur at the Clearinghouse.

The earnings accrue at Dominion Generation and at Dominion E&P.

In addition to grow growing the internal asset optimization side of the business, the Clearinghouse has, over the past few years, and in particular earlier this year, added additional geographic scope to its existing business lines -- for example, producer services in Houston and Calgary.

We also expanded into related product lines -- for example, coal, oil and emissions trading.

This was done to provide an element of earnings growth and balance within the Clearinghouse portfolio.

Some of these product lines have been successful, in particular coal trading.

Others have been less successful, and we have discontinued them as a part of this remissioning during the second quarter.

We are exiting, for example, the Calgary Producer Services effort and have greatly reduced our efforts in Houston.

While earnings from the Clearinghouse are not expected to grow significantly over the coming years, Clearinghouse's value to Dominion, to the integrative whole, will continue to grow along with the rest of the Company.

That value will, to a large degree, show up in the earnings of the other business units as Clearinghouse works to optimize the assets and earnings for the fully-integrated Dominion.

The changes made during the second quarter at the Clearinghouse are consistent with what we told investors at the May 6th analyst meeting.

We expect Clearinghouse to contribute in a range of $40 to $60 million annually on a sustained basis in 2005 and forward, and at a level of $20 to $40 million in 2004.

That is the level of contribution we are comfortable with, and a level we are comfortable we can deliver.

These levels of contribution are consistent with current consolidated earnings guidance for 2004 and 2005, as well as Dominion's expected growth rate going forward.

Thanks, Tom.

Thank you, Tom.

Now I'll ask Duane Radtke to give an update on Devil’s Tower and Front Runner.

Duane?

Thanks, Tom.

As you mentioned, Devil’s Tower, which is 75% owned by Dominion, 25% by Pioneer, but operated by Dominion, went onstream May 5th.

We currently have 2 wells completed and we're producing about 22,000 barrels a day equivalent per day.

All 6 of the additional risers have been run and completed.

We're on our third completion, which we expect to have done probably the second week of August, which would be on schedule or slightly ahead of schedule.

At Front Runner, where Murphy is the operator, Dominion holds a 37.5% interest.

We are still on schedule for an early fourth quarter production start-up.

We look forward to the second half of the year as production ramps up from DT, and well into '05 as we have both DT and Front Runner onstream.

Thank you, Duane.

We would like to invite you to attend an analyst meeting that we will host on Tuesday, September the 14th at the Waldorf Astoria.

At this meeting, Duane will lead a discussion on Dominion's natural gas and oil business, and why it is an important element to the integrated model.

We want not only to demonstrate that E&P is a good business, but also that we are actually pretty good at it.

Additional details will be coming soon.

Before we go to questions, I'd like to point out a slightly new look to our Investor Relations website.

We've come to understand that much of the information we believe to be of value to you has not been easily found.

We encourage you to visit www.dom.com/investors and go to quarterly update.

Here you will find updated financial and statistical schedules, as well as exhibits detailing our commodity hedge position and reconciliations to our earnings guidance range.

That concludes our prepared remarks.

Now we'll open the line for your questions.

Thank you.

The floor is now open for questions.

If you have a question, please press star, then 1 on your touch-tone phone at this time.

If at any point your question has been answered, you may remove yourself from the queue by pressing the pound key.

We do ask that while you pose your question, that you pick up your handset to provide optimum sound quality.

Once again, to ask a question, please press star, then 1 on your touch-tone phone at this time.

Our first question is coming from Dan Eggers of Credit Suisse First Boston.

Please go ahead.

Good morning.

Morning, Dan.

Not to be lazy, but if you look at the earnings guidance you guys have for the full year and then what you put out for the third quarter today, add that to the first and second, it looks like you're implying about $1.20 to $1.35 in the fourth quarter, which is pretty strong relative to history.

Could you just give us a little bit of a flavor of what all you think is going to show up in the fourth to give the fourth a look similar to the third?

We have a number of items, and I might ask Joe O'Hare to kick them out.

For one thing, you know, where we just concluded a ramp up of production at Devil’s Tower and that will continue on.

We've got reversals of various positions in the Clearinghouse that will show up.

As you see, they've been a loss year-to-date and we expect them to record a profit for the year, continued growth, franchise growth, a better situation in terms of generation availability and hopefully onto the fuel side for the remainder of the year.

But, Joe O'Hare, do you have any other items that would be significant?

Yeah, Dan.

One significant thing is, it would be Millstone.

I mean, in the fourth quarter of 2003, there was an outage in Millstone, which we will not have a scheduled outage in the fourth quarter of 2004.

That's a significant upside.

I would say that's really the most notable thing other than E&P, certainly with the production of Devil’s Tower and the commodity price help that we expect.

I have a full reconciliation that's preliminary that we can discuss later.

I do not have that on the website, because we really want to adjust that based on third quarter actual results.

And also we will have a first reduction from Front Runner.

So, you know, we didn't have either one last year.

And then we've got Cove Point this quarter as well.

Great.

Thank you, guys.

And I guess the other question, looking at a dividend increase, you know, relative to other investment opportunities you have out there, buying back the NUGS, among others, should we view today's announced increase as just trying to keep up with earnings and the growth strategy will stay in place otherwise?

Yes.

I think, you know, besides the 5% to 7% growth that we've talked about is included in our models, although we have not previously announced it, dividend increases.

And we hadn't done any for 10 years now.

And I think it just shows the optimism that we have about cash flow and earnings.

The payout ratios will still continue to be fairly low.

I might ask Scott Hetzer to chime in here and kind of give you more or less the view that we gave our finance committee and directors in our recommendation.

Dan, this is Scott.

We expect to be at about a mid-50% payout range for 2004.

And we've always said kind of the -- that was our target, that or low 50s.

And with this dividend increase and what we see for earnings for the next several years, we still will be in the low 50s.

In fact, may actually, you know, pierce through that and be in the high 40s within the next 5 years.

Great.

Thank you guys.

Thank you.

Thank you.

Our next question is coming from Steve Fleishman of Merrill Lynch.

Please go ahead.

Yeah, hi, everyone.

Hey, Steve.

Could you be -- go maybe more specific through the E&P quarterly earnings factors here?

For example, there was a big reduction in O&M expense and taxes.

Could you explain that?

And then just go through the VPP impact.

Is that an ongoing 10 cents a quarter?

Or is there any one-time nature of that extent of impact?

Okay.

Duane, would you like to handle --?

Sure.

First, Steve, on the quarter-to-quarter comparison on there, pricing did improve by about 1 cent; when you add the VPP production and DD&A that was about 5 cents.

But as you mentioned, the O&M was 9 cents.

The largest component of that was the FAS 133 movement, like we had last quarter, and we chose to lock in some of that value.

And, again, you know, with the FAS 133 there's really 3 components that move.

You have the hedge ineffectiveness, the D-designation of the hedges and the options.

And the structures that we put around some of our hedges actually had some call options to help protect some of the cash-margin calls.

And as prices moved up, particularly on oil, we moved through those hedges.

And so you had a great deal of both real value and option value move forward.

So, again, we worked with the Clearinghouse, as Tom Farrell had mentioned, and chose to lock in that.

That's the biggest amount of the 5 -- of the 9 cents.

Of the 5 cents on taxes, that's Canadian tax-rate change and some state income tax changes.

When you look at the VPP component of that, we lost about -- the VPP gained about 10 cents.

Yes, we would expect that on a going-forward basis, the way the accounting works on the VPP.

So 10 cents a quarter?

We would have a quarter-to-quarter comparison.

Now, I'd have to go back and look at what it does on an annual basis.

I guess those are 2 different VPPs now.

That's correct.

If you remember, we did one last year, where we sold 66 Bs for 266 million.

Yeah.

This year we did 83 for 415.

So you have different pieces rolling off at different times.

Maybe if you could just clarify, on these O&M and the taxes, is that 9 cent O&M, would you say that's all related to these -- the FAS 133 -- you know, essentially locking in gains on hedges?

The vast --

Would O&M otherwise have been up?

The vast majority of it was that way.

What we like to look at is we try to separate those types of movements out of what we would call "lifting costs," and our guidance has been 85 to 95 cents.

And for the first half of the year we were at the low end of that range.

As we move forward into the second half of the year, we'd expect to start moving more into the middle of that range.

And then on the taxes, is that of these tax adjustments?

That was a one-time gain.

Those are all one-time?

Okay.

Right.

And then I guess, to Tom Farrell, with respect to explaining this 6 million margin benefit, or margin -- I guess hit at Generation and 6 million benefit from E&P you talked about --

Yeah.

How do I see that in the numbers that you do on the kind of -- the guidance here?

Is that kind of -- if I look at Generation, weather's a 9-cent benefit; customer gross, a penny.

And then you have the fuel expenses in excess of rate recovery of negative 12.

So net-net that's a negative 2 cents?

Right.

Is that kind of the pieces you're looking at when you're -- or are you just looking at gross margin?

No.

That's the piece -- those are the pieces we're look looking at.

Okay.

Okay.

Thank you.

Thank you.

Our next question is coming from Paul Fremont of Jefferies & Company.

Please go ahead.

A couple of questions.

One, basically you talked about some coal plant outages during the quarter.

Can you give us a sense of what the coal capacity utilization has been this year and what you would expect it to be for the year as a whole?

I will ask Mark McGettrick to cover that.

The outage that Tom was referring to -- there were planned outages in the spring period.

Through June of this year the availability on fossil's been about 83%, which is better than what we've anticipated at this point.

If you look at -- as compares since last year we would have been about 79% in terms of availability through the first 6 months.

We expect that availability actually to get higher as the year goes out, because our spring outage season was significantly heavier than what our fall outage season is.

And in terms of utilization, instead of availability, where have you been running this year relative to last year?

In terms of capacity factors?

Right.

Capacity factor for the first part of this year would be -- for the first 6 months this year would be in the mid-70s and for '03 would have been in the upper 60s.

So in a sense, then, the '03 levels would be aberrationally low and this is a return to more normal levels for the coal fleet?

I think that's probably right year-to-date.

We did a lot of emission-control work last year in preparing for the requirements that were due this summer.

So I would say, yes, '03 was a little bit low.

Okay.

And -- and I know you've given guidance previously with respect to the targeted level of nuclear utilization that was included in your regulatory plan.

Was there any sort of targeted level of coal utilization included in the plan?

Or -- leave it at that.

Really, the -- in terms of the fossil fleet, it's a combination of a lot of factors based on coal and oil prices.

The dispatch mix could change, as well as planned outages one year to the next.

Right.

But in other words, was there any adjustment made for an assumed increase in your -- in your coal capacity utilization, or was that sort of not --?

No.

Excuse me.

It was based on historical levels.

Okay.

And I guess my last question would be following up on Steve Fleishman's question on O&M.

Within the E&P business, the unusually low levels of O&M and E&P in the first and second quarter, you would expect to basically not be recurring in the sense that they would -- they should return to historically higher levels.

Is that correct in terms of -- for forecasting purposes?

Tom, I'll take that.

Yeah.

For -- for the lifting cost, again, the guidance is 85 to 95 cents.

The O&M movement that you saw in the first and second quarter, the positive movement, was mostly through the FAS 133.

Obviously, each quarter -- and we take a look at what our FAS position is, there may be an opportunity to lock in some more of that going forward.

But we've not completed that analysis yet.

Paul, this is Tom Chewning.

I think the bottom line is that we've taken a normal lifting cost, et cetera, on the guidance for the third quarter and for the year.

So I -- if it doesn't, it's reflected not, you know, FAS 133 movement, but just normal levels.

Thank you.

Thank you, Paul.

Thank you.

Our next question is coming from Ron Barone of UBS.

Please go ahead.

Could you give us an idea of the impact of the nuclear decommissioning trust on the quarter?

Yeah, Ron, I'll take that.

The third -- second quarter of 2004 was $4 million less on a pre-tax basis than it was in the second quarter of 2003.

So on an after-tax or a per-share basis it was 1 cent or less.

Okay.

And, secondly, could you give us an idea on how far out of the money the hedges were -- sorry, the Clearinghouse positions were when you covered them?

We cover them at all different times, over a series of days.

So I don't think we could -- I could give you a very precise answer on that.

Okay.

Thank you.

Thank you, Ron.

Thank you.

Our next question is coming from Hugh Wynne of Sanford Bernstein.

Please go ahead.

Hi, guys.

Hey, Hugh.

Just -- hi.

A couple quickies.

Millstone, the -- the reduction in production there was due to a scheduled outage, I assume?

That's correct.

Okay.

That was fueling related?

Refueling related.

Yep, okay.

And the other quickie was on the operating revenue breakdown that you provide on page 8 of the selected financial statements.

There's a rather substantial increase in other revenue on a consolidated basis.

And when you -- when you break it down among your segments, it seems to derive primarily from Dominion Energy and to a lesser extent from Dominion E&P.

I was wondering what that related to?

Yeah, Hugh.

At this point, what we -- at this stage of the quarter, we really do this call to cover the business areas and results from, you know, an operations and a driver standpoint.

Those kinds of explanations are actually being developed right now in preparation for the 10-Q and we're not prepared to answer that on this call.

If we could get back with you on that, if it's not developed fully in the 10-Q, we'd be happy to do that.

All right.

Thanks.

Appreciate it.

Thank you.

Thank you.

Our next question is coming from Paul Patterson of Glenrock Associates.

Please go ahead.

Good morning, guys.

Can you hear me?

Yeah, Paul, we can hear you.

I wanted to touch base with you on -- going forward in 2005 and what have you.

You mentioned that you were hedged 62% without the -- without the -- the diesel and gas barge generation that you have.

And what I was wondering is what is the price of gas that you guys are using in your 2005 estimate, your market price that you guys are assuming for -- for natural gas?

I believe for next year we are using 450 in our current model.

Okay.

So that hasn't changed.

No.

And then what I was wondering was in terms of the -- the dividend, I just wanted to clarify something here.

You guys mentioned that you guys were sort of in the mid-50s now for '04 and that you could go down into the high 40s.

And I was wondering, I just wanted to clarify something here.

Should we expect the dividend to pretty much keep track with earnings?

Or -- or, I mean, what exactly is the payout ratio goal, if you follow me?

We don't really have a goal.

It's a little more sensitive than just concrete, like we would continue to pay X percent out.

I think it -- we feel very comfortable at an 8 cent per year annual increase in our 5-year plan.

Of course, the Board has the discretion to alter that.

And, at that -- at that rate, compared to the earnings growth that we have, it's certainly, you know, not the lion's share of our earnings growth.

So we've got some room.

Our credit metrics are improving, and we'd like to see them get a little stronger.

I think we've got some flexibility and some upside movement to that dividend.

But, you know, rather than saying that, I think that we -- we want to be somewhat conservative and say that we think that 8 cents per year is certainly in the cards.

And, you know, we wouldn't have said that had we thought we could do that one time or we didn't think that we could continue to grow 5% to 7%.

So the numbers that we have on our cash flow, et cetera, going forward include this extra dividend and they include -- include our 5% to 7% growth.

So I hope that kind of answers your question.

We don't really -- we didn't adopt -- we didn't discuss with the finance committee a payout ratio that we had to -- to hit or that we wanted to hit.

Okay.

Can you give us a flavor, again, just to jump back to the hedged amount of gas and oil, what the -- what the price per MMBtu or decatherm, or whatever, that you've hedged in for now at 2005, 2006?

I believe it's on a schedule.

It is on the site, Paul.

It is on the site?

I'm just going to find it.

Okay, I'll look there.

Thanks a lot, guys.

Thank you.

Thank you.

Our next question is coming from Paul Ridzon of Key McDonald.

Please go ahead.

Can you just give more detail about the positions that you had to exit and kind of --?

They were in the -- they were primarily in our electric book and they were summer positions.

And there -- we closed them all down in May.

(technical difficulty) that decision.

Pardon me?

What was the dynamics that you kind of cited for -- for why they failed and what drove your decision to exit?

We thought that there -- that fundamentals were not prevailing in the marketplace, and that with the Iraq war and concerns about oil prices and things like that, the fundamentals were, as I said, were not prevailing.

And we became uncomfortable with the positions, so we closed them out.

And not at a large loss.

We just don't -- we don't feel comfortable in that world and we're -- we're not going to participate in it.

How should we think about the -- the trading going forward?

Are you just not going to put those positions on anymore, or just be a lot more selective?

I think that we will -- as I said, we'll continue with some proprietary trading.

And I don't want to get into exactly all the strategies and tactics we use with our trading partners.

We will continue to do proprietary trading in the selected categories that we have, which are all associated with our core businesses.

And we're going to produce earnings at a lower level, but a very -- at a sustainable level than we thought about in the past.

(technical difficulty) growth expectations, or are you saying there's going to be a step down?

I'm sorry?

I didn't hear you -- I didn't understand your question.

Would you say you're more tempering your growth expectations going forward?

Or are -- we could see a step down from historical levels?

No.

I think you'll see a flat -- we project -- the Clearinghouse has traditionally the last few years earned between $40 and $60 million.

And that's where we expect to stay.

So flat into the future.

Okay.

Thank you very much.

5 to 7% earnings growth comes from the other business units.

Thank you.

Thanks, Paul.

Thank you.

Our next question is coming from David Schanzer of Janney Montgomery Scott.

Please go ahead.

Yes, hi, good morning.

Hey, Dave.

Question -- most of my questions have been answered, but there's a question about Cove Point.

You were talking about the capacity increase going up through '08.

Is there a schedule of how that capacity's being added on?

Is it kind of arithmetic or is it a geometric increase with -- with most of it early on or --?

Yeah.

It's -- I'm sorry, this is Paul Koonce with Dominion Energy.

The capacity expansion really will follow an application at the FERC where they will grant the certificate to construct, and then -- which we expect will begin in the late mid-'06 time frame.

And then the expansion itself will go commercial in late 2008 as -- as one component.

Okay.

So it's -- it's kind of back loaded.

I guess -- there's a number of activities, uh, I'm referring at Cove Point.

Let me just step you through the time sequence.

We brought the facility back into commercial operation last August.

But the initial reactivation still had some expansion components to it.

We will bring on the last of the initial recommissioning, which is the fifth tank, in December of this year.

That will bring the storage capacity up to a little over 7 Bcf of on-site storage.

So at the -- at December of this year, we will complete the expansion of the initial recommissioning.

The schedule [ph] agreement is essentially a doubling beyond that point, and that's the capacity that will come into service late '08.

Okay.

And what -- what kind of environmental objections, if any, do you expect to be raised during this time period?

Well, we have been working very closely with the Calvert County community, the Heritage Trust and the Sierra Club.

And we believe that we've got good support from those agencies, principally because we've got a 1,000-acre footprint and we're really adding onto an existing facility.

And so we're not really encroaching on any of the environmentally sensitive areas beyond what property we already own.

Okay.

Great.

Thanks.

Thank you.

Our next question is coming from Scott Fuller of Morgan Stanley.

Please go ahead.

Good morning.

Hi, Scott.

Hi, Tom.

I had 1 or 2 questions about E&P and then 1 about Clearinghouse.

Regarding your CapEx budget, we were noticing that your recent presentation to this presentation looks like you all have increased your CapEx plan by about 280 in '04 and 160 in '05 over previous guidance.

In regard to where the money's being spent, it looks like most of it this year’s in E&P and about half next year's in E&P.

So I was hoping you all could color in specifically where you plan on investing that money.

Which types of projects?

What parts of North America, perhaps?

And does that change your growth rate expectations on earnings of that 5 to 7% growth rate?

Duane, do you want to answer that, at least the first part?

I'll answer the first half of it, Scott.

You're right;

I think about 2/3 of the first VPP we're essentially putting back in the ground.

And it's fairly close to across the board.

The vast majority of it is going back into our gas factories onshore and the exploitation.

There has been a slight increase offshore, but really across all the business units as we saw additional opportunities under this pricing environment.

Tom, I'll let you handle what the total earnings -- it's not significant enough that I don't think it would change the total forecast of earnings for Dominion.

No, I don't think it does.

I think what we've done here is that we have sold some production forward in order to create more funds for E&P to use in the current period.

And part of that is because of opportunities that we would like to exploit sooner than later, bring that production on sooner, find the reserves sooner.

The other is to recognize some increased costs to actually, you know, drill.

So this is kind of the way that we've looked at the E&P business, is that if we -- if we originally had a budget, I think, of about 925 million for the year, Duane saw some opportunities and some rising costs.

And we said fine, you can spend more than 915 if you create money within your portfolio to fund it.

And as you can see, we have raised the E&P number for this year and next, but it's not to the same level that we just sold the last VPP.

So we've actually come out where we've reduced our net -- our net CapEx as a result.

Okay.

And then, Duane, is this mostly production where it looks like the lead time between drilling and -- and then actually -- you know, when you actually spud the well and you're actually producing from those wells, is that a pretty short lead time on these new projects?

I mean it varies across the board.

Obviously, Sonora is a week, and some of the things in South Texas or South Louisiana may be 6 months.

But we weren't really driven by, you know, exactly the shortest hookup versus the opportunity base that we saw in each business unit.

Okay.

And then I have 1 question on Clearinghouse, if I could.

Just in general, you were talking about Iraq and then you were talking about the loss (ph) on a power position.

I guess I was trying to understand.

Is there a certain amount of oil that was being traded in the quarter?

And is that a -- is that a --

No.

-- position that you all will not --

No.

No.

It wasn't oil.

It was electric positions.

And they were being -- those positions were being affected in a non-fundamental way by what was going on in the world markets.

Just because of volatility, I would presume and not --

Yeah.

Okay, Tom, that's helpful.

And then can you all provide your maximum 5-day VAR for the second quarter?

I don't know if that's in the package or --

Yeah.

We publish in the -- this is Paul Koonce again.

We publish in our 10-K our risk-control metrics and we have a VAR there that is a daily VAR.

We don't have a five-day VAR.

And that daily VAR, we managed to -- it is about 13.5 million.

And throughout the second quarter and throughout the first half of the year, we've really not run beyond our internal control metrics.

So all that has really remained in place and been respected and I think is a measure of sort of the level of activity we're talking about.

Okay.

And I -- and I have to say as the CFO that looking back away from it, because I'm not in Paul's group or in operating unit, what we have is a situation where we could have gone on with these positions and might well have come out whole on them because it was a position for the summer.

But we decided that since the markets weren't trading on a basic supply and demand anymore, that you couldn't count on supply and demand ever really determining the price.

And when you see that, if you're -- if your theory is that you chart supply and demand and come to a position, but that no longer counts, the situation was that we said, well, let's go ahead and take a small loss in order to not gamble because we're not gamblers.

And it really doesn't change Dominion's EPS particularly.

And so we're not home-run hitters.

I think it shows the -- we probably could have come out okay, but we decided to not take that risk.

Okay.

All right.

That's it.

Thank you.

Thank you.

Thank you.

Our next question is coming from Leslie Rich of Columbia Management Group.

Please go ahead.

Could you update us on the closing of the Kewaunee nuclear acquisition.

We expect a ruling from the Wisconsin Public Service Commission in early September.

That is too close to the scheduled refueling outage at Kewaunee, in which the vessel head will be replaced, for us to be comfortable taking it over with just a few weeks of operation.

So we will wait.

Assuming that Wisconsin Utility Commission rules in favor of the transfer, we will wait until after that refueling outage, which ought to lead to a closing very late in the year -- December.

Okay.

And then in terms of Clearinghouse, I know you said 40 to 60 million is your sort of ongoing normalized annual earnings contribution.

And this year you expect it to be lower, in the 20 to 40 million range.

Could you tell us what you've earned year-to-date at Clearinghouse?

Yeah.

Year-to-date, the -- the earnings that we've reported is a loss of about $25 million net income.

And that loss is made up of about $9 million of trading loss and the balance being the fixed costs associated with the salaries and the -- and the office building and the like.

So those are the 2 components and those are the results year-to-date.

So your assumption, then, is that you'll --

Yeah.

-- make 60 million in the second half?

Yes.

And that's really driven in large part, 1, lower costs as a result of the remissioning work that we've -- we've done. 2, we can see in the transactions that we have on the books, accrual earnings coming back through in coal, gas, oil, electricity.

And then, 3, you know, there will be some third-party activity involved in producing those earnings.

But it's our view, as we look out, based on what we know about our cost structure, what we know about accrual earnings and what we know about our trading climate, that we'll be able to produce in that range.

Okay.

Thank you.

Thanks, Leslie.

Thank you.

Our next question is coming from Margaret Jones of ABN Amro.

Please go ahead.

Could you update us on the situation with S&P in resolving the negative outlook?

Yes.

This is Scott Hetzer.

Our annual review would take place in the fourth quarter.

Really have not had a lot of discussion with them about whether or not they're inclined to remove that.

I think they want to see further improvement in debt-to-cap.

We are very pleased that we've dropped debt-to-cap by 200 basis points this quarter, and our other ratios look very strong and are improving.

We are looking at FFO to interest coverage of a very strong 4.8 times for this year.

Some of that is nonrecurring, a lot of that is from deferred tax help (ph).

But we really have very strong credit metrics as of June 30 and project them to be stronger at the end of the year.

So we're going to make whatever arguments we can with them, but we don't -- we can't comment on whether or not they're looking at lifting that.

Scott, would you see the same improving trend with whatever restatements S&P is likely to make?

You mean in terms of their adjustments?

Right, uh-huh.

That's a good question.

The numbers I've cited are looking at it with just a couple of adjustments, that's the -- treating the trust preferreds, taking them out of debt and putting them into equity and treating the mandatory converts as both debt and equity.

And S&P, of course we all know, makes many adjustments.

This would be a similar improvement.

I don't have a number in front of me.

It may not be a full 200 basis points, but the trend would be the same.

Okay.

Great.

Thank you very much.

Uh-huh.

Thank you, Margaret.

Thank you.

Our next question is coming from Brian Chin (ph) of Fossil Capital (ph).

Please go ahead.

Hi, good morning.

Just to clarify on the dividends, you -- so going forward, you are thinking even past '05, that it would be 8 cents increase per year for -- you said the 5-year plan going forward?

Yes.

I mean, based into our 5-year plan we've built in that type of -- of dividend increase in our models.

Okay.

So '06 you're looking at another 8 cents and then '07 as well.

Right.

We want to leave our Directors some discretion, but if we do -- if we hit the targets we think we will, we will think it is a pretty easy decision to make.

Okay.

Thank you very much.

Thank you.

Our next question is coming from Ted Olshinski from Scotia Capital.

Please go ahead.

Yes, good morning.

Just a couple of follow ups on the balance sheet and I think you might have answered it.

The -- you know, according to your preliminary statements here for the end of the quarter, it looks like your debt to capital is 61.5%.

Am I to understand that the difference between that and the mid-50s that you cited in your presentation is all related to the treatment of trust preferreds?

Yes, Ted, it's trust preferreds and the adjustments that we make for the mandatory converts -- (multiple speakers)

Okay.

-- where we add them back.

We keep them in as debt, but we add them back as equity as well.

Okay.

And secondly, I was looking at the preliminary statement of the cash flows.

I noticed that you had a $522 million reimbursement for a lease under -- for a project under construction.

Could you remind us which project that is that's under construction?

And, you know, could you talk a little bit about how you expect S&P to treat that -- that lease?

Yes.

That was the reimbursement for the Fairless facility where we were funding the construction of it and then the lease financing was completed in April.

The first tranche of debt was sold -- lease debt was sold and we took in approximately 560 million and reduced commercial paper as a result.

The second tranche will come in in August and is a -- is a -- I believe about 240 million that's still coming back to us.

And we will use that to reduce commercial paper as well.

As far as how S&P will treat it, they will make their normal adjustments, like they do for traditional leases.

And -- and as -- our estimate is that they will make an adjustment of some 350 million to the debt number – (multiple speakers)

Okay.

-- for that plan.

By the way, those projects -- that plan is in service.

Right.

Okay.

All right.

And aside from the, you know, the money coming in in August, are there any other initiatives that you have underway that would potentially reduce the amount of debt that you have on your balance sheet?

Well, we have the free cash flow for the second half of this year, which is -- which is still looking very good.

And some of that could find its way to reduce debt.

A big driver that we have in the second half of the year are the -- the first mandatory convert of 413 million does convert to equity, and that will drive it down even further.

Our projection for the end of the year is just under 54%.

Okay.

And what is your estimate for free cash flow for the second half of the year?

Well, we are -- we -- we're at 530 -- 533 for the first half, we're projecting 725 for the --

I think that's --

Yeah, it’s about 200 million but we're projecting 725 for the full year, including -- including the benefit of the VPP.

Okay.

All right.

Thank you very much.

Thank you.

Our next question is coming from Nathan Judge of Atlantic Equities.

Please go ahead.

Hello.

Could you give us an update on your efforts to issue stock with -- related to the Kewaunee plant now that I think you have decided to hold off on the Kewaunee plant purchase?

Yes.

We have been saying that we expected to issue about 110 million.

That was what was in the plan for the Kewaunee facility.

We have approved a couple of other acquisitions, the non-utility-generating contracts.

And they will require some additional equity as well.

The total equity need between the NUGS and Kewaunee is about 350 million.

We have taken in an incremental 200 million in equity ahead of our plan for this year from both the DRIP and the direct purchases running ahead of schedule and from management's exercises of stock options.

And so we have a net need of 150, not materially different from the 110 that we did have, and that's a pretty small equity offering.

We don't have any specific plans on how or when we would pull the trigger on that.

Could you go into further thought process behind acquisitions as they stand today?

In particular, how you look at E&P acquisitions now?

Well, I'm not sure who wants to answer that one.

As the CFO, all of the acquisitions that we'd look at basically have to clear all these hurdles that -- neatly (ph) accretive and good cash return on invested capital, and also that -- they have the FFO, the interest coverage, the FFO to capital.

And I would think right now, you know, it might be difficult unless we went originally and hedged some gas production to make all those things come true.

But at the same time, you know, if we did that, if we saw something that would improve our portfolio, we would try to use the same discipline that we did with the VPP and increasing CapEx, which would mean that we'd probably sell part of our operation because we'd be buying and selling into a pretty high price regime.

So we would try to balance those things out.

So I think that would be more probable.

So we wouldn't say we wouldn't, but we think the net would be that our EPP asset size would be almost the same it would be after acquisitions -- an acquisition, it would be a superior property in terms of operations than one we would sell.

With regard to the -- thanks very much for that.

Could you just give us a little bit of an update on this Clearinghouse?

I'm not quite sure (ph) I followed with regard to the Houston and Calgary offices.

You said you'd taken down 30 people.

I guess that's primarily out of those offices.

What is your staff count now on Clearinghouse?

Paul, can you answer --?

Yeah.

Let me answer.

First off, the Clearinghouse, in terms of front office commercial staffing, is about 150.

And then the mid and back office that supports those activities number about another 150.

But when we talk about the Clearinghouse, you have to look at what are the commercial activities that were embedded in Dominion and C&G prior to the merger.

So the biggest tranche of the 300 total are really the co-location of commercial functions that exist whether you have the Clearinghouse or not, be it the LDC buying Group, selling the merchant generation capacity.

The Calgary/Houston offices were very small.

I think they numbered in Calgary about a dozen and in Houston about half a dozen.

So of the total 32 full-time employees who were affected by the remissioning, you know, about half of those numbers came from Calgary and Houston.

The rest came from initiatives that we had kicked off in -- in Richmond that we're suspending.

So, you know, you have to -- we always have to kind of think of the total numbers.

So what would be the total number we would have, whether we had a Clearinghouse or not, and that really is the lion's share of the 300 people.

Okay.

So the strategy now is really back to understanding what your proprietary positions are putting on, basically due to your natural advantages that you have in the Northeast.

So you're really pulling back from your efforts that you put in, or your prop trading that you put in these other offices?

Do I understand this correctly, or --?

Yeah.

Let me -- let me just comment a second on the Clearinghouse.

What we're trying to do is not so much describe sort of what went wrong at the Clearinghouse in the second quarter, but to describe sort of what we see we do well going forward.

And we do engage in proprietary trading in the Maine to Maine footprint to support the marketing of our electric generation, our E&P and to provide liquidity support for our LDC buying functions.

Those activities we're going to continue.

We need to continue those so that the markets can't forecast what part of the transaction are we bringing to the market, are we always the buyer or always the seller?

So we need to keep a level of deal flow in the marketplace so that people can't predict what we're doing.

And, really, what we had looked at in the Calgary and the Houston operations was something that's not unlike what we do in Appalachia.

And Appalachia, which is in MAIN-to-Maine, we are a large aggregator of small independent producers, gas.

With the retracement of other energy merchants from the marketplace over the past 2 years, we thought that it opened up an opportunity to engage in similar aggregation activities like we have in Appalachia.

But it really was not material in terms of earnings.

And so we decided that it was probably more of a distraction as an earnings driver and so we've exited that -- that activity.

That is very helpful.

Thank you very much for that.

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

Mr. Chewning, do you have any closing remarks?

Thank you very much for joining us this morning, and we look forward to having a good third quarter and seeing you again in October.

And we would also encourage any of you who can to make it to our analyst meeting on September 14th at the Waldorf where we will concentrate our efforts on E&P division.

Thank you very much.

Thank you.

That does conclude today's teleconference.

You may disconnect your lines at this time, and have a wonderful day.