道明尼資源 (D) 2004 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to your Dominion third-quarter earnings release conference call.

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 is now my pleasure to turn the floor over to your host, Tom Chewning.

Sir, the floor is yours.

Thank you.

Good morning and thanks for joining us for our third-quarter 2004 earnings conference call.

Joining me this morning are Tom Capps, our CEO;

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

Today we will present the usual cautionary language upfront and then cover particular areas of interest related to our results, as well as the views 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 of analysts and investors.

Operating earnings is a non-GAAP measure.

We define operating earnings as reported earnings or GAAP 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 Dominion Board of Directors as well as for the company's annual 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 I will review our third-quarter 2004 operating results, discuss items excluded from operating earnings, explain how we capture cash and earnings that have been reported as FAS 133 gains in our E&P segment.

Provide the current status of commodity hedging for 2005, 2006, and 2007 and lay out a road map of our fourth quarter and the revised 2004 guidance and beyond.

Tom Farrell will provide an operational view of the quarter and give updates on several significant items, including the impact of Hurricane Ivan on our Gulf of Mexico operation.

And Tom Capps will reflect on Dominion's 2004 results.

First for earnings.

Dominion posted operating earnings of $1.21 per share in the third quarter of 2004, 4 cents less per share than the low end of the quarterly guidance range of $1.25 to $1.35 per share.

On a GAAP basis, we reported net income of about $1.02 per share in the third quarter of 2004 compared to a net loss of 79 cents per share in the third quarter of 2003.

Three negative factors reduced operating earnings for the third quarter.

Delayed natural gas of oil production caused by damage from Hurricane Ivan cost us 5 cents per share.

Of this amount, approximately 2 cents per share should be recovered in the fourth quarter when our insurance claims for the period from September 26th through September 30th was submitted.

Net weather variance was negative three cents per share.

Lost income due to milder quarterly weather was five cents per share, but we used two cents per share less fuel than what we would have consumed under normal weather conditions.

There was a five cents per share negative mark-to-market impact related to hedge ineffectiveness at the Clearinghouse on certain trading activities, including natural gas storage and transportation division.

We will recover these earnings as contracts settle in the fourth quarter of this year.

Adjusting operating earnings of $1.21 per share by these additional 13 cents per share would result in pro forma earnings of $1.34 per share for the quarter, near the upper end of our expectations.

Dominion E&P has had a 6 cents per share gain from mark-to-market of ineffective hedges under FAS 133 in the third quarter.

The company actually monetized the value of the options along with an additional 14 cents per share of option gains recorded in the first and second quarters.

I will elaborate later on the process that created and captured these earnings.

Offsetting this 6 cents per share option gain was a disappointing performance of the Clearinghouse which produced 12 cents per share less than we had expected.

The balance sheet and other credit methods ended the quarter on solid ground.

Our adjusted ratio of debt to total capitalization is essentially unchanged at 54.9%, and we are on target for further improvements through the end of the year.

For the 12 months ended September 30th, funds from operations covered our interest expense by 4.3 times, and this ratio's expected to be 4.4 times at year-end 2004.

Free cash flow for the nine months ending September 30th was $727 million, including the cash impact of our second VPP transaction.

And available liquidity was $1.8 billion at quarter end.

As I mentioned earlier, details of items excluded from operating earnings are included in our earnings release and can also be found on our website.

However, one item related to Hurricane Ivan once discussion on the call.

As described by FAS 133, we are required to dedesignate hedges for those volumes of future production that are no longer expected to occur at the time provided in their original forecast.

In other words, they no longer qualify for hedge treatment.

Certain Gulf of Mexico productions delayed by Hurricane Ivan primarily production expected from Devils Tower was previously effectively hedged until September the 14th, the mark-to-market impact of those contracts was accounted for in the balance sheet through accumulated other comprehensive income or AOCI.

As a result, we designated those hedges effected -- we dedesignated those hedges effective September 14th.

The after-tax effects results from the dedesignation of these hedges was $61 million.

The $61 million is excluded from third-quarter operating earnings and include the amounts we classified from AOCI to income as of September 14th, and the change in value of the dedesignated contract in September the15th through September the 30th.

We've been working with our insurance carriers to establish a process for expedited processing, to facilitate recovery of lost production revenue.

We expect to recognize the majority of the business insurance recoveries related to this delayed production in approximately the same time frame that we expected the delayed volumes to be produced.

The business interruption coverage will be based on each commodities stock price just as if the production were not delayed.

The important point to remember is that over time, the economics of the delayed production will be the same as if business interruption never occurred.

For the physical production is sold into the market, but we realize a recovery under a business interruption insurance claim, we will over time recognize revenue based on the market price of the commodity, settle our hedge contract, redesignate or otherwise, and realize the average price contemplated when the hedges were put into play.

What did we get in the third quarter of '04 compared to what we expected?

For the first time, we've included on our website a reconciliation of our quarter actual results compared to the midpoint of our quarterly guidance.

In addition to the variances I have previously mentioned, you will see that we underestimated fuel expenses in Virginia exclusive of the weather impact by two cents per share, due to higher pricing of fuel consumed.

Our E&P division (technical difficulty) .8 (ph) cents a share above forecast excluding the impact of Hurricane Ivan.

This cause of variance was primarily attributed to higher commodity prices on unhedge production.

Now, turning to FAS 133 gains at E&P.

For the first two quarters, Dominion reported cumulative after-tax gain of 14 cents per share in FAS 133 mark-to-market gain in the E&P reporting segment.

As you have just heard we recorded another cents per share from the FAS 133 at E&P for the third quarter.

These gains were recorded as a reduction to E&P O&M expense which is the GAAP convention Dominion has followed for several years.

For the year 2003, this FAS 133 calculation actually increased O&M at E&P by $5.6 million or put another way, reduced Dominion's after-tax earnings by one cents per share.

Specifically in 2004, this mark-to-market impact arose mainly from call options Dominion Clearinghouse acquired in order to either protect the company from further margin calls on oil hedges or alternatively, enabled us to participate in any upward movement in oil futures markets during the year.

In the third quarter, Dominion exercised these options and reported to lock in 20 cents per share on both the cash and book basis.

Dominion views this option gain as a part of its corporate market risk function.

Our Clearinghouse recommended and executed purchase of these options.

Rather than treating these gains as a reduction of E&P, O&M expense, as required by GAAP, these option gains would be more appropriately contrasted as an offset positions taken in the Clearinghouse electric trading book that we have recognized 16 cents per share of losses through the first three quarters of 2004.

Before I update Dominion's commodity hedging division and provide fourth quarter guidance, let me ask Tom Farrell to cover significant operational items.

Good morning.

Dominion's operations continue at a high level.

I will discuss each segment and then give you an update on pending transactions as well as the status of our entry into PJM.

Turning first to Dominion Delivery.

We are on track to add by year-end about 18,000 gross gas customers in Ohio, Pennsylvania and West Virginia along with about 55,000 electric customers in Virginia and North Carolina.

These are slightly above the levels we have experienced in the last several years.

We have seen continued strong growth in tariff revenues in the electric service territories, which enhances earnings at both Delivery and Generation.

This year's increases, of course, will carry into next year.

We escaped major impacts from hurricanes in Virginia this year, but Ivan certainly affected our E&P operations, which I will discuss further in a minute.

Dominion Generation continues with excellent operations across its entire fleet.

Our Virginia nuclear units, as well as Millstone, have a less than 1% forced outage rate year to date.

Record refueling outages were achieved at both (technical difficulty) units.

The fleet-wide year-to-date capacity factor is just under 93%, outstanding performance.

In our Fossil Fleet, the Virginia units have achieved a 95% peak season availability rate this year and have the highest capacity factors in the last three years.

Our State Line and Kincaid units have set records for consecutive day runs.

Fairless Works, which became operational only on July 1st, has run often and extremely well.

Fuel management under our frozen fuel clause remains consistent with our expectations and is explained in detail at our conferences in May and in September.

As I said at our September conference, we understand how the fuel works, and next year when we have our open E&P positions, we will be able to offset the impact on fuel costs which we were unable to do this year.

With respect to NUG mitigation, we have announced three transactions so far in 2004 and continue to work on several others.

We have made significant progress and - - which will largely be reflected in positively in 2005 earnings.

Dominion Energy operations also continue to perform at or above expectations, except at the Clearinghouse, which I will cover in some detail in a minute.

Gas and electric transmission facilities have achieved 100% availability through the first three quarters.

As has our Cove Point facility.

The fifth tank at Cove Point, which will increase our L&G storage capacity by 50%, should become commercial in early December, about three months early.

Cove Point continues to be the number 1 import destination in the United States, having received 20 ships, carrying 23 BCF during the third quarter.

Our pipeline operations were recently ranked number one in overall performance based on measures of financial integrity, operational efficiency and profitability in the mid-Atlantic and northeast regions and ranked number two nationally on the same metrics by the Fosters Financial Report.

We are rated number 1 in the United States in revenue per deck cotherm (ph) of throughput and in overhead per deck cotherm of throughput.

Turning to our Electric Transmission Access our NERC (ph) electric control area audit recently completed, rated Dominion best in class.

Following the second quarter, we took a hard look at the Clearinghouse and refocused inward on asset management.

At that time, we trimmed our 2004 earnings expectations for the Clearinghouse by some $20 million and looked for a contribution of 15 to 20 million in the third quarter in order to provide full-year earnings between 20 and 40 million.

We have continued to focus our attention on the Clearinghouse, but obviously our third quarter loss of $21 million did not meet expectations.

Incorporated in our full-year 2004 guidance, given to you this morning by Tom Chewning, is a fourth quarter earnings contribution from the Clearinghouse of 30 to $35 million.

That compares to a loss last year of about 29.

Now, more than 30 of the 30 to 35, I want to repeat that.

More than 30 of the 30 to $35 million of projected fourth quarter earnings are going to come from accrual or other non-proprietary trading sources of income. $10 million is expected to come from proprietary trading and fourth quarter fixed costs are projected to be about $10 million after tax.

These figures support a fourth quarter earnings range per deck for the Clearinghouse of 30 to $35 million for a year-end loss of 12 or 13 million.

While overall the Clearinghouse will bring in positive revenues, it has not produced enough positive gross margin to cover its fixed costs, which are about $60 million pre-tax on an annual basis.

Since its initiation, Dominion's proprietary trading has been based on thorough fundamental analysis of the markets in which we do business and in commodities we know extremely well.

No position has been put in place that was not carefully thought through by our trading team.

Our fundamental analysis is as good as anybody's in the business and I will put our people up against anybody else's.

The results prior to this year have been excellent and produce a lot of value for Dominion shareholders.

Our trading philosophy in 2004 has been no different and no less carefully analyzed.

Over the course of the year, it has become obvious that these markets are no longer trading on fundamentals.

It is not clear to us when these markets will return to normalcy.

As Julian Robertson said when he closed the Tiger fund in 2000, quote, "As you have heard me say on many occasions, the key to Tiger's success over the years has been a steady commitment to buying the best stocks and shorting the worst.

In a rational environment, this strategy functions well.

But in an irrational market, where earnings and price considerations take a back seat to mouse clicks and momentum, such logic, as we have learned, does not count for much" Unquote.

For the same reason, we are re-examining every aspect of the Clearinghouse and we are closely examining exiting proprietary or speculative trading.

That decision will be made during the course of the fourth quarter.

Whatever decision we make regarding proprietary trading, the Clearinghouse will continue to be a vital component of Dominion with its primary focus remaining on maximizing the Dominion integrated model.

Our E&P operations are producing at company record levels.

Through the third quarter, we produced 355 BCFE, as compared to 341 BCFE through three quarters last year.

The 355 includes the VPP volumes and transmission volumes.

We would have actually produced 360 BCFE if not for Hurricane Ivan.

Lifting costs have risen to about 99 cents in MCFE including transportation, which reflects rising costs throughout the industry, but we believe this number reflects well when compared to our peers.

Before I give a report on the operational impacts of Ivan, let me say a word about our Canadian operations.

As you know, we are - - we are longer in gas production than is necessary for our integrated model.

We are constantly reviewing all of our assets as to what best fits our overall portfolio needs.

With that in mind, we have decided to offer our British Columbia reserves for sale.

Assets have been selling at excellent premiums in Canada, and with recent tax changes we have the flexibility to repatriate any gains at a more effective tax rate.

Proceeds will be used to pay down debt, forego the issuance of equity for other transactions or NUG write downs or a combination of both.

We will continue to assess our other assets as well, although we presently have no plans to exit Alberta.

Tom Chewning has covered Ivan's earnings impact for you.

We have previously announced that Ivan caused some damage to Devils Tower spar itself and seriously damaged the well completion rate.

We can reaffirm today that the three wells at Devils Tower producing prior to Ivan will be back in full operation by November 15, a fourth well will also be completed within that time.

The remaining four wells will be finished by the middle of next year.

Neptune's gas productions - - production resumed October 9.

Our main past assets and Neptune's oil volumes are ready to produce but are waiting on downstream repairs.

Front Runner was unaffected and should produce first oil by mid-next month.

All in all, we expect Ivan to delay production of just under 22 BCFE this year.

Earnings impacts are minimal, as Tom Chewning has explained, because of our insurance coverage.

Let me turn to a couple of pending transactions.

First, KaHuany (ph).

KaHuany is presently in its refueling outage and is replacing its vessel head.

We are hopeful the Wisconsin commission will take the matter up later this month.

We are expecting to close by the middle of December, after the outage has been completed.

With respect to the USGen assets in New England, the bankruptcy court has entered an order which provides for any competing bids to be submitted by November 8, with an auction, if any, to be held on November 15.

Let me turn now and conclude with PJM.

Dominion is pleased with receipt of the October 5 FERC order.

It completes one of the regulatory approvals that is required in order to integrate into PJM.

We are now focusing on obtaining the remaining approvals from Virginia and North Carolina.

Importantly, the FERC order upheld our legal analysis with respect to the deferral of RTO start-up costs and PJM administrative fees for Virginia jurisdictional retail customers throughout the Virginia rate cap period.

On Tuesday, October 12, Dominion, Virginia power and other stakeholders submitted to the SEC in Virginia a partial settlement for consideration and approval as a part of our overall application to join PJM.

The case will be heard on October 25th to address any remaining issues.

We expect to be integrated into PJM on the latter on the 1st of December, or the date on which regulatory approvals are received.

Thank you, Tom, that's all I have.

Thanks, Tom.

Now let me update the commodity hedging percentages of - - as of October the 19th.

The detail hedging exhibit can be found on our website.

Approximately 93% of our Generation capacity is hedged in 2004, 93% in 2005, and 89% in 2006.

Using traditional means, including swap, about 82% of our remaining 2004 oil and gas production is hedged. 67% of 2005, 57% of 2006, and 42% of 2007.

Approximately 100% of 2005, 68% of 2006, and 73% of 2007 coal needs have been contracted.

When we add the equivalent amount of gas needed to supply our Fossil Generating Fleet and Dominion Retail supply volumes, we are 100% hedged in 2004 and about 95% in 2005, 91% in 2006, and 65% in 2007.

As a result of recent hedging, our consolidated earnings per share sensitivity to changes in natural gas prices has changed dramatically from that presented in our New York analyst meeting on May the 6th.

For each dollar increase in natural gas prices, earnings per share would increase 7 - - 7 cents per share in 2005, 15 cents in 2006, and 48 cents in 2007.

For each dollar decrease in natural gas prices, earnings per share would decrease 7 cents per share in 2005, 13 cents per share in 2006, and 48 cents per share in 2007.

As a cautionary note, please recall that the 2007 sensitivity only reflects one half year of hedging Virginia fuel since the fuel rate will be reset in July of 2007.

These sensitivities include a direct effect on natural gas and oil production as well as correlated effects on coal expenses, electricity margins on unhedged output at Millstone and our unregulated natural gas-fired plant.

Revised sensitivities are found in the exhibit on our website, you will also be able to see how dramatically they've reduced this if you look at our May 6th presentation, at the sensitivity slide presented on that date.

Factors reducing our consolidated sensitivity or additional hedges on natural gas and oil production, inclusion of the second volume metric production payment into the sensitivity model, locking in the upside collars on certain oil and natural gas options, increasing the amount of coal hedge for utility generation, and hedging additional output at Millstone.

Now, let's turn to fourth quarter earnings guidance.

Due to actual results in the third quarter, we have revised our full 2004 earnings guidance downward to $4.68 to $4.75 per share.

The revised guidance assumes 35 cents per share of unrecoverable Virginia fuel costs for the full year 2004.

As Tom Capps will comment more fully later, the company has performed up to or beyond our expectations as 19 - - as - - as 2004 began except for this unplanned fuel expense.

Our fourth quarter earnings guidance range is $1.29 to $1.36 per share.

A detailed reconciliation for the 84 cents per share recorded in the fourth quarter of 2003 can be found on our website.

The most significant positives (inaudible) are the assumption of normal weather, no outage schedule and Millstone Power Station, a profitable quarter anticipated by the Clearinghouse, and increased production and profit margins at E&P.

Dominion is now developing its 2005 operating budget for submission to the board of directors in December.

At this time, we are revising 2005 guidance downward to $5 to $5.20 per share due to reduction of 10 cents per share in earnings expected from the Clearinghouse.

Some of the major drivers for growth from 2004 to 2005 are: The acquisition of the KaHuany plant, increased E&P production and prices, Cove Point expansion, and a full year's affect of no (ph) buyout.

Not included in this guidance are the impact of newly signed corporate tax legislation, any further NUG mitigation, nova (ph) earnings that would be gained from the USGen power plant, until we become the owner of those assets.

Dominion will give specific update in 2005 guidance before year-end.

Now our CEO, Tom Capps, has his reflections on Dominion's 2004 and its future.

Tom?

Thanks, Tom and good morning.

I'd just like to make a brief comment.

Notwithstanding the other factors that the Tom's mentioned, the Clearinghouse, weather, the hurricane, mark-to-market accounting, the primary reason that we were un unable to make our original guidance of $4.80 to $5.00 is the frozen fuel factor.

We couldn't plan for it because we didn't know it was coming.

And when it came, we were hedged on gas to such an extent that we had little room to maneuver.

As a result, the frozen fuel cost should cost us 35 cents per share this year.

If you add back the 35 cents to the 4.68 to 4.75 Tom Chewning just gave you for the year, we would be earning 5.03 to 5.10, well above the original 4.80 to $5.00.

As to next year, that's an entirely new ball game.

The frozen fuel clause should be considered a chaperone for the frozen base rates.

Taken together, they are without a doubt good for our shareholders and good for our customers.

Would we agree all over again to a frozen fuel clause to have our base rates extended through 2010?

Oh, hell yes.

Thank you.

Thank you, Tom.

And now we'll be glad to take your questions.

Thank you.

The floor is now open for questions.

If you have a question, please press star, then one on your touch-tone telephone 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 hand set to provide optimum sound quality.

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

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

Please go ahead.

Good morning.

Hi, Dan.

First question if we can just spend a little more time on Clearinghouse, make sure we understand what's going on here.

Will we be better off, first of all, thinking about the trading book by netting the gains at E&P against the losses at Clearinghouse?

And are they taking it on the chin partly because of - -

Yeah.

Running the book at E&P?

Right.

Dan, you're exactly right.

I mean, the GAAP position is that we really had a choice because those were options on oil and gas production.

They either treat it as a revenue adjustment an O&M adjustment and a few years back we decided to treat it as an O&M adjustment and for the last couple years it's actually been negative marks and we've never mentioned it, they weren't that significant.

But there really - - it's a measure of options, value and a position that the Clearinghouse recommended to us, and it was their strategy, just like the electric book was their strategy.

And, in fact, those two positions, helped mitigate each other because the real run-up that we had in oil also impacted the power markets, and the electric book was - - was short for the summer, so in effect, you know, it should never be an E&P.

We've said this before, that the lifting costs, which Tom Farrell referred to this quarter of 99 cents is really more reflective than O&M when you include FAS 133.

I think what's also important, Dan, is that it's not a mark.

Both the electric book loss of 16 cents per share and this FAS 133 20 cent per share gain through th first nine months had been realized in the marketplace.

We paid cash in one sense and lost it and we got cash, and paid taxes in the other.

So it - - it really is more reflective of the - - of the overall company's Clearinghouse operations to include this 20 cent gain of FAS 133 there rather than in A&P.

And Tom Farrell might have other comments.

Nothing to add to that.

That's - - Dan, you're absolutely right.

Your - - we could have put it in either place, we chose several years ago to put it in E&P's O&M.

The overall wash for this year at Clearinghouse, how much of that is a function of, uh, the prop desk not being able to win on a fundamental perspective this year?

All of it.

So the entire - - or is it the loss plus what the - - the deposit accrual book would have been?

Or is it - -

Yeah.

Well, there have been, as we said in the - - in the press release, there has been some movements in mark-to-market space that we expect to come back in the third quarter on pieces of activities by the Clearinghouse and our storage and transportation position that don't necessarily count as proprietary or spot trading, open position type trading.

But the majority of the losses that have occurred are a result of positions we took - - four positions we took in electric, primarily in the electric book over the course of the year.

Okay.

I - - that's great.

Thank you.

Is Duane on by chance?

Yes.

Yes, I am, Dan.

Hey, Duane.

How are you doing?

I'm well, thank you.

A question.

With, uh, Ivan and the impact numbers, the volume delays you guys have done a pretty good job of explaining.

But how does this affect your exploration program and a number of pretty attractive deep-water wells that you guys have planned to drill, you know, this year going into next year?

There's no impact on our program.

We still expect to spend maybe 10% of our budget on exploration.

I mean, we're consistent with that model.

You know, we have already approved the subsea tiebacks for the fourth quarter of next year and are obviously working with the other partners at Atwater Valley for Synergy/Seno (ph) and Spiderman/Amazon.

Great.

Thank you guys.

Thank you.

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

Please go ahead.

Hi, Paul.

Hello.

I'm trying to understand, I think the timing in terms of what happened to Clearinghouse.

Because you guys, I think, were in New York in September, was there something that happened sort of late in September after the meeting that sort of affected the profitability of Clearinghouse?

Or wouldn't you have known pretty much at the time of the meeting that Clearinghouse was sort of not on track to do what - - what you would have - - had been hoping that it would do.

Uh, fair question.

Actually, Paul, very late in the - - two things happened - - two primary things happened.

There was a prior period adjustment that was recorded in the third quarter that we were unaware of in September of about $10 million and there was a mark-to-market move, I think it's 15 - - is it 15 million? $15 million that occurred because of the run-up in gas prices in the last two days of the month of September.

So that accounts for $25 million, which is where - - which we thought we were going to have in earnings coming into the - - coming out of the third quarter that in one case is because of prior period adjustments and in the other case is because it was pushed off into the fourth quarter and some of which will be pushed off into the first quarter of 2005.

And then I guess as it relates to next year, the assumptions that you're using for - - for the unhedged portion of gas, because you've got lots - - significant additional production coming on-line next year, is that still - - sort of in the mid fours?

And wouldn't some of the - - offset to Clearinghouse potentially be better commodity prices, that are currently in the forward markets?

Paul, if they were the only two items that are going to go up and down between now and year-end and our budget process, I'd say yes.

Because we were using, I believe, a 4.50 budget of unhedged oil and gas.

However it lots to probably 10 or 15 items that are different than - - as we get into the budgeting process than we felt - - even two months ago when we started it.

So we're not - - the only difference in our guidance to this point that we felt we should offer was that we're not going to expect the Clearinghouse, a Tom Capps - - as Tom Farrell said we are examining exiting proprietary trading.

And we have taken 10 cents a share, which was our expectation for the Clearinghouse in proprietary trading out at this point and, you know, we're still reviewing the decision but we thought it best to lower our expectation and that's why we took the 10 cents per share off.

As I've said before, we are in a budgeting process and it's tradition with Dominion, we present it to our board in December and there are lots of puts and takes, and we will give you very specific guidance with reconciliation to our previous ranges in December.

So then just to clarify, then.

It's not just Clearinghouse as being sort of the primary driver, there are other things that we're not seeing that are also impacting your expectations for next year?

Uh, yes.

I can't say any one real thing, it - - it's a matter of - - of Virginia fuel expected to be under-recovered more than what we thought, that sort of thing.

But, the budgeting process is not through.

We don't even have an approved budget at this point.

So we just felt that because we - - we had maybe pushed Clearinghouse too - - too far too hard in terms of earnings expectations and that we weren't going to build a budget based on that next year or any other year, that we back off at this point rather than just leave guidance at - - at 5.10 to 5.30.

Thank you.

Thank you.

Thank you.

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

Please go ahead.

Hi, Steve.

Yes, hi.

Just a - - in that discussion a little bit.

So in the '05 guidance now, how much of an income do you have from Clearinghouse?

We have about $20 million.

And it assumes that there is zero contribution from a speculative or proprietary trading.

Okay.

And the mark-to-market that hit at the end of the quarter, these are on positions that are kind of ineffectively hedged so that you - - it's something that - - that the money comes back to you as the positions close?

Or was this in the prop book?

No.

This was in - - it's the former, Steve.

Okay.

Yeah.

It's in our transportation - - transportation and storage positions.

So when the positions close, the money comes back to you.

Right.

It's just the positions got marked because they're not effective hedges.

Really to be more specific through the nine months, that number was actually around 22 million and we expect 19 million of - - of the profitability projection and guidance in fourth quarter for the Clearinghouse, we are anticipating that about $19 million of previously marked positions relating to this item will be below all.

Okay.

And on this - - these BC properties that you're planning to sell, what are their production levels and if in any way kind of what their - - what do they earn?

The rate is about 83 million a day.

And the specific contribution to earnings this year I'll have to defer to Duane or Dennis for that.

Are they there.

Yes, it would be about 25 to $30 million Tom.

Is there after-tax earnings?

Those are after-tax, that's correct.

And just the annual production?

It's - - its production would be about 28 to 32 Bs, somewhere in that range.

Steve, they're hopes that - - strictly these (technical difficulty) rates fall dramatically to about 5.7%, that was the - - the interest that's strong in Canada that we'll have an accretive or non-dilutive transaction.

Okay.

Okay.

And then just to - - one last thing on KaHuany.

You mentioned, you know, closing but you the Wisconsin commission.

I know there have been issues at the commission on - - on their comfort and really selling this think, I think.

So if you could just clarify how likely this - - this deal gets done?

We - - Steve, we have a very high level of confidence that it's going to be done.

There's been lots of discussion going on at the staff levels in Wisconsin.

It was delayed.

Their only reason it's been delayed this long is because one of the commissioners in Wisconsin resigned in the summertime and they had to get a new commissioner and that took some time and that commissioner had to get up to speed.

But there are two more dockets this month and we have every expectation that the matter will be taken up during the month of October.

We would expect to get an order in the - - by the middle of November.

And then close after the - - the unit is buttoned up and producing electricity.

Okay.

Thank you.

Thank you, Steve.

Thank you.

Our next question is coming from Greg Gordon of Smith Barney.

Please go ahead.

Hi, Greg.

Thanks, hi guys.

So, $20 million, that's net of tax numbers so you're basically assuming Clearinghouse is a five cent contributor give or take next year.

Is that - -?

I think that - -

That would be around five to six cents.

Great, great, terrific.

And you're not assuming any financial impact from the potential acquisition of the northeast assets in your new numbers, correct?

No.

We're not - - we're not including that, nor further NUG mitigation, nor - - it's been estimated, and this is very preliminary, that the company's tax bill under the new corporate tax rate would - - in '05 and '06 be $5 to $10 million less.

Which is not a big number, but we haven't included that either.

We're still refining that.

So there's no NUG mitigation in there at all or there's just an - - ( multiple speakers) assumed baseline level of NUG mitigation that you have the potential to - -

Right.

No further NUG mitigation from what we've currently announced.

And your - - did you have a second part of that?

Yeah.

I mean there's a certain level of NUG mitigation that you guys sort of assume as a baseline, at least you have historically.

You're saying that this number now sort of assumes no new incremental transactions are announced?

No new incremental NUG transactions are in the - - our $5 to $5.20.

Well, it seems to me, guys, you know, obviously the quarter was - - was not great, but it seems to me that this new earnings guidance is really scrubbed down to sort of a very achievable number based on the - - the more visible portions of your business, that you've taken a lot of the - - and pardon my expression, I'm sure you'll disagree with these, but taken a lot of the fluff out of your guidance for - - for '05.

You know, there's no NUG mitigation in there, there's no assumed acquisitions in there, there's very little trading assumed in there.

So this is a number that we should all things being equal have a much higher level of confidence in.

Well, yeah.

I don't disagree with anything but the word fluff.

But - - and I'll think of a better one and I'll write you later, Greg.

But I do think that - - you know, certainly a reliance on - - on repeatable earnings.

I mean, if you look at the 20 cents a share we achieved on FAS 133.

That's not repeatable.

But neither is the - - we aren't going to repeat 16 cents a share loss in proprietary trading in the electric book either.

So then you start looking around for other items that are varying and as Tom Capps has often said, the weather is the biggest thing.

About the only concern I have is - - is the way accounting develops.

We - - we have these dehedged volumes and once they dehedged after this quarter, it - - to the extent that those volumes are not recovered at year-end, they're considered still unhedged unless we take an action to hedge them further, so we could have a mark on that.

But to tend to our old corporate hedge but that would wear off as soon as the production came back on.

But that one is an accounting anomaly and as you know, we never forecast any mark-to-market gain or loss.

But I think the fundamentals are there that are pretty repeatable.

Next year we have a long position in gas, and therefore I think that, you know, the Virginia fuel has gotten, you know, a big hurt, 35 cents a share estimated at the year-end.

But next year, even though obviously we've made more money if we didn't have the - - the fuel clause for '05, we are going to make real progress and we will overcome that with that long positioning.

It doesn't change the fact that as we roll into '05, '06 and '07, the amount of production you have on hedge grows dramatically and - -

Right.

And - - and prices - - can you remind us what the average hedge position is currently on a - - on a BCF equivalent?

As of October 19th?

Yeah.

As of October, Greg - - this is Joe O'Hare.

We - - the position - - the hedge report is actually on the website and I'll give you the numbers but what I want to make - - let you know is that it's based on a pro forma basis as if Hurricane Ivan had never occurred.

Because the economics are going to be the same whether we get the revenue from insurance recovery or through production.

But for 2005, about 67% of our expected pro forma production is hedged at an average price of 4.38.

And then 57% and 42% in the following years at 4.35 and 5.55.

Great.

Thank you, guys.

Thank you.

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

Please go ahead.

Good morning.

Hi.

Can you hear me?

Yeah, Paul.

I wanted to touch base with you on the impact of the PJM integration.

From what I've read, it looks like there's a $280 million expense, and I know you guys have got fable FERC language, etc., for the deferral of that.

But if it wasn't deferred, when would those expenses actually be incurred and when would they be recorded?

They are recorded as they are incurred.

Right.

And they would start being incurred once you went into PJM.

Okay.

And so would it be over - - I mean you want to defer them until 2011, would it be - - would it be incurred on a straight-line basis or would it be pretty much all in one year or?

Well, there's two pieces to it.

On the start-up costs, those would be amortized over a period of years, that we would have to determine.

They wouldn't all be taken at one time.

The admin fees would be expensed on an annual basis.

But, as you said a few minutes ago, FERC made it clear that it is perfectly appropriate for us to defer those expenses until after our rate-cap period, our frozen rates expires, and then there will be a - - a proceeding at FERC in 2011.

Okay.

Just the admin fees, what are - - how much are those?

If you have a rough approximation as to what those would be and - - and what the amortization of the start-up fee would be?

The admin fees would run around, 40 - - between $35 and $40 million pre-tax.

That's annually?

Yes.

Okay.

And of course those would be recoverable on our transmission rates as we go forward.

Okay.

And the start-up fee?

Start-up costs, there's two of them.

One is for - - excuse me, Paul, with the alliance, which I think is about $16 million, and for PJM is a significantly less number than that.

It's about - - I'm sorry. 20 million - - excuse me, $20 million.

Now, those are to be amortized over a period of time that is yet to be determined.

But, as I said - - or as you said yourself a minute ago, those fall into the deferral language that we got from FERC.

So they will not show up in any of our expense calculations until 2011.

The SEC's looking at this, right.

What - - have they - - when are we going to hear them sort of sign off on it, do you think?

Uh, should be by the end of October or maybe the first week in November.

But it's - - the issue of transmission rates and deferrals are not a Virginia issue.

They are - - those are exclusively FERC jurisdiction.

Okay.

Okay.

And - - and just - - just to clarify here.

There's no contribution from proprietary trading in 2005, the New England assets aren't included in 2005, and you guys are assuming in your guidance 4.50 for gas prices in 2005 guidance, which would have a 7 cents variation if it was a dollar higher than that, is that correct?

That's correct.

By itself.

As I answered in Paul Fremont's questions.

There are other things.

There are other things there.

So don't do your 2005 model over yet.

Besides, you know, I've seen a lot of ranges on the USGen by itself.

But I know you guys like to get ahead and, you know, once the earnings season is over you start looking at 2005.

But we'll - - we'll get you specifics in - - in December and save you the trouble.

Okay.

And could you just also just refresh our memory about how much you have in terms of NUG buyout in 2005?

How much we have in NUG buyout for 2005.

For the contribution - - for the guidance?

In the previous guidance there was $10 to $20 million incremental over our 2004 actualbles.

But like Tom said, you know, the schedule of NUG buyout contemplated when we put that schedule together has probably shifted.

So that'll be one of the factors that we identify in - - when we do the guidance later this year.

Would that be upside to the guidance that you currently have in 2005?

Once again, I'm going to go back to the same thing.

You're asking the same question a different way.

I feel like we're in a court case here, Paul.

But we're - - you know, that would be - - we have the potential to have more in NUG mitigation than we had earlier in guidance.

We also have the potential for some other expenses, expenses beginning of fuel that we would estimate higher as well.

Okay.

Thank you very much, guys.

Thank you.

Our next question is coming from Daniele Seitz of Maxcor Financial.

Please go ahead.

My question has not been answered but it's not going to be answered so thanks a lot.

Thank you for being so nice, Daniele.

Thank you.

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

Please go ahead.

Good morning.

Hey, Scott.

Most of my questions have been answered.

I just had one I guess for Tom Farrell.

Tom, in general about the proprietary trading business, is the decision to potentially exit more driven by the fact that there's just inherent - - there's always going to be inherent volatility or variability in that business and you're trying to really tighten the range of earnings guidance going forward and the predictability.

Because it sounds like you fundamentally believe in the business and given you' alls deep asset position in so many of your business segments, you probably do have a fundamental advantage in a lot of ways in that business.

But could you just kind of maybe color that in a little bit, have you all been thinking through why you all might potentially exit?

Yeah.

It's a good question.

As I said earlier, we have done extremely well with our proprietary trading over the last four or five years until this year.

There is now all sorts of hedge funds in the commodity world.

You have all these international incidents affecting the commodity world.

The gas is now more of a component of the cost of electric generation.

And all those factors combined have led to a market that is not being driven on fundamental basis.

And I think - - I don't - - I think most anybody would agree with that.

We are not set up, institutionally or emotionally to take the kind of volatility that can come into earnings that are being driven by non-fundamental factors.

So that is primarily the reason.

We want to have - - make sure that there are more predictable earnings.

Now, I want to make sure we understand each other, though.

What we're talking about here is the type of business that takes price views, takes open positions on whether in the electric or gas book.

There are lots of things we do in origination, field services where we aggregate people's assets and resell them.

Those - - those type of earnings end up primarily in the accrual space or the earnings show up - - don't show up at the Clearinghouse, they show up at Dominion Generation, for example, when we aggregate electric business around Millstone, for example.

Those kind of activities will continue.

The Clearinghouse is the primary focus of our integration model.

They're the ones that bring these assets together.

So the Clearinghouse itself is going to be there and will be working hand and glove with all the rest of our folks.

But, the - - over the last three quarters it has become plain as day that fundamentals are not what's going on anymore in the electric and gas and oil books and that's why we're examining this very closely and we'll make an announcement later in the fourth quarter.

Okay.

That's - - that's fair.

Thanks, Tom.

That's it.

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 today and we look forward to getting back to you the analytical community and investor community with our 2005 specific guidance when it's approved by our directors in December.

Talk to you then.

Thank you.

Thank you.

That does conclude today's teleconference.

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