道明尼資源 (D) 2006 Q1 法說會逐字稿

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

We now have Mr. Tom Chewning, Dominion's Executive Vice President and Chief Financial Officer, in conference.

Please be aware that each of your lines is in a listen-only mode.

At the conclusion of Mr. Chewning's presentation, we will open the floor for questions.

At that time, instructions will be given as to the procedure to follow if you would like to ask a question.

I would now like to turn the conference over to Tom Chewning.

Mr. Chewning, you may begin.

Good morning, and welcome to Dominion's first-quarter 2006 earnings call.

Joining me this morning are Tom Farrell, our President and CEO, and other members of our management team.

This morning, I will review actual first-quarter 2006 results compared to our expectations, give an update on our credit metrics and liquidity position, outline the changes to our commodities hedges since our last call and provide assumptions for the second quarter of 2006.

We will defer detailed discussion regarding our post-2006 financial outlook to our May 22nd analyst meeting in Boston.

Tom Farrell will review operational performance and other matters following my remarks.

Concurrent with our earnings announcement this morning, we published several supplemental schedules on our website.

We ask that you refer to these exhibits for certain historical quantitative results, as well as our operating assumptions for the second quarter.

From time to time during this call, we will refer to certain schedules included in our quarterly earnings release or the pages from our first-quarter '06 earnings release kit, both of which were posted this morning to Dominion's website.

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

Let me start by providing the usual cautionary language.

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

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

Also on this call, we will discuss some measures about our company's performance that differ from those recognized by GAAP.

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

Dominion recorded operating earnings of $1.63 per share in the first quarter of 2006 compared to $1.44 per share in the prior year.

Schedule five of our earnings releases provide the detailed reconciliation of the first quarter of 2006 to the first quarter of 2005.

The first-quarter 2006 results exceeded internal expectations, largely due to higher-than-expected oil production in the Gulf of Mexico.

Equivalent natural gas production of 111 billion cubic feet exceeded the upper end of our first-quarter forecast, primarily due to increased deepwater oil production at the Devil's Tower facility, including three new wells at Triton and Goldfinger.

Other differences between actual and expected results generally offset each other.

Lower-than-expected natural gas prices had a favorable effect on Virginia fuel expenses, variable cost of natural gas and oil production and the marked-to-market valuation of remaining de-designated hedges.

However, these lower natural gas prices had an unfavorable effect on unhedged natural gas sales revenue.

Warmer than normal weather had a favorable effect on Virginia fuel expenses, but an unfavorable effect on electric and natural gas utility sales.

Adjusting for the net impact of warmer than normal weather on utility-based rate revenue and Virginia fuel expenses and the net changes in the fair value of hedge contracts that will settle later this year, normalized first-quarter operating earnings were $1.50 per share.

On a GAAP basis, earnings per share for the first quarter of 2006 were $1.53 per share, compared to $1.25 per share the prior year.

A reconciliation of GAAP to operating earnings for 2005 and 2006 can be found on schedules two and three of our earnings release.

As Tom Farrell will review in detail later, the Company's operations performed at or above the levels we had set as our goals for the quarter.

Due to the positive first-quarter start and the expectation for continued operational excellence for the balance of the year, we are affirming full-year guidance of $5.05 to $5.25 per share.

During the first quarter, Moody's downgraded Dominion's senior unsecured debt rating one notch to Baa2 with a stable outlook, and Fitch affirmed its BBB+ rating with a stable outlook.

While we are disappointed with Moody's ratings action, our focus is on the execution of our business plan, and we will continue to strengthen our balance sheet, cash flow and credit ratios over the next several years.

I am pleased to report that our credit metrics generally improved during the first quarter.

Although the FFO-to-interest-coverage ratio for the trailing 12 months held flat at 3.7 times compared to year end 2005, the adjusted debt-to-cap ratio improved to 56.4% from 58.1% at year end.

The calculation of these measures can be found on pages 34 and 35 of our first-quarter earnings release kit.

Lastly, we generated nearly $1 billion in operating cash flow during the first quarter, and finished the quarter with more than $3 billion of available liquidity.

In the second quarter, we will take in $330 million of new equity as we settle our March 2002 mandatory convertible offering.

While we have no plans for any capital market equity offerings, we have decided to utilize newly authorized shares to satisfy purchases under our direct stock purchase plans during the remainder of 2006.

This will provide approximately $140 million in new equity, and will add about 2 million shares to total shares outstanding over the next nine months.

This new equity provides financial flexibility to take advantage of incremental asset purchases such as the [Pablo] Gas & Oil acquisition, which Tom Farrell will discuss, as well as opportunities that might be available to our other business units.

In addition, it will help us to accelerate the improvement in our credit metrics.

There is no change to our 2006 earnings per share guidance as a result of this decision.

In addition to the assumptions we normally provide for the quarter, we have listed several factors you should keep in mind when developing an estimate of second-quarter 2006 earnings.

Drivers that compare favorably to second quarter 2005 include higher-than-expected natural gas and oil production and prices and the absence of a scheduled refueling outage at Millstone.

Favorable items in the second quarter of 2005 not expected to recur in 2006 include business interruption insurance proceeds from Hurricane Ivan and gains from the sale of excess SO2 allowances.

Details of our second-quarter drivers and assumptions can be found on schedules six of today's earnings release.

Dominion continued to follow its practice of disciplined and gradual commodities hedging during the first quarter of 2006.

Since our last update, we have hedged an additional 20 Bcf of 2007 natural gas production at $9.41 per Mcf and an additional 111 Bcf of 2008 production at $9.13 per Mcf.

We have not hedged any additional oil production since our last hedge update.

Including internal offsets, our current natural gas equivalent hedge positions are as follows.

We have hedged 85% of '06 production at $4.67 per Mcfe, 67% of '07 at $5.86 per Mcfe and 37% of '08 at $8.26 per Mcfe.

Hedge percentages are based on the midpoint of our production forecast parameters.

Additionally, we have hedged locational basis differentials that essentially match our '07 and '08 natural gas commodities hedging, plus volumes that exceed our natural gas commodity hedge in 2006.

These basis hedges were put into place to lock in average realized prices that support our current year earnings plan.

With respect to merchant generation, since our last update we have hedged an additional 5% each of our '06 and '07 New England-based load generation output and an additional 25% of '08's New England-based load output.

Year to date, the average New England market around-the-clock prices have been about $87 per megawatt hour for '07 and about $82 per megawatt hour for '08.

To date, we have hedged 96%, 80% and 56%, respectively, of our '06, '07 and '08 New England-based load output.

We will review in more detail the earnings impacts of our generation hedge position, including our merchant capacity hedges, on May 22nd.

Details of our current natural gas, oil, electric and coal hedge positions can be found on pages 30 and 31 of our first-quarter earnings release kit.

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

Good morning.

We're pleased with the Company's operational and financial performance in the first quarter.

Despite a very mild winter, which affected utility energy sales and resulted in a near-term retreat in commodity prices, Dominion's strong operational performance delivered a good start to the year.

Before I review first-quarter results in the business units, I want to highlight three initiatives at the corporate level that should give investors an idea of where we are focusing our attention.

First, the Virginia General Assembly adopted Senate Bill 262 on April 19.

This bill provides for the return to past practice for the pass-through of fuel expense to our customers.

We will return to annual fuel cases for the three 12-month periods beginning July 1, 2007, and one six-month period beginning July 1, 2010, with adjustments at the end of each 12-month period to true up any difference between actual and projected fuel costs.

This change demonstrates the constructive environment in which Dominion operates in Virginia.

The orderly process by which Virginia dealt with this potentially difficult situation the utility customers face in the new commodity environment contrasts sharply with the way similar issues have been addressed in nearby states.

Energy prices have become extremely volatile in recent years.

Accurately estimating utility fuel costs has become difficult, even over short time horizons.

The 42-month estimate required under the old law was problematic because of this uncertainty.

The change will allow more accurate estimates to protect consumers by ensuring that they pay only for costs we actually incur, and it protects the Company by eliminating the risk of underrecovery of future fuel expense.

Importantly for our customers, the new law would authorize the State Corporation Commission to defer as much as 40% of the first-year fuel factor increase.

The deferred amount would be collected over the two-and-a-half-year period beginning July 1 of 2008.

Under current law, such a deferral was not possible.

Second, as we have said previously, we have acquired a lot of assets over the last ten years.

We believe each of them made sense at the time, and their performance has been consistent with our expectations.

That said, markets change, and as part of our effort to improve returns on invested capital, we have been engaged in a review of all of our assets to determine how they fit strategically and provide appropriate rates of return.

I want to emphasize that this is not a one-time event.

It is an ongoing process.

It is how we manage this company.

One outcome of this process was the decision to sell the Peoples and Hope Gas local distribution companies to equitable resources, which we announced in early March.

Peoples and Hope are both good businesses, but we determined they did not fit strategically.

Finally, beginning April 1, the Company initiated a new long-term incentive program for officers and selected key contributors.

The program ties long-term incentive compensation to total shareholder return and return on invested capital.

Total return performance will be compared to peer group of utilities, while return on invested capital performance will be measured against targets approved by the Board's Compensation Committee.

When added to the existing annual incentive plan, going forward, about 50% of senior management's compensation will be tied to performance-based incentives.

These programs put our money where our mouths are and further align management's interests with its investors'.

Now, let me turn to the operating performance for each business unit.

The first quarter provided a number of significant events for our generation business.

First, we continue to have excellent operations across the fleet.

The total nuclear capacity factor was above 95%, with our merchant unit at Millstone and Kewaunee at nearly 100%.

Our fossil fleet also had a good quarter, with our utility and merchant coal units having availability levels just shy of 90%, well above last year.

Second, the New England forward capacity market settlement, in lieu of what was formerly known as LICAP, occurred this quarter and is now in front of FERC for final resolution.

Dominion was an active participant in this process and strongly supports the settlement, which we hope will be approved by the requested June 30 deadline.

We will review our merchant capacity hedge positions and the positive earnings impacts of the proposed forward capacity market at our May 22nd analyst meeting.

Delivery safety record and electric service reliability continued to improve.

Our safety performance was the best we have experienced in seven years.

Electrical liability also improved over first quarter of last year, and our target is to meet or exceed last year's strong performance.

Delivery experienced its highest first-quarter new electric connect volume in five years, with 15,000 gross new connects.

Virginia's economy is thriving.

At Dominion Retail, Delivery's unregulated retail business also experienced significant customer growth, adding nearly 70,000 or 6.1% net new accounts over the last 12 months.

As Tom noted, Dominion's oil and gas production for the quarter rose to 111 billion cubic feet equivalent, compared to 99 Bcfe last year, which was 9 Bcfe or about 10% above the midpoint of our first-quarter guidance range.

In the onshore side of E&P, our Sonora Field in West Texas achieved another record during April, with gross operated production exceeding 230 million cubic feet equivalent per day.

The [Closedon] acquisition located in the Texas Panhandle for $92.7 million in February called Pablo.

This purchase of 44 Bcfe of proved reserves was in one of our core operating areas, and provides over 200 additional drilling locations.

From time to time, we will add assets to our core E&P areas and, likewise, will dispose of non-core assets, largely when we are not the operator, as we continue to upgrade our portfolio.

In our offshore business, we are back to greater than 95% of pre-Katrina and Rita levels of operation.

Specifically, the final Devil's Tower well was completed in April, and we are now producing 34,200 barrels of oil equivalent per day, net to Dominion.

Completion of the final Front Runner well started in April.

As previously announced, Rigel/Seventeen Hands commenced production in March.

Dominion Energy also had a good first quarter.

Electric and gas transmission in Cove Point are on track to another record year in safety and reliability.

Our focus on excellence is showing good results throughout Energy's operations.

Two recent events are of particular interest.

First, on April 1, Dominion Transmission commenced operation of our new Northeast storage project, which added 10 Bcf to our portfolio.

And second, last week, we received the final environmental impact statement from FERC for the Cove Point expansion project, and we expect to receive a certificate in time to begin construction this summer.

Expansion of the plant from a daily throughput capacity of 1 billion cubic feet to 1.8 billion cubic feet should be completed in 2008.

All in all, a very good first quarter.

All of the factors that we believe will result in highly accelerated earnings in cash flow growth in 2007 and beyond remain in place.

I will now turn the call back over to Tom Chewning for a few concluding remarks.

Thanks, Tom.

Just a reminder that our Form 10-Q will be filed with the SEC later today and our second-quarter earnings release is scheduled for Thursday, August the 3rd.

Also, we invite you to attend our May 22nd analyst meeting at the Fairmont Copley Plaza Hotel in Boston, when we will discuss our businesses strategy and provide details about the 2007 and 2008 financial outlook, including earnings guidance, forecasted cash flows and supporting drivers and assumptions.

The meeting begins at 9 AM Eastern time.

If you plan to attend, we ask that you RSVP through our website at www.dom.com/investors.

This concludes our prepared remarks, and we are happy to take your questions now.

(OPERATOR INSTRUCTIONS).

Steve Fleishman, Merrill Lynch.

First, Tom Chewning, you mentioned that the quarter, kind of on a normalized basis, was $1.50 excluding certain things?

Yes.

At the end of your -- could you just repeat what you excluded when you gave that number?

Here's the way you can do it.

The first quarter that we reported operating earnings was $1.63 per share.

We had weather hurt in our base rate revenue of $0.10, but we picked up $0.04 a share savings by using less fuel.

And we had mark-to-market on our de-designated hedges that remained of $0.22 a share, but we also had a mark in our producer services of $0.03 negative.

So the net of those two is that weather on net cost us $0.06 a share and marks gave us $0.19 a share, so when you add and subtract all that, you get $1.50 per share.

And those marks that make up the total of $0.19 will all settle in 2006.

So you will have some of that reverse out later in the year, then?

Yes.

So we obviously don't take credit for it from a standpoint of the quarterly earnings.

And just in the spirit of getting this kind of number, I am wondering if you might, of the 5 to 5.25 for this year guidance, give us any sense of what really the normalized number is for this year?

Or is that something for the meetings?

Well, we're not going to get into weather, even though we had a whether hurt that first quarter.

We know that people don't care about weather, particularly.

We are right onstream for the 5.05 to 5.25 range, and there will be no marks of any significance at year end.

These will all settle out.

So those marks that we had are more or less meaningless to us.

They just mess up a quarter in terms of appearance.

And on the marks, I think the marks ended up impacting your lifting cost number?

Or is that not correct?

Because it's in O&M?

No.

On schedule five, we break out O&M and the impact of FAS 133 at E&P.

So that O&M variance number is predominantly lifting costs.

There's no effect of the mark in lifting.

So the lifting cost number that you gave in the quarter, which was better than you expected, is a clean number on schedule four?

Yes, correct.

Maybe Duane could comment on why that might be better?

And is that a good sign, or is that just a temporary thing?

I'll be glad to.

It was actually at the low end of the guidance that we gave, mostly because of ad valorem taxes that rolled through.

But from a quarter to quarter basis, you can look at it this way.

On pricing alone, it was about $0.07.

And then, according to the way we are modeling it here, it looks like it's about $0.10 just on higher industry costs.

And then the majority of the balance is due to the higher insurance premiums, due to the hurricanes in the Gulf of Mexico.

And we wanted to separate that as a line item, if that will help you.

But going forward, we are now saying $1.50 to $1.60, and we were 1.54 for the quarter.

And then, just to maybe round out the comment on the fact that you are now going to be issuing some new equity through the stock purchase plan, Tom, you mentioned that's to kind of fund this E&P investment and then keep a little dry powder for other stuff?

That's right.

But obviously, it would be small stuff, because $140 million only goes so far.

But we really felt that, once we [cut the drip] back on in terms of using newly authorized shares, that we would just go ahead and keep that practice on for this year.

Obviously, investments will offset the additional shares for the year, so there's no change in earnings.

But we should get up a little bit or at least keep up with credit metrics.

Greg Gordon, Citigroup.

I'm going to ask one of the questions that was already asked, but a little bit differently.

When you look at the impact of business interruption insurance net of all of the mark-to-market and the de-designated hedges, we know it's going to be pretty hard to model that quarter by quarter.

But over the course of the whole fiscal year, can you refresh our memory as to how much of that is in the 5.05 to 5.25 guidance that sort of rolls through and is gone at the end of '06?

We incorporated our assumption for BI in the full-year guidance, with our production increase, because at the time, we weren't precisely sure of the early return to production or what really our claim was going to be.

We're still not willing to disclose the actual amount that is built into our assumption, but I think that you can expect on May 22nd that we're going to provide some point of view on 2006 normalized, so you can measure what the structural uplifts are, translated to 2007 and beyond.

And I've got a question for Tom Farrell.

I think, especially with the new legal -- well, new is old -- regulatory structure in Virginia, as I talk to investors, there's an increasing buzz around the concept of, well, when you had the rate freeze, the concept of having a BTU hedge between the E&P business and the utility business was something that you thought created a strategic underpinning for keeping the E&P business and the utility businesses and the merchant power businesses all part of the same corporate entity.

As we approach our May 22nd analyst meeting, it's increasingly less clear that there's -- especially with the fuel adjustment clause having been reimplemented, that that strategic rationale still exists.

So are we going to hear some comments from you in that meeting with regard to whether or not your strategy on the corporate profile has changed at all?

I thought you were going to ask me about whether D'Brickashaw Ferguson was really all that good, going to the Jets.

I already know the answer to that question.

Good, okay.

Well, there were two rationales for our support of the change in the way the fuel is reimbursed to us for our Virginia utility.

The first was to eliminate the volatility to the customers.

And the uncertainty around getting the number right for all of us allowed the deferral to ease any increases, as they may or may not come, and to ensure that in the post-setting environment, that we were not facing under-recovery of fuel costs anymore.

So it basically takes the thing out of our earnings and puts it back into regulatory space.

The other part of it was to increase our flexibility across Dominion, what we decide to do with all these assets as we go forward.

You should expect to hear some discussion around that when we get to Boston.

Hugh Wynne, Sanford Bernstein.

Just a clarification on something you already explained.

The normalized number for the first quarter is $1.50, and you pointed out that weather hurt your base rate revenues by $0.10, but you saved $0.04 by using less fuel.

The second component of that was the adjustment for the mark-to-market of the ineffective hedges.

I was just going to ask if you could repeat the calculations that went into that adjustment.

Well, there were $0.22 positive on those volumes or those contracts, and there was a $0.03 negative mark in another part of the Company on another transportation position.

So our net non-cash items that were mark-to-market were $0.19, and all of those will reverse in 2006.

So they are not a part of our annual normalized 5.05 to 5.25; they won't play a factor because they will all reverse this year.

As I was answering Steve Fleishman's question earlier, even though we were $0.06 down to weather, we don't consider that to change our normalized 5.05 to 5.25 for the year.

So you had a $0.22 gain on ineffective hedges, basically, in the E&P segment?

Right.

And then a $0.03 lost on ineffective hedges related to transportation costs.

Is that correct?

Transportation positions in Dominion Energy.

And then, related to the comments you made on the equity issuance and the drip, what is the expected share count, average diluted shares outstanding for the year, now?

We have not recalculated that, but being that it would only add 2 million shares over the course of nine months, you can expect it to be in the range of 1 million or so, in addition to our original assumption.

Which was?

351.4.

So something like 352.4, going forward?

Something like that.

Paul Fremont, Jefferies.

)Paul Fremont: Really, two questions.

One is, I guess, on page 12 or schedule five you have got FAS 133 hedge ineffectiveness at $0.37 for the quarter.

In trying to get a sense of what that number is for the year, is that what you're going to talk about more at the May 22nd meeting?

Or is it possible to get a sense of what that number is likely to be for the year?

It's not going to be for the year.

It will be zero for the year, Paul.

All of those -- and that's a comparison, that $0.37 is a comparison between the first quarter of last year, where there was a negative mark, which would have been $0.15 negative, and this year at 19 plus or not quite that -- 19 and whatever the difference is, 18.

So that's a comparison quarter to quarter of a negative mark last year and a positive mark this year.

But I want to reiterate; those are entirely timing issues.

All of the contracts associated with it, whether they are the oil and gas contracts in E&P or the transportation position in energy, will reverse; there will be no impact for the year.

Looking at O&M, it looks as if Delivery O&M is up pretty substantially and Generation O&M is down substantially.

Is that sort of the result of a reclassification, or are there other drivers there?

That's something that is going to be discussed in the 10-Q that's filed this afternoon.

If we can just take that off-line, I would appreciate that.

Dan Eggers, Credit Suisse.

On the E&P site, I guess the oil volumes were very good.

I don't know if Duane could give a little more color on how he was able to get so far ahead of schedule for the quarter, and any trajectory for the year and sustainability of oil volumes at these levels?

Sure, be glad to.

First of all, a lot of that was driven by Devil's Tower.

If you will remember, as we were ending 2005, we were a little bit ahead of schedule on how we were able to mitigate some of the shut-in production.

So that carried forward into January, particularly.

Then, in addition to that, the actual performance of the wells are above what we had modeled from a reservoir standpoint and continues today, to see that.

So that's been a big driver there.

Then Rigel/Seventeen Hands came on one month early, and then some of the onshore assets continue to perform very good.

Can you guys give a little more color on Appalachian production?

It looks like volumes were flat from a production perspective year over year.

You guys have been a bit more active in history in that region, if I remember correctly.

I'm not certain which schedule, but generally, the Appalachian barely -- when I say barely grows, it's the nature of it, because it's very low-rate.

I think our current plans are to drill 250 to 300 wells, and we would expect certainly by the end of the year to have some marginal growth in Appalachia, like we've had each of the last couple years, as we continue to expand that program.

But it's very small.

For one of the Tom's, you guys did a very good job as far as incrementally positive hedges, particularly on the power side.

Do you guys have any feel for how much of LICAP has already been [liened] into forward commodity prices, as you the producer demand some payment if you are going to lock up your capacity right now?

Well, the hedges that we have done there -- well, the direct answer to your question is I don't know the answer to it.

But I can tell you, very little of the hedging that you see for the out years -- '07, '08 -- have to do with capacity.

Those are energy hedges that we have added, which leaves -- the way that the capacity payments are worked, it's who has the ownership of that capacity, whether that's by actual ownership or by contract right, will get the payments.

So we intend to try to hang onto the capacity.

So the hedges you are seeing there are largely energy only.

So if we were to front-run May 22nd, we we should assume that the bulk of your output or the bulk of your capacity for those out years would still be a beneficiary of those LICAP changes?

Yes.

(OPERATOR INSTRUCTIONS).

Paul Ridzon, KeyBanc.

You mentioned you are looking at your portfolio of assets to see which ones make sense.

How far along are you on that process?

And can you give us what flavor these assets are?

Well, we are looking at every asset we have.

We haven't said, let's go concentrate on this or concentrate on that.

We're going through the portfolio not by business, not saying let's look at our overall delivery business or our overall generation business or whatever.

We're looking at each one of the component pieces, to make the decision as to whether it's really improving on our return on invested capital.

The reason I mentioned the long-term incentive plan was traditionally, utility companies, when they give out long-term plans, tend to give restricted stock, which reward you for staying around.

We do have a restricted stock component in the program, but 50% of the long-term program is now based on, like we said, putting our money where our mouths are, which is to increase our total shareholder return compared to our peer groups, and to increase our return on invested capital.

So we are very focused on that.

But to say -- I don't have anything to tell you about what the next asset will be or whether there will be another asset that's sold.

We're going to go through it systematically.

We're not going to do anything in a rush.

We don't have anything to announce on that, and we will just continue to go along as time goes by.

How should we think about the interplay between production coming on early and the receipt of business interruption insurance for lost production?

Is there a kind of an offset there?

And do you still expect the combination of BI and production to be at the same level?

Or has the accelerated recovery of production lifted that up a little bit?

Well, it's a great question.

Yes, there is a great direct relationship between early recovery of production and reduction of our insurance claim.

But we have not changed -- as of now, we have not changed our outlook for the total combination of those two items for 2006.

Can we get an update on what you're seeing with regards to the insurability of offshore production, and kind of how you think about that strategically going forward as the current policies start to expire?

We are currently in discussions with our London carriers.

Clearly, capacity is going down as a result of the last two years, and prices are going up.

Too early to comment on specific impact.

We do have conservative assumptions in our guidance for the year, and we will give you more details as we have them.

Scott Soler, Morgan Stanley.

Just on tax rate, we were looking at -- I was looking at pages 14 and 19 this morning.

And on the GAAP income statement, the effective tax rate is 27.6%, and then it's in the higher 30's on the recurring earnings schedule on page 19 of the package this morning.

What is the difference there?

And what should we use as a normalized rate?

You should use the 36% [or so] as a normalized rate.

The reason the rate is lower in the first quarter is because of the sale of Peoples and Hope.

We had some adjustments to our deferred taxes, and we realized some benefits on the reserves we had set up on the telecom write-off.

And it was a net benefit, and it reduced the rate for the quarter.

But ongoing, we expect more of a normal rate, like what you have seen over time.

Okay, that makes sense.

And then, either Tom or Duane, your lifting and DD&A costs were toward the lower end of the guided range, and that is very good.

And we were just curious -- is it much too early in the year, when you're looking out at what you think your capital spending is going to be and also what your production costs are going to be, to make an assumption that that will still be tracking at the lower end of the guided range?

It is too early, obviously, after the first quarter.

The main driver on the production costs was the fact of commodity prices going down.

Other than that, the things that are fixed and variable came in pretty much as to what we said.

So I would stick with the guidance that we gave you, not necessarily drive towards the low end.

So it was mainly just taxes, right?

That's exactly right.

And the DD&A came in right in the middle of the guidance.

And then, on your compensation plan, that is great, that you all are [geared to] return on capital.

What I was curious about, Tom, is that on the other half, when you were talking about total shareholder return, were you referring to simply earnings growth plus yield, as many utilities look at, or are you more specifically just talking about the share price performance versus a peer group?

Share price and dividend together, shareholder return.

That's our definition of it, for this compensation plan.

Sam Brothwell, Wachovia Securities.

Can you give us any color with respect to the compensation plan on who makes up that peer group?

It's what you would expect.

I don't have the list sitting here in front of me.

It was approved by our Board Compensation Committee.

But I know TXU's in it.

That will be interesting.

[Installation] is in it.

Hold on, (indiscernible) the envelope.

Progress, AEP, TXU, Entergy, FPL, Duke, Southern, Excelon, [Nice Source], PP&L and FirstEnergy.

David Schanzer, Janney Montgomery Scott.

You indicated that in the Gulf, production is up to about 95% of pre-hurricane levels.

How long does it take to go from 95 to 100, or has there been permanent damage and you won't be able to reach it?

Could you give us a little color on that?

Duane, I think you should answer that.

We have about 15 million a day shut in built various shut in, still, various damage.

Some of it, the platforms actually have to be replaced.

But we would expect by the end of the year or very early '07 we would have about 10 of that back. 5 of that may never come back; we just don't have enough technical information on it yet.

But it's very minor; we certainly don't change anything because of it.

No, I understand.

And then, as far as your nuclear capacity being at 95% for the quarter or at the end of the quarter, what does the cooling season look like?

And will all your nuclear units be available?

Yes, all the units will be available for cooling.

And then, in the reassessment of assets that you talked about, would that encompass potentially a change from the previous main-to-main strategy?

Would you be looking beyond that strategy when you're assessing your assets?

Well, we're going to talk more about what we are thinking about on May 22nd.

Well, I can wait, then.

I don't want to get ahead of that, particularly.

But it doesn't mean we're going to start going to California.

Understood.

We'll wait until May 22nd.

Paul Patterson, Glenrock Associates.

I wanted to sort of check with you.

Was there any -- just, I guess, to follow up on Paul Ridzon's question -- the strategic review, any timeframe where we think it might be completed?

And is there anything that -- is everything on the table?

Or is there any particular sort of class of assets that might be more or less under review than others?

Everything is on the table.

Saying that, we certainly have to keep in mind our obligations in Virginia to serve our electric customers.

So shedding the Virginia power plant is not a very likely scenario.

But other than that, we're taking a look at everything.

And I don't have an end frame for you on when we we will be finished; we're going to continue to go through it systematically.

I think, to answer it another way, to amplify that a little bit, for instance, in the case of the two LDCs that we are selling, they were good operations but it was a combination of the fact that we didn't have critical mass in terms of size in those jurisdictions, and the market for those assets was extremely strong.

So markets change from time to time, so you need to continuously review your opportunities, because maybe one quarter or one year, the market is not strong for one of your assets that might be under-earning or that you could part with strategically, and the next year it is.

So it will not only take us some time to get through, but we plan to continuously monitor opportunities to bring more value to our shareholders.

And that's really -- we've got great assets, and most of them are in great shape.

In fact, all of them are very positive.

But some of them are more positive than others, and then sometimes, somebody else wants them more than we do.

So in that case, if we have a good tax position and we don't have to lose too much to taxes, we bring value to our shareholders by selling.

And then, the other sort of big-picture question here -- we saw, obviously, TXU make a very large announcement about building not only power plants in its area, but also sort of discussing how it's potentially going to take the show on the road to PJM, which is an area where you guys operate.

And I think of you guys as having a strong fuel set in generation.

Obviously, you're market participants.

Any thoughts?

Well, we have been looking at a coal plant in part of Virginia now for a considerable period of time.

I don't know what TXU's experience is with the regulatory regimes around building coal-fire power plants, and the amount of time and effort you have to go through to get the permits for it.

So I think it's going to take a considerable period of time to implement a strategy that is building large numbers of coal plants in any region of the country, particularly east of the Mississippi, where all the SIP call regulations are in place and a variety of other issues, particularly with states -- for example, Maryland is just joining onto -- trying to join the carbon dioxide issues.

So I thought that announcement was very interesting, and we certainly have, I think, just about what -- probably not the last, but close to the last coal-fire plant that was commissioned in the United States was commissioned by Dominion, one of any size, and that was in 1995.

So we have a great deal of experience ourselves in these issues.

So we are looking at one in Virginia.

We have looked at other places.

Getting it done is a lot harder than talking about it.

Absolutely.

But in terms of merchant generation or building new merchant generation, now that you guys have LICAP or whatever, the successor to LICAP, are you guys thinking of building any merchant generation?

Not at the moment.

The coal-fire plant we talked about would be under this Virginia legislation that was adopted in 2004, where we would go to the Commission in advance and get a guaranteed rate of return on the plant before we spent any money or turned over any soil.

[Tom O'Neill], [Sidvale].

I just had a quick question on the basis differential.

If I'm reading this correctly, this is the hedge price that you incurred to put these on.

I was just curious how that compared to the current market, and if you could just offer some insight into the widening that takes place as we go further out in time.

It's actually not the cost of the hedge; it's the average of all our contracts that we have put on to hedge locational-based differential in 2006.

You can see that we have about 100 Bcf of unhedged gas that is to be sold that is unhedged.

Now, we have seen an improvement from what we saw at the end of 2005, and that track is incorporated, still, in our 5.05 to 5.25.

But we have not quantified what we are seeing in the marketplace today, because it's not quite as easy as discussing Henry Hub gas, because there are so many delivery points.

It's just a little more complex discussion, which we're going to get into from our prospective again on May 22nd.

So let's just say that what we see in the market today still supports our earnings guidance, and that $0.27 is the average contract price of the hedges that we have on.

So the outer years reflect just more expensive hedges being put on more recently?

Again, yes.

But consider the fact that their differentials are varied, depending on what delivery point has been hedged.

So in the out years, you can actually see that number fluctuate as we put on more hedges, because of where we may put them on.

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

Mr. Chewning, do you have any closing remarks?

Yes.

I would like to thank everybody for joining us this morning, and look forward to seeing many of you on May 22nd.

Please enjoy the rest of your day.

Good morning.

Thank you.

The does conclude today's teleconference.

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