Thomas F. Farrell, II, President and CEO Thomas N.

Chewning, Executive Vice President and CFO Duane C. Radtke, President and CEO, Dominion Exploration Scott Hetzer, Group Vice President, Principal Accounting Officer Mark F.

McGettrick, President and CEO, Dominion Generation Joseph O’Hare, Director, Investor Relations

Steve Fleishman, Merrill Lynch Greg Gordon, Citigroup Hu Win, Sanford C. Bernstein Paul Fremont, Jefferies & Co Dan Eggers, Credit Suisse Paul Rizdon, KeyBanc Capital Markets Scott Soler, Morgan Stanley Sam Brothwell, Wachovia Securities David Schanzer, Janney Montgomery Scott Paul Paterson, Glenrock Associates Tom O’Neil

Thank you Pfeiffer. 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 changes to our commodity 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 2006 earnings release kit, both of which were posted this morning to the Dominion website. The website address is www.dom.com/investors.

We start by providing the usual cautionary language. The earnings release and other matters that maybe 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 quarter report on Form 10-Q for a discussion of factors that may cause results to differ from management’s projections, forecast estimates, and expectations. Also, on this call we will discuss the measures about our company’s performance that differ from those recognized by GAAP.

You can find 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 5 of our earnings releases provides a detailed reconciliation of the first quarter of 2006 to the first quarter of 2005. The first quarter of 2006 results exceeded internal expectations largely due to highly unexpected 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 deep water 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 the general fuel expense, variable cost to natural gas and oil production, and the mark-to-market evaluation 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 fare value of hedged 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 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 2 and 3 of our earnings release.

As Tom Farrell will review in detail earlier, 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 expectations 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 Sr. unsecured debt rating one notch to Baa2 with a stable outlook, and Fitch affirmed its BBB rating with a sable outlook.

While we are disappointed with Moody’s rating 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’m pleased to report that our credit metrics generally improved during the first quarter.

Although the FFO, the interest coverage ratios for the trailing 12 months, held flat at 3.7 times compared to year end 2005, the adjusted debt-to-capital show 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’ve taken $330 million of new equity as we settle our March 2002 mandatory convertible offerings.

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 the second quarter 2006 earnings.

Drivers that compare favorably to second quarter 2005 include higher expected natural gas and oil production and prices in 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 James from the sale of excess SO2 allowances.

Details of our second quarter drivers and assumptions can be found on Schedule 6 of today’s earnings release. Dominion continued to follow its practice and discipline in gradual commodities hedging during the first quarter of 2006.

Since our last update, we have hedged an additional 20 Bcf of 2007 natural 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 2006 production at $4.67 per Mcfe, 67% of 2007 at $5.86 per Mcfe, and 37% of 2008 at $8.26 cents per Mcfe. Hedge percentages are based on a midpoint of our production forecast range.

Additionally, we have hedged locational basis differentials that essentially match our 2007 and 2008 natural commodities hedging plus volumes that exceed our natural gas commodities 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 2006 and 2007 New England based load generation output and an additional 25% of 2008 New England based load output. Here to date, the average New England market around-the-clock prices have been about $87 per megawatts hour for 2007 and about $82 per megawatt hour for 2008.

To date, we have hedged 96%, 80%, and 56% respectively of our 2006, 2007, and 2008 New England based load output. We will review in more detail the earnings impact of our generation hedge position including our merchant capacity hedges on May 22nd.

Details of our current natural gas, oil, electric, and coal hedged 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 are 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 from the business units, I want to highlight three initiatives at the cooperative level which should give investors an idea of where we are focussing our attention.

First, the Virginia General Assembly adopted Senate Bill 262 on April 19th. This bill provides for the return to practice for the passthrough 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 6-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 cost. This change demonstrates the constructive environment in which Dominion operates in Virginia.

The orderly process by which Virginia dealt with this potentially difficult situation in the utility customer space 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 cost 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 such that consumers find share that they pay only for cost we actually incur and it protects the company by eliminating the risk of under-recovery of future fuel expense. Importantly for our customers, the new law would authorize the Safe Corporation Commission to defer as much as 40% of the first year fuel factor increase.

The deferred amount will be collected over the two and half year period beginning July 1, 2008. Under current laws such as a deferral was not possible.

Second, as we have said previously, we have acquired a lot of assets over the last 10 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 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 & Hope Gas local distribution companies to equitable resources, which we announced in early March. Peoples & 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 compensations to total shareholder return and return on invested capital.

Total return performance will be compared to peer groups 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 interest 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 continued to have excellent operations across the point.

Our total nuclear capacity factor was above 95% with our merchant units at Millstone in Kewaunee at nearly 100%. Our fossil fleet also had a good quarter with out utility and merchant core units having availability levels just shy of 90%, well above last year.

Second, the New England Forward Capacity Market Settlements, in lieu of what was formerly known as LICAP, occurred this quarter and is now in 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 deadlock.

We will review our merchant capacity hedged positions and a positive earnings impact of the proposed forward capacity market at our May 22 analyst meeting. Delivery safety record and electric service reliability continue to improve.

Our safety performance was the best we’ve experienced in seven years. Electric reliability 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 driving.

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.

The offshore side of E&P, in regards to Northfield and West Texas, achieved another record during April with gross operative production exceeding 230 million cubic feet equivalent per day, because of an acquisition located in Texas Panhandle for $92.7 million in February called Pablo. This purchase of 44 Bcfe approved reserves was in one of our core operating areas and provides over 200 additional billing locations.

From time to time we will add assets to our core E&P areas and likewise will dispose off 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 frontrunner 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 and coal were on track for 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.

Second, last week, we received the final environmental impact statements from FERC for the coal point expansion project, and we expect to receive the 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 and 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 as a reminder, our form 10-Q will be filed with the SEC later today and our second quarter earnings release is scheduled for Thursday, August 3rd.

Also, we invite you to attend our May 22 analyst meeting at the Fairmont Copley Plaza Hotel in Boston, when we will discuss our business 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 a.m.

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

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

Hi guys, good morning. A couple of things; first, Tom Chewning, you mentioned that the quarter kind of on a normalized basis was about 50 excluding certain things, could you just repeat what you excluded when you gave that number?

Here’s the way you can do it, Steve. The first quarter that we reported operating earnings was $1.53 per share.

We had weather hurt our base rate revenues of $0.10, but we picked up $0.04 of share saving by using less fuel, and we had mark-to-market de-designated hedges that remained at $0.22 per 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 per share and marked gave us $0.19 per share.

So, when you add and subtract all that you get $1.50 per share. Those marks that make up the total of $0.19 will all settle in 2006.

Okay, you’ll have some of that reverse out later in the year then?

Yes, we obviously don’t take credit for it from a standpoint of the quarterly earnings.

Correct. In the spirit of giving this kind of number, I’m wondering with the $5.05 to $5.25 for this year guidance give us any sense of what the normalized number is for this year, or is that some for the meeting?

Well, we’re not going to get into weather even though we had the weather hurt that first quarter. We know that people don’t care about weather particularly.

We’re right on stream 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.

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?

Steve, on Schedule 5, we break out O&M and the impact of FAS 133 E&P. So, that O&M variant number is predominantly lifting cost.

There is no effect of the mark in lifting.

Okay, so the lifting cost number that you gave in the quarter, which was better than you expected, is a clean number on Schedule 4?

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.

Steve, I’ll be glad to. It was actually at low end of the guidance that we gave mostly because of ab-norm taxes that rolled through, but from a quarter-to-quarter basis, we can look at this way: On pricing alone it was about $0.07 and then according to the way we’re modeling as here it looks like it’s about $0.10 just on higher industry cost, and then the majority of the balance is due to the higher insurance premiums due the hurricanes in the Gulf of Mexico, and we wanted to separate that as a line item, as that will help you.

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

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

That’s right. Relatively small stuff because it’s not $140 million, only goes so far, but the monthly cut trips back on in terms of using really newly authorized shares that we would just go ahead and keep that practice on for this year, so obviously investments will offset the additional shares for the year, so there is no change in earnings, but we should get up a little bit or at least keep up with credit metrics.

Thank you.

Okay, 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 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 2006?

Greg, 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 claims were going to be. We’re still not willing to disclose the actual amount that’s built into our assumption, but I think 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 for 2007 and beyond.

I’ve got a question for Tom Farrell, I think especially with the new legal regulatory structure in Virginia, as I talked to investors there’s an increasing buzz around the concept of “when you to feed 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 you approach your May 22nd analyst meeting it’s increasingly less clear, especially with the fuel adjustment clause having been re-implemented, 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?

Greg, I thought you were going to ask me about whether the Booker Shaw Fergusson was really all that good…there are two rationales for our support of the change in the way 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 weren’t taking under-recovery fuel cost anymore.

So, basically, it takes this thing out of our earnings and puts it back into regulatory expense. The other part of it was to increase our flexibility across Dominion on what we decide to do with all these assets as we go forward.

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

Okay thank you.

Hi, just a clarification on something you already explained. The normalized number for the first quarter was $1.50 and you pointed out that the weather hurt your base rate revenues by $0.10 but you say $0.04 for using less fuel.

But 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.

There were $0.22 positive on those volumes of those contracts and there was a $0.03 negative marked in another part of the company on another transportation position. So, net non-cash items that were mark-to-market were $0.19 and all of those were reversed in 2006.

So, it is not a part of the annual normalized $5.05 to $5.25 factor, because they will also reverse this year. As that was an answer in 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.

So you had a $0.22 gain on ineffective hedges basically in the E&P segment and then a $0.03 loss 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 trip, what is the expected share count average diluted shares outstanding for the year now?

We hadn’t recalculated that, Hu, 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 a million or so in addition to our original assumption.

Which was?

351.4.

Okay, so something like 352.4 going forward?

Something like that.

All right, thank you very much.

Thanks, really two questions. One is, I guess on page 12 or Schedule 5, you’ve got FAS 133 hedge ineffectiveness at $0.37 for the quarter.

I’m just 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 zero for the year, Paul, and that $0.37 is a comparison of between the first quarter of last year where there was a negative mark, which would have been $0.15 negative, and this year $0.19 and whatever, the difference is $0.18. That’s a comparison quarter to quarter, a negative mark last year and a positive mark this year, but I want to reiterate, those entirely timing issues, all of the contracts associated with it, whether they are the oil and gas contracts and E&P of the transportation and position and energy will reverse.

There will be no impact for the year.

Okay. And then the second question I have is, 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?

Paul, this is Joe, that’s something that’s going to be discussed in the 10-Q that’s filed this afternoon. If we could just take that offline I’d appreciate that.

Okay.

Hi, good morning. On the E&P side I guess the oil volumes were very good, I don’t know if Duane can give a little more color on how he was able to get so far ahead of schedule for the quarter and any projection for the year on sustainability of oil at these levels?

Sure Dan, I’d be glad to. First of all, a lot of that was driven by Devil’s Tower.

If you remember as we were ending 2005, we were a little bit of 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 is 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.

Got it. Can you guys give a little more color on Dominion Exploration & Production, it looks like volumes were flat in your production respectively year over year, you guys have been a bit more active in history in that region…

I’m not certain which schedule, but generally the…when I say barely grows, it’s a nature of it, because it’s very low rate, I think our current plans are to drill 250-300 wells and we would expect certainly by the end of the year to have some marginal growth in…like we’ve had each of the last couple of years as we continue to expand that program, but it’s very small.

And I guess for one of the Tom’s, you guys did a very good job as far as incrementally positive hedge particularly on the power side. You guys have any feel for how much LICAP has already being leaned into forward commodity prices as you the producer have demanded some payments if you’re going to walk into capacity right now?

Well the hedges that we’ve done there, Dan…the direct answer to your question, I don’t know the answer to it, but I can tell you that very little of the hedging that you see for the out years of 708 have to do with capacity. Those are energy hedges that we have added, which leave the way the capacity payments that work who has the ownership of that capacity, whether that’s by actual ownership or by contract right, we’ll get the payments.

So, we intend to try to hang onto the capacity. So the hedges you’re seeing there are largely energy only.

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

Yes.

Got it, thank you guys.

Good morning. You mentioned you’re looking at your portfolio of assets to see which ones make sense.

How far long are you on that process, and can you give us what flavor these assets are?

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 saying let’s look at our overall delivery business, 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 plans was traditionally utility companies when they give up long-term plans they tend to give restricted stock, which rewards 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’re very focused on that, but I don’t have anything to tell you about what the next asset will be or whether there will be another asset. 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’ll just continue to go along with it as time goes by.

Second question; 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 look to get up a little bit?

That’s a great question, but yes, there’s a direct relationship between early recovery of production and reduction of our insurance claims, but 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 how you think about that strategically going forward as the current policies start to expire?

Paul this is Scott Hetzer. We are currently in discussion with our London carriers.

Clearly capacity is going down as a result of the last two years and prices are going up. It’s too early to comment on specific impact.

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

Thank you very much.

Good morning Tom. I had three questions and the first question is just on the tax rate.

We were looking through 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 30s on the recurrent earnings schedule on page 19 of the package this morning. What’s the difference there and what should we use as a normalized rate?

Scott, this is Steve Rogers. You should use the 36% as a normalized rate.

The reason the rate is low in the first quarter is because of the sale of Peoples & 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’re seeing over time.

Okay, that makes sense. And then either Tom or Duane, your lifting the DD&A cost towards the lower end of the guided range, that’s 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 in the lower end of the guided range?

Tom, I’ll take that. It is too early obviously after the first quarter.

The main driver on the production cost 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’d stick with the guidance that we gave you, not necessarily drive towards the low end.

So, Duane, it was mainly just taxes?

That’s exactly right, and the DD&A came in right in the middle of the guidance.

Okay, on your compensation plan, that’s great that you’re already geared to return on capital, what I was curious about, Tom, 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 it. Are you more specific just talking about the share price performance versus the peer group?

Share price and dividends together. That’s our definition of it for this compensation claim.

All right, thank you.

Hi good morning, most of mine have been covered, but can you give us any color with respect to the compensation claim on who makes up that peer group?

It’s who you would expect. I don’t have the list sitting here in front of me.

It was approved by Board Compensation Committee. I know TXU is in it…Progress, AEP, TXU, Entity, FPL, Duke, Southern, Exelon, UniSource, PPL, and FirstEnergy.

Okay, thanks very much.

Hi, good morning. A couple of fairly quick questions; you had indicated that in the Gulf production 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 could answer that.

We have about 15 million a day shut in, some of the platforms actually have to be replaced, but we would expect by the end of the year or very early 2007 we’d have about ten of that back, five of that may never come back. We just don’t have enough technical information on it yet, but it’s very minor.

We certainly won’t change anything because of it.

And then as far as your nuclear capacity being at 95% through the quarter or at the end of the quarter, what is the cooling season look like and will all your nuclear units be available?

This is Mark McGettrick, yes, all those units will be available for cooling.

Okay, great. 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’re thinking about on May 22nd…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, thank you.

Good morning guys. Most of my questions have been asked and answered, but I wanted to sort of check with you…I guess it’s a followup on Paul Rizdon’s question, the strategic review, any timeframe where we think it might be completed and is everything on the table or is there any particular subclass of assets that might be more or less under review than others?

Everything is on the table. Saying that we’d certainly have to keep in mind our obligations in Virginia to serve elective customers, so shedding our 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’ll be finished.

We’re going to continue to go through it. Another way of amplify it 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.

Markets change from time to time, so you need to continuously review your opportunities, because may be one quarter or one year the market is not strong for one of your assets, it might be under-earning or that you could part with strategically, and the next year it is. So, it will not only take us sometime to get through but we plan to continuously monitor our opportunities to bring more value to our shareholders.

We’ve got great assets and most of them are in great shape, in fact all of them are very positive, but some 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 lose too much taxes, we bring value to our shareholders by selling.

Okay, and the other is a big picture question, we saw obviously TXU make a very large announcement about building not only power plants in this area but also sort of the discussing how it’s potentially going to take the show on the road to TJM, which is the area where you guys operate, and I think of you guys as having a strong field set generation, obviously your market participants, any thoughts?

We’ve been looking at a coal plant in part of Virginia now for a considerable period of time. I don’t know what TXUs experience is with the regulatory regimes around building coal power plants and the amount of time and effort you have to go through to get the permit for it.

So I think it’s going to take a considerable period of time to implement a strategy that’s building large number of coal plants in any region of the country, particularly east of the Mississippi, where all the regulations are in place and a variety of other issues, particularly with states, for example Maryland joined the carbon dioxide issues. So, I thought that announcement was very interesting and we certainly have…probably not the last, the last coal power 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’re 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 the merchant generation, now that you guys have…or whatever the successor to LICAP, are you guys thinking of building any merchant generation?

Not at the moment. The coal power plant we talked about would be under the 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.

Okay, thanks a lot guys.

Good morning, 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’m just curious how that compared to current market and if you could just offer some insight into the widening that takes place as we go further up. Thanks.

Tom, 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 basis differential in 2006. You can see that we have about 100 Bcf of unhedged gas that is to be sold.

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 haven’t quantified what we’re seeing in the marketplace today, because it’s not quite as easy as discussing Henry Hubb gas, because there are so many delivery points and it’s just a little more complex discussion which we’re going to get into from our perspective 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.

Okay, so then the outer years reflect just more expense on 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. Though in the outer years you can actually see that number fluctuate as we’ve put on more hedges, because of where we may put them on.

Okay, great, thank you.

I’d 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.