道明尼資源 (D) 2005 Q2 法說會逐字稿

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

At this time all participants have been placed on a listen-only mode and the floor will be open 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 welcome to Dominion's second quarter 2005 earnings call.

Joining me this morning are Tom Capps, our CEO;

Tom Farrell, our COO; and numerous other members of our Management team.

This morning we will review GAAP and operating earnings for the second quarter, compare actual second quarter results to our forecast, and provide earnings guidance for the third quarter.

In addition to financial results, Tom Farrell will be discussing several items of interest.

Following our prepared remarks, we will be happy to answer your questions.

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

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

From time to time during this call we will refer to certain schedules included in this morning's earnings release, or to pages from our second quarter earnings release kit posted this morning to our website.

Our 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 experienced a very good second quarter.

Our operating activities performed, on balance, as we expected.

Additionally, we achieved a final settlement with our underwriters on our business interruption claim relating to Hurricane Ivan.

On a GAAP basis, earnings were $0.97 per share.

Operating earnings were $0.99 per share. [Inaudible] detail with second quarter results can be found on Schedule 1 of this morning earnings release.

Items excluded from operating earnings reflect charges related to exiting certain businesses.

The final true up on this [inaudible] long-term towing contract was $0.01 per share.

Revisions of a value of residual mortgage asset, held by Dominion capital, also amounted to $0.01 per share.

The reconciliation between GAAP earnings and operating earnings can be found in Schedule 2 of this morning's earnings release.

Income related to the Hurricane Ivan business interruption claim was $0.14 per share above the high end of quarterly guidance.

The $114 million of total income recognized in 2005 from this claim compensates us for all volumes lost due to the storm.

It does not result in a change of our 2005 annual guidance.

Importantly, we were able to negotiate a fair settlement that allows us earnings and cash flow certainty, as well as the flexibility going forward to manage our offshore drilling program without impacting our claim.

As a part of its steel management activity, the Company took the opportunity to sell excess emissions credit into a robust market during June.

This, and above-forecasted benefits from PJM energy supply margins, enabled us to overcome negative events experienced in the quarter.

Weather in our Virginia electric territory was below normal for the quarter.

Specifically, weather was below normal in April and May, slightly above normal during June.

The combination of higher than forecast generation volume and prices paid in June caused Virginia Power Fuel to be slightly above our quarterly forecast.

E&P production was slightly beneath our quarterly projection, as were prices received at E&P.

A sharp rise in prices in late June led to a non-cash charge, as required under FAS 133, from increased oil and gas basis differentials.

Our Brayton Point facility expansed to a 16-day extension of a planned outage in May, which created a small underrun in unregulated generation income.

For the 12 months ended June 30, 2005, funds from operations covered our interest expenses 4.2 times, and our available liquidity at the end of the quarter was $1.3 billion.

Our adjusted debt to total cap ratio increased from 55.8% at the end of the first quarter, to 56.3% at the end of the second quarter.

Payment to buy out the [inaudible] contract, an increase in cash margins used to collateralize oil and gas hedges, resulted in increased debt, while the Company deferred accessing $321 million of equity raised in our forward (ph) sale until August.

This was originally planned to be taken down in May.

Summarizing the second quarter and year-to-date, we are progressing on schedule to meet our 2005 earnings expectations and, therefore, can reconfirm our annual guidance of $5 to $5.10 per share.

Tom Farrell, our Chief Operating Officer, will now comment on the dynamics of generation and oil and gas production along with other items of interest.

Tom?

Thanks, Tom.

Good morning.

On July 5, we completed the acquisition of the 568-megawatt Kewaunee nuclear power station in Wisconsin for $192 million in cash.

Dominion will sell 100% of the facility's output back to the local utilities under two power purchase agreements, which expire in 2013.

We successfully completed the reactor vessel head replacement for Millstone Unit 2 on May 18, five days ahead of schedule during a planned refueling outage.

In doing, so the Unit set a record for the shortest and safest refueling outage in its history.

All six planned reactor vessel head replacements, including Kewaunee, have now been completed.

Our first two months of operation within PJM went as we expected.

Overall, since joining PJM net purchases are up, replacing our more costly units which has helped mitigate increased fuel expense in a variety of ways.

More on that in a moment.

Depending on load conditions, we are cycling mid-merit (ph) coal units, combined cycle units, and large oil units to maximize the purchasing benefit of PJM.

The cycling is consistent with our expectations and allows us to optimize fully each plant's daily run schedule.

Transmission congestion has been greater than anticipated, but the financial impacts have been mitigated by our financial transmission rights, so-called FTRs.

This is how FTRs are designed to work and they have.

Our drilling success continues in the Gulf of Mexico with a recently announced discovery of the deepwater 'Q' prospects in Mississippi Canyon 961.

Dominion holds a 50% interest with our partner, Spinnaker Exploration.

Other significant activity includes the continued completion of Devils Tower and front runner.

We are also tying in four new deepwater development fields, Triton/Goldfinger and Rigel-17 Hands, with scheduled first production this fall.

Completion operations on the final well at Devils Tower plus four planned recompletions will be finished by year end, while the four remaining wells at Front Runner will be completed through the second quarter of 2006.

The total of about four BCF equivalent of 2005 production has been delayed due to early storms in the Gulf of Mexico.

The majority of this due to shut-in production and operational delays resulting from hurricanes Dennis and Emily.

Fortunately, none of our facilities was damaged, but several drilling and completion operations were temporarily suspended due to the back-to- back storms.

Also in the first six months of 2005 we have enjoyed a 201% reserve replacement ratio that includes divestments and our third BBP.

Before I turn the call back over to Tom Chewning, I want to add a few words about Virginia fuel expense in the second quarter and our forecasts for oil and gas production over the balance of the year.

Virginia fuel expense came in very close to the guidance we gave you in our quarter one call.

Schedule IV shows we are about $0.02 more in action fuel expense than anticipated, which was offset by $0.02 in higher than expected energy supply margins resulting from higher than expected FTR revenues.

Our fuel expense is managed as part and parcel of our overall Virginia Power generation portfolio and our experience in PJM, which, of course, we joined May 1.

During May and June and July, for that matter, we experienced positive and negative variances within the parameters we expected and which we reflect in guidance.

A few examples illustrate the point.

We actually ran some marginal coal units less than we otherwise would have because purchased power was less expensive on the margin, saving on fuel expense.

When we experienced higher than expected congestion on our grid because of PJM's dispatch protocol we had to back off some coal units and run higher-cost oil units in other parts of the service territory but we were compensated for that through increased FTR revenues.

Also because of PJM's marginal dispatch we used less coal than expected in the quarter.

This usage pattern creates a reduction in projected coal consumption and generates surplus emissions credits, which are available for resale should this pattern continue.

We have spent a lot of capital to reduce emissions in [inaudible] fleet over the last few years.

Brayton Point and Salem Harbor came with large banks' credits.

Our operational excellence, as well as our PJM experience, has allowed us to create an increasing surplus bank of allowances.

Like electricity and gas, other commodities which we produce, we will continue to monetize our excess allowances at opportune times.

We have done so for years and we expect to continue to so.

As we have stated before, our internal hedges in PJM work to offset increased fuel expense.

These include higher E&P prices, increased tariff sales in a hotter than normal month like June, increased FTR revenue, if congestion causes a more expensive unit to run, and additional allowances available for sale to third parties.

All in all, we met our internal expectations on fuel usage and conform to the financial guidance we gave earlier in the year.

Our present forecast for E&P production is slightly reduced for yeard end, dropping about 1% to 440 to 445 BCFE equivalent.

The reduction is caused primarily by 4 BCF equivalent from the June and July hurricanes, as well as about 7 BCF equivalent from lingering delays caused by last year's Hurricane Ivan.

This 11 BCFE is offset, in part, by excellent onshore performance, which should be 5 to 7 BCFE above forecast.

E&Ps production delays have turned the corner with daily product increasing notably in July over preceding months.

Now I will turn the call back over to Tom Chewning.

Thank you, Tom.

Let's now turn to third quarter guidance.

Assumptions used and reconciliation to the third quarter of 2004 can be found on page 13 of our second quarter earnings kit on our website under third quarter '05 guidance and assumptions.

The third quarter 2005 guidance is a range of $1.20 to $1.25 per share.

This compares to operating earnings of $1.21 per share in the third quarter of 2004.

The primary earnings growth drivers compared to the third quarter of 2004 include a return to normal weather, increased contributions from unregulated generation, and our producer services businesses.

Customer growth, higher commodity price realizations at E&P, incremental VPP revenue, and benefit from FTR income.

These positive contributions are expected to be partially offset by an increase in the under recovery of Virginia fuel expense due to return to normal weather, demand growth and higher commodity prices.

Lower gas and oil production due to VPPs, sale of British Columbia assets, and Hurricane Ivan delays, higher DD&A rates and production costs.

The effects of FAS 133 gains recognized from oil options at E&P in the third quarter of 2004, which will not recur in the third quarter of 2005, and dilution associated with an increased share count which includes accessing the 5 million shares of common stock in August.

This issuance will conclude Dominion's obligation under the forward equity sale agreement entered into with Merrill Lynch in September of 2004.

For those who have done your math, our third quarter earning guidance implies an increase in the range of 10% over last year's fourth quarter results in order for us to achieve our annual guidance.

We are not going to supply specific fourth quarter guidance until our third quarter call on November 3.

However, there are many comparative positives, including a return to normal weather, franchise growth, the addition of Dominion in England, Kewaunee, and the fifth tank at Cove Point, price uplifts and VP benefits at E&P, higher note savings, FDR income and, most importantly, a significant increase in oil and gas production.

We expect to produce approximately 35 more BCF equivalent in this year's fourth quarter in comparison to the same period of '04.

Certainly, a part of this involves recovery from loss production caused by Hurricane Ivan, but we are also added production from Front Runner and production from subsea tie backs, previously mentioned by Tom Farrell, will begin in the fourth quarter.

There are several items that offset some of these benefits, but overall, we should see a very significant improvement in our fourth quarter results this year in comparison to last.

This ends our prepared remarks.

We will be happy to take your questions now.

Ashley?

Thank you.

The floor is now open for questions. [Operator Instructions.] Your first question is coming from Scott Fuller of Morgan Stanley.

Please go ahead.

Good morning.

Good morning, Scott.

I had a few questions, I wasn't sure if Duane Radke was on the phone, wanted to go a little bit on the E&P and cost pressures in the industry.

When you put out your may IR presentation, or update book, the finding and development costs, DDA assumptions, and LOE assumptions, what I wanted to understand is most E&P companies in North America are projecting finding and development costs potentially rise by 10% to 15% per year over the next couple of years, and I wanted to understand where the cost pressures are, potentially, the greatest, and where the potential offsets may be at Dominion to not realize that type of inflation?

Or, is there any change to the assumptions that were laid out a few months ago in terms of those cost pressures in the industry?

Glen, could you answer that, please?

Sure, Scott.

First of all the guidance we gave for F&D costs were $1.75 to $1.85.

We are still staying with those numbers.

For DD&A, $1.40 to $1.50, and for LOE, $1.10 to $1.20.

We have not changed our guidance.

We are certainly seeing the cost pressures.

I think the difference that we are seeing in a lot of areas, and I will talk about LOE first in the operating expenses, the true lifting costs, because we drilled so many wells in our gas factories, the incremental MCFE that we produced actually comes in below.

So even though we are seeing cost pressures increases, the incremental well that we drill comes in below the average.

So that's one way we are certainly offsetting it.

The other, and the other thing is certainly the same thing is set for the F&D cost because we drill so many in the gas factories we are able to standardize a lot of our equipment and really reduce the cost.

So we haven't changed it and certainly the DD&A is at the low end of the guidance, but we do see the price increase pressures.

But, Duane, I think the guidance I am talking about is just '05 guidance.

As you all think about '06 and '07, should we be building in inflation of some rate or is there enough going on with the projects on land to potentially offset the inflation offshore, or?

We are talking about, I mean we haven't given any guidance beyond the '05.

We will be doing that in the fourth quarter.

We are certainly seeing price increases.

Well, thank you.

Thank you.

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

Please go ahead.

Thanks.

A couple questions.

Just on the explanation you gave around the quarterly earnings gives and takes, just to summarize it so I understand it correctly, the PJM integration allowed you, caused you, allowed you guys from time to time to run more efficiently.

But when you had to run your oil and gas plants because of the new PJM rules that was, you were compensated for that through the FTRs, left you burning less coal and then you were that able to sell the credits into the market.

Is that a fair regurgitation of the explanation?

I think that's fair, yes.

The sale of the credits is in part due to the operational excellence of our pollution control equipment.

We spent a tremendous amount of money -- we determined a few years ago not to get into a fight about pollution control.

We installed them early, and they run extremely well.

And it is through their excellent operation, along with the fact that with our experience in PJM, that we are dispatching some of the particularly the mid-merit coal units less that allows to us take advantage of these credits which we are creating through our excellent operations.

So this is one of those advantages you alluded to being a part of PJM when you first joined several months ago?

Yes.

Thank you.

Two other questions.

First on cash flow for the quarter.

There were a couple of items that I was hoping could you explain.

The 163 million in deferred revenue in the quarter, and then 323 million in margin deposit, asset and liabilities, could you explain those entries?

Greg, we have an increase of about 100 million in cash margin out for the quarter.

It is to support the hedges that we have.

We actually have about 300 million in cash total in margin outstanding that we think we can reclaim in the last half of the year.

So we think some of that is temporary and will be reversed in the next two quarters.

Thank you.

Then the last question was, there was just under $1 billion increase in accumulated other comprehensive loss.

Can you explain that as well?

There was no change quarter to quarter.

It is about 1.9 billion, 1.930 billion at the end of the second quarter.

It is temporary in nature.

It is primarily the result of all of our hedging activity.

And it will of course come back as those hedges sell.

Thank you, guys.

Thank you.

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

Please go ahead.

Hi, guys.

Hi, Steve.

A couple questions.

First, just a sense, the business interruption proceeds that you've received, I guess $0.26, how much was that above what you had expected for the year?

Steve, the way we characterize that internally and externally is we had changes in both what we expected from business interruption and what we saw was lost production, and that settlement included compensation for what we expected, as well as what came up between then and the time we settled.

So we have been compensated for all of the lost production due to the storm.

When you net out the insurance proceeds and lost production it's what we expected for the year.

Could you remind us what that was?

We didn't spell it out with total for the year.

I think we gave first and second quarter guidance and that was about it.

But if we've reconciled production, lost production insurance proceeds, and they come out to where we would expect it to be when the year began.

Okay.

So in other words, part of the benefit of this business interruption covers lost production you saw even in the first and second quarter of this year going back to Ivan.

That's right.

And the delay in getting Devils Tower fully up and running, and all that, that's how you're looking at that?

Yes.

Okay.

You've had good performance in Q2 and expecting Q3 in producer services, can you talk about what you are doing there to see better performance?

Steve, partly it is performance of our plant we own at Hastings, but a large part of it has to do with the fact that we, is the price differentials you are seeing in the market.

We know this is all done in Appalachia, where we have pipelines gathering systems.

We produce oil and gas and it's our knowledge base there and our contacts that has a large parted to with it.

We have, we've done very well with it this year and we expect to continue to well with it as the year progresses.

So it's like a basis spread benefit essentially?

Yes.

And it's sustainable?

Yes.

Okay.

And it does look like in your forward projections that you give on hedging that the amount you need to cover your Virginia Power, gas oil and coal, has gone down versus prior numbers.

Is that due to benefits of PJM?

Or is it something else?

It's largely due to the benefits from PJM.

And the way that we have been dispatching our plants.

Our actual full usage may decline next year.

We will have to see how that goes.

But part what have we are doing, remember, is we show it on an economic basis.

So as oil and gas prices rise that means we may be dispatching oil and gas units less.

And that's why when we show those hedges we are doing it on a financial basis.

So, as I said, when oil and gas prices go up you see the price differential between coal and oil and gas changing, and that may affect the way the plants are dispatched and the way we are saving oil and gas production to use as an internal offset.

Right.

As we go through the year we may do some more, take advantage of that spread, we haven't done very much of it right now because we are watching it very closely.

Okay.

And then last question would be, excuse me, last question would be, just you did not, in this presentation, update some of the '07, '08, kind of earnings upside data, that you had in some other once?

Is it as simple as just adjusting prices, again the rest of the data looks relatively similar?

I would say yes, the reason we don't do that is because we know everybody else out there is doing that, and you can see the price deck on April 15, which is the last time we talked about the price deck, today is quite different and it is higher.

Our internal feeling is that we are concentrating the third quarter of '05, and then each subsequent quarter, and at '07 and '08 are out there for awhile and we are already primed and loaded for those years.

So we are not fantasizing about current strip prices or anything like that.

We are just staying in the moment, so to speak.

But we don't sit around here and run those numbers every day, but they are looking kind of large.

I actually had one last quickie.

The hot weather we are seeing in July, so far, if we just think about your position with PJM, with Virginia fuel, with gas prices high, et cetera, the whole net of it, should we view you being a beneficiary of this weather conditions, and such, or not?

I'm glad you asked that question because I expected someone to.

We have to take a look overall, and overall, our total generation fleet is in more than one weather area and it looks like July was a hot month just about everywhere we operate.

So in extremely hot weather in Virginia, we have base rates that are going up and, of course, we have summer differential and our units have operated well but, obviously, the cost of fuel goes up.

So as we said before, I think we said way last May, that extremely hot weather on a margin might not be quite as good as it used to be for us, but also you take a look at the Midwest and the New England, and, overall, I would say that hot weather in all of that generation fleet is still a positive if it covers June and later.

You might just want to answer for Virginia is the power generation fleet as a whole, it is positive.

Okay.

Thank you.

Thank you.

Your next question is coming from Paul Fremont of Jefferies.

Please go ahead.

My question has been answered.

Thank you.

Thank you, Paul.

Thank you.

Your next question is coming from Mark Levin of Davenport.

Please go ahead.

Thank you.

Two big picture questions.

The first has to do with your approach to hedging going forward.

It looks like you didn't add many hedges from the first quarter to the second quarter.

And then I'm curious as to what the strategy is there?

My second big picture question has to do with your storage pipeline and LNG facility.

Has there been any discussion about the possibility of creating a master, or Limited Partnership, or spinning off those assets into, or selling those assets to an MLP given the multiples that those types of companies are trading at?

Thanks.

Mark, Tom Chewning.

I will answer the second part and then I will turn the hedging question over to Tom Farrell.

We are always looking at opportunities to increase the value to our shareholders of assets we hold.

Certainly the MLP phenomena has really accelerated.

There's a lot of money in that area.

We are constantly evaluating those things.

We have also, we evaluate a lot of things we never talk about.

We adopted a policy that we don't say anything about any possibility until it becomes a reality.

But I can assure you that we are not asleep at the switch, and we do take a look at MLPs, and other transactions that are potentially, enable us to improve our return on invested capital.

But until we, until we actually have anything in hands we do not comment.

I am going to ask Tom Farrell to talk about our hedging position and philosophy.

We actually had, have had some hedges in New England generation.

I think that's probably the only, if anything, notable that you will have seen quarter over quarter.

And it is consistent with the policy we announced in the last call, which is to go into a year, 65% to 80% hedged as we roll out of one year into the other.

And then less two years out, less three years out.

And the numbers where we sit right now are, we believe are consistent with that philosophy and we will continue to take a closer look at this as we go along through the year, and as we approach 2006 you should expect to see us as we exit '05 going into '06 at about those levels for '06, '07, and '08.

We are going to try to average in, which is different from what we have done in the past.

Thank you.

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

Please go ahead.

Just a little more clarification on the BI proceeds.

Does this imply that we had $0.14 of hurt in the first quarter?

No.

It's not related.

The settlement is for the entire business interruption claims due to the event of Hurricane Ivan.

That is actually even ongoing.

So it's not just a reflection of what happened in the first and second quarter.

It's also a reflection of delays that we've experienced related to use of the smaller rig, et cetera, that are still occurring in the third quarter and fourth quarter.

So it's some projection, as well as recovering some previous delayed production.

So the settlement is 2005 is now closed from a BI perspective?

That's correct.

And then the $0.10 from EA sales, what happened to your inventory?

Is this $0.10 what you were actually able to realize through optimization activity in the quarter, or did you dip into inventory?

A little of both.

We saw very high prices and we decided to do take advantage of them.

We are also creating adding to those banks as well.

So we are in great shape in terms of emission.

We are not even close to having a problem with that bank.

We still have excess emission credits over what we expect to use in those banks.

You basically through your early adoption of, early installation of environmental equipment, and your optimization by going to market and avoiding coal burn you are generating EAs?

That is correct, on an ongoing basis we will create emissions credits, emissions allowances.

Thank you very much.

Thank you.

Your next question is coming from Devon Gaygon (ph) of DLT (ph).

Please go ahead.

Hi, thanks for the time today.

Just wanted to ask a quick question on your two and three T reserves, a lot of other companies have been disclosing it slowly.

Want to try and get a sense for what the likely probable reserves were on top of what's booked in the 10-K, as of the end of the year?

Duane, would you answer that, please?

Sure, Devon, how are you doing?

I think the last time you came together we were at a little over three Ts of probable and possible reserves.

We have not updated that.

We are in the process of doing that and when we finish it at the appropriate time we will show that.

Is there any way to get a break down between what's probable versus possible in that three?

Sure.

We have that.

We will post it to make certain everybody receives it.

Great.

Thanks so much.

Thank you.

Your next question is coming from Tom O'Neill of Citadel.

Please go ahead.

Good morning.

Just had a question on the Virginia fuel true up.

How should we think of the emission credit sales and the FTRs?

Are those trued up in 2007, as well, and they will help offset some of the requests you will be making?

The emissions credits don't run through the fuel clause.

The sale of the allowances don't run through the fuel clause.

FTRs run through a separate line item, which is the energy supply margin you see there on Schedule IV.

When we have talked in the past and we are not going to spend a lot of time talking about '07 and '08 today.

But when we have talked with you all about that in the past, we have said we are going to see how we do, and we are going to see how our experience goes in PJM.

We think we know how it's going to go.

Certainly, the first three months, May, June and July, have demonstrated to do us that it's coming in as we expected.

So we believe that we will continue to enjoy the benefits of that dispatch protocols as, with our frozen fuel clause working together through the period.

Thank you.

Thank you.

Your next question is coming from Mark Reider of Partner Ree (ph).

Please go ahead.

Yes, hi.

Given where you are now what's your expectation for year end debt to capital?

We have, this is Scott Hetzer, we have projections for the end of the year of 50.8% adjusted.

We are comfortable with all the components that make up that credit ratio except for AOCI, which, as we pointed out in our response to an earlier question, is $1.930 billion negative at the end of the quarter.

And we don't try to project what that's going to be because it involves of course commodity pricing.

So excluding AOCI, we are comfortable with every number that's out there on our projection for debt to cap.

Okay, and as far as this fourth quarter EMP forecast, it seems to assume that there is no storms.

We're hearing projections it's going to be a bad hurricane season.

Is there any head room there?

What's imbedded in that that number?

There is a modest amount of head room set aside in the range that we have given you in the 440 to 445.

We are not counting on just because we had early hurricanes that that's the end of it, so we normally experience these hurricanes later in the season than we have in 2005.

So we adjusted for that.

And lastly, just any thoughts how this energy bill could affect Dominion?

Obviously, the repeal '35 Act is beneficial from a paperwork reduction standpoint.

It's not going to change the way we do business.

There are a number of very beneficial financial pieces to the energy bill that we are examining closely to see what advantages we can take of those, if any, but sitting here today we don't have any change in guidance or forecast we are going to be able to give you because of the adoption of the energy bill.

Thank you.

Thank you.

Your next question is coming from Eric Mendelblaugh (ph) of TVG Axon (ph) Please go ahead.

Hi.

Good morning.

Hello, I was hoping you could compare the 2006, 2007, 2008 gas, oil and round-the-clock [inaudible] prices today relative to the disclosures you gave us on April 15?

Eric, this is Joe here.

I've got them as of the end of July, compared to April 15.

Starting with natural gas.

The increase in 2006 is $0.97, '07 and '08 are $1.02 and $1.08, respectively increase.

Oil has increased $11.20, $11.97, and $12.38, respectively.

Coal has gone down $3.88 at the time in '06 is level with '07 and it has increased $1.00 in '08.

Neepool (ph) has increased in a range of $3.32 to $7.45, escalating over those three years.

And PJM has increased $3.95 in '06, going up to $4.62 and $7.13 in '07 and '08, respectively.

I know that was kind of fast but those were orders of magnitude.

Perfect, thank you.

Okay.

Thank you.

Your next question is coming from Teresa Ho of Saranac Capital.

Please go ahead.

Thank you.

My question was asked and answered.

Thank you.

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

Mr. Chewning, do you have any closing remarks?

Thank you, Ashley.

I would like to thank everybody for joining us this morning.

Our second quarter 10-Q will be available after 4 p.m. this afternoon.

And a reminder, our third quarter earnings release and conference call is scheduled for Thursday, November 3.

I hope you enjoy the rest of your day.

Good morning.

Thank you.

That does conclude today's teleconference.

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

Good job, guys.