道明尼資源 (D) 2005 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to Dominion's third 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 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.

Thank you, Lindsay.

Good morning, and welcome to Dominion's third 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 third quarter, compare actual third quarter results to our forecast and provide earnings guidance for the fourth quarter.

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

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

Concurrent with our earnings announcement last evening, 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 our quarterly earnings release or to pages from our third quarter earnings release kit posted yesterday to our website.

I particularly call your attention to the supplemental Q & A outlining hurricane related effects on operations and financial results.

The 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 the measures about our Company's performance that differ from those recognized by GAAP.

You can find the reconciliation of these non-GAAP measures to GAAP on our Investor Relations website under "GAAP Reconciliation."

Outside of the consequences of Hurricanes Katrina and Rita, Dominion had an excellent third quarter.

Our $1.08 per share operating earnings would have been $1.28 per share had not the storms cut net income by $0.20 per share.

All operating activities outside the Gulf performed to or above our expectations.

Dominion is required in the FAS 133 to dedesignate all hedge volumes shut in by the storms for the period of time until production is expected to resume.

Accordingly, we took a $357 million charge, which reduced GAAP earnings to $0.04 per share for the quarter.

Approximately 37 DCF equivalent was dedesignated from expected 2005 production and about 23 BCF equivalent from 2006.

The dedesignated hedges will be subject to mark-to-mark accounting identical to the accounting treatment on our corporate hedges entered into during 2001, 2002, and 2003.

The dedesignation charge should be recovered over the next five quarters as income is recorded from business interruption insurance proceeds and through the resumption of gas and oil production.

Katrina and Rita will also negatively impact our expectations for the remainder of 2005.

Our guidance for the fourth quarter of 60 to $0.70 per share would have been $1.35 to $1.45 per share had not these hurricanes reduced our expected quarterly net income by $0.75 per share.

Dominion's full year results should have been within or above our full 2005 earnings guidance range of $5 to $5.10 per share if we were able to realize the $0.95 per share which will be lost to production delays in the third and fourth quarters.

Commodity prices spiked during the quarter as a result of significantly curtailed oil and gas production in the Gulf.

This increased the cost of fuel used to generate electricity in [INAUDIBLE] generation plea.

However, as Tom Farrell will cover later, positive factors within Dominion Generation substantially offset this impact.

Another consequence arrived in commodity prices was higher margin calls for our financial hedges on electric and oil and gas production.

Dominion expanded its available sources, met all collateral calls, and finished the quarter with $2.3 billion in liquidity.

Coverage ratios and debt-to-cap ratios also suffered as the storms reduced anticipated cash flow and rising commodity prices created a $1.2 billion negative mark-to-market charge to accumulated other comprehensive income.

Funds from operations to interest was 3.9 times for the trailing 12 months.

Debt-to-cap was 59.6% at quarter end.

Katrina and Rita have caused a temporary detour in our normal earnings patterns for 2005 and 2006.

Our fourth quarter guidance includes no business interruption income nor any potential mark-to-market impact on income arising from the hedge instruments dedesignated in the third quarter.

If either of these items recorded during the fourth quarter our actual operating income will differ from the 60 to $0.70 per share guidance given earlier.

In regards to our previously offered 2006 earnings guidance of $5 to $5.25 per share, we would expect that range to rise.

However, we won't update 2006 guidance until our January 26th, 2006 earnings call, as we cannot predict potential income impacts in this year's fourth quarter from insurance proceeds, mark-to-market adjustments, or the potential for greater oil and gas production from shut-in wells than we have projected.

In short, we have a good handle on what to expect for income over the next five quarters, but no good way at this time to predict in which quarter of 2005 and 2006 this income will be recognized.

I should also point out we are tracking our 2005 guidance for capital expenditures, free cash flow, FFO-to-interest coverage, and total debt to total capitalization ratio.

The number of potentially variable items between quarters makes forecast of these year-end numbers unreliable.

What we do know is that all the earnings drivers we assumed in forecasting substantial higher levels of operating income for 2007 and beyond are in place, including our projected level of oil and gas production.

The storms have not changed our longer-term prospects for increased operating income, growing cash flows, and improving financial metrics.

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

Tom?

Thanks Tom and good morning, everyone.

Dominion operations continue to perform at or above expectation.

With the sole exception of the delayed earnings caused by the hurricanes each business unit performed at or better than we expected in setting our yearly goals.

To state the obvious, Dominion faced challenges in the third quarter as a result of Katrina and Rita.

Both hurricanes were category 5 storms while in the Gulf of Mexico.

Katrina made landfall on August 29 as a Category 4, Rita on September 24 as a Category 3.

These events not only disrupted the natural gas and oil business industry-wide, they had a large impact on our work force. (Cough) Excuse me.

Our Louisiana-based employees, numbering over 400, were displaced by Katrina.

It took about nine days before all were accounted for.

We went to work immediately to relocate our employees and their families to Houston and we now have approximately 350 residing and working there.

At the same time, we were taking care of -- the same time we were taking care of our employee relocations, we deployed over 500 line and contractor personnel to assist in the restoration of power in Louisiana.

In terms of our business, Dominion sustained only modest physical damage to its Gulf of Mexico facilities.

The primary impact of the storms was to the downstream infrastructure upon which Dominion and the entire E&P industry operating in the Gulf of Mexico are dependent.

Damage to the Empire Terminal in south Louisiana as well as various gas processing facilities along the Gulf Coast represent bottlenecks, keeping large portions of available off-shore production shut in.

Even so, our off-shore group is doing everything possible, investigating every alternative to reestablish production from this important region.

For example, in the third quarter Dominion completed the subsea tie-back of the Triton and Goldfinger wells to Devils Tower.

These wells are ready to flow, pending downstream infrastructure.

Deepwater completion programs progressed at Devils Tower with the recompletion of the A2 well and at Front Runner with the recently announced A4 completion.

Development work at the Rigel and 17 Hands wells continued with the delivery of the umbilicals.

These wells would have been ready to produce this month but will remain shut-in pending repairs to the host facility.

On the shelf, an exploration well at West Cameron 77 was drilled and is currently being tested.

Also on the shelf, the Main Pass 270 A2 development sidetrack was completed.

You may remember that Main Pass 270 was our one operated platform that sustained significant damage during Katrina.

We expect repairs will be completed and that it will be ready to begin production by year-end.

Dominion would currently be producing about 700 million cubic feet equivalent per day offshore were it not for the storms.

Of this amount, approximately 230 million cubic feet per day, including temporary measures, is currently on-line.

With the majority of the remainder waiting on rehabilitation of downstream infrastructure.

If all of the third-party infrastructure was available today, we could produce about 560 million a day.

In other words, about 140 million a day is shut in because of damage to our platforms.

Almost all of which will be repaired by year-end.

We do not expect any impact on 2007 and beyond production targets, which remain forecast at 5 to 6% average growth from '06 through '08 as shown on Page 30 of our third quarter '05 Earnings Release Kit.

Following Rita, we began to post on our website weekly updates of our daily production rates.

We will continue to do so until a substantial amount of our shut-in capacity has returned.

On shore, our programs continue to exceed forecast through the first three quarters of 2005.

Through the third quarter of this year, Dominion had drilled 682 net wells and is on pace to be one of the U.S.'s top drillers for 2005.

Just recently, Dominion was named the most active driller in the United States in 2004 by the Oil & Gas Journal.

We will continue to expand our on-shore programs.

Dominion Energy's third quarter was highlighted by solid performance from the Producers Services group and the continued success of the Cove Point LNG business. [INAUDIBLE] services is the portion in the clearinghouse that is reported through Dominion Energy and includes field services and natural gas aggregation and marketing.

This group earned $13.5 million during the third quarter this year compared to a loss of $42 million in the prior year or a $56 million year-over-year improvement.

The losses in the year-ago period resulted from proprietary trading activities, which were discontinued as part of the late 2004 restructuring of clearinghouse.

Also during the third quarter, Cove Point continued its leading position in the LNG import business, accounting for more than 1/3 of the volumes imported into the United States.

Cove Point has been the number 1 import facility in the country since it was reactivated in 2003.

As you know, we plan to expand Cove Point.

The expansion will add about 7 million decatherms of LNG storage on-site and nearly double Cove Point's deliverability and it is proceeding according to plan.

This past Friday, a favorable draft and environmental impact statement was issued which recommends commission approval of the project.

We hope to receive the final FERQ certificate during the first quarter of 2006 with construction beginning shortly thereafter.

In our Electric Delivery business, we continue to benefit from Virginia's robust economy.

During the third quarter, we connected nearly 3% more customers than we did in the third quarter of 2004 and 10% more than the third quarter average for the four-year period 2001 through 2004.

Our Generation business continued to have excellent operations in the third quarter with a nuclear capacity factor of 98.5% and fossil and hydro plant availability of 92%.

Both of these indicators remain at or near Company records.

This performance was critical as we saw degree days 26% above normal, making this one of the hottest summers on record in Mid-Atlantic.

In fact, we set four new peak load periods this summer, topping at just under 19,000 megawatts on July 27th.

Our first summer operating PJM was in line with our expectations.

We were a net buyer with all of our units needed for native load supported by daily purchases.

Because of the summer loads, we did not see the ramping of our coal units as we did in the second quarter.

The increased demand due to extreme weather, combined with a sharp rise in commodity prices fueled by Katrina and Rita, drove Virginia fuel expense above guidance, but as outlined in Schedule 4, the Company was able to offset entirely this higher fuel expense through four drivers: First, electric utility revenue increases due dot hot weather; second, emission sales.

Now, with respect to emission sales, we have taken advantage of higher prices, to monetize excess allowances as part of our effort to mitigate our fuel expense.

We will continue this strategy from time to time with regard to excess allowances as conditions may dictate, but not necessarily each quarter.

Third, energy supply margins-- these are largely the financial transmission rights, or FTRs, we discussed in the second quarter.

FTRs are designed to cover congestion costs and are granted by PJM to load-serving entities who are not able to dispatch at their economic capability because of congestion on the grid.

As in the second quarter, FTRs worked as intended in the third.

And fourth, merchant generation margins, primarily from our New England and PJM operations.

Several other items of note in our Generation business since our last update include: Our coal hedges for 2006 increased from 66% to nearly 80% for Virginia Power.

Our average hedge price is significantly below current spot-market prices.

Millstone 2006 hedging increased from 85% to 92%.

North Anna 2 just completed a fall refueling outage in 28 days, well ahead of schedule.

Millstone 3 just completed a fall refueling outage also in 28 days, the best in its history.

We announced this week a nud (ph) contract restructuring with Cogentrix, which will provide approximately $50 million in savings over the next 10 years at no cost to us.

The majority of these savings are in reduced capacity payments.

This continues our ongoing effort to reduce above market capacity payments with our non-utility generators.

Finally, we continue to receive inquiries about the 2007 reset of our fuel rate in Virginia to reflect current market commodity prices.

There has been no change in our views.

As we have said previously, the case will be like all other fuel cases over the last 30 years with only two exceptions: The reset will cover 42 months from July 1, 2007 until December 31, 2010 rather than 12 months; and there will be no true-up to reflect our past under recovery.

We have noted that a number of other utilities have filed for fuel increases, which we believe are much larger than the one we will seek, whether because of their fuel mix or because they have a large prior period under recovery or both.

For instance, one company is seeking an annual fuel rate increase of about $2.2 billion.

If approved, this would raise the typical monthly residential bill nearly 16%.

Another has requested a rate increase that would boost the typical monthly residential bill by nearly 19%.

That utility attributes the increase to rising natural gas costs.

Depending upon which 2005 forward price curves for the reset period you choose, we would expect to seek an increase at levels well below those utilities.

This relatively small increase will be the first fuel increase for our customers in 3 1/2 years.

Of course, our customers also are enjoying frozen-base rates until the end of 2010.

We have been treated fairly and professionally on fuel cases for decades and don't expect anything different in the next case.

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

Lindsay?

Yes, sir. (Operator Instructions) Our first question comes from Greg Gordon with Citigroup.

Sir, please go ahead.

Thanks.

Good morning.

Good morning, Greg.

So, would it be fair -- a couple questions.

It would be fair to say that the reason that you lowered your guidance so aggressively for the balance of the year is simply because you can't count on the timing of your business interrupted insurance proceeds?

That is correct.

Second question: I know you've endorsed still a fairly bullish outlook for production growth in '06, '07, '08, but can you please comment directly with regard to the disclosures made by some of your partners on the changes to the outlook for the Front Runner project and how that directly im -- impacts your -- your expectations?

Sure.

Greg, this is Duane.

Good question.

First of all, on Front Runner, as we put in the website questions in our press release, of the five wells completed to date, three are underperforming forecast as to what we had.

The implications of that are that we'll have less production over the next couple of years than we originally forecast, and that actually, we're taking into account in our guidance for 2007.

But it doesn't mean we're going to have any change in reserves; it just means we're going to take a longer period of time to recover those reserves.

In fact, in -- in the analysis that we did, our most likely reserves are actually in excess of what we booked.

So I mean, that's just the normal course of what we do.

And you have to remember, Front Runner is a very small component of our reserve base, and we have offsetting positives both at Sonora, western Oklahoma, South Texas, even some of our shelf production that's offsetting those losses.

So we never look at one asset, we look at the whole portfolio.

Thank you guys.

Thank you.

Our next question comes from Steve Fleishman with Merrill Lynch.

Sir, please go ahead.

Yeah, hi.

Good morning.

Hi, Steve.

Couple questions.

First on the business interruption insurance.

Did -- you -- in your release, you mentioned there's caps on that for each of the storms.

Do -- do those caps cover the deductible period as well?

Are those --

No, they -- they're separate, Steve.

Okay.

At the maximum amount that we can call for each wind event.

I will say just right off hand, though, that we don't expect that those caps provide any restraint on us -- on recovering our anticipated losses to Katrina or --

Okay.

And then I know with Ivan, the storm occurred in last year's third quarter and you got most of the money by first half this year.

Any reason the timing should be much different this time?

We really can't answer that.

That's up to the underwriters.

I think there was -- they've got their hands full with an awful lot of claims from Katrina and Rita, so we might have more people knocking on their door and that might administratively take them a little longer.

We'll going to continue to process our claims the way we always have on a regular basis, and certainly, you know, they'll get to them as soon as they can and we will be cooperative to make sure that we reach settlement as soon as we can.

They -- they were very cooperative the last time, and actually gave us periodic payments, and -- but we -- we have no way of knowing this time because we really haven't submitted a claim yet.

Our deductible periods are over, at least with Katrina, and they will be over early next week on Rita, on Monday, but we don't really put a claim in on first day.

We -- we -- you do it periodically, we'll be doing one probably in late November.

Mm hmm.

And -- and then on a separate topic, in terms of the '07 production being on track, one would think to the negative you you -- have a -- it's probably harder to get rigs to -- to get to that from what you had initially planned.

But on the other hand, maybe the decline rates that you thought before you'd have in the Gulf are now going to be extended out.

Is that how you're still comfortable with the oil production forecast?

Yes, Steve, this is Duane.

We -- we have the rigs contracted in almost all cases and in a few instances we're even tying some up in -- in longer-term contracts where we know we're going to be busy for the next couple of years.

So we're not -- although we certainly have to go through all the issues of logistics around acquiring rigs, we -- we take that into account in our forecast.

Okay.

And then how about in terms of just expected future costs of the business?

Cert -- certainly higher.

You know, I think as part of the January call, we will give you what our new incremental F & D costs will be going forward.

Yes, we'll take that into account based on the cost increases we've seen.

Okay.

Thank you.

Thanks, Steve.

Our next question comes from David Maccarrone with Goldman Sachs.

Sir, please go ahead.

David?

Hello.

Yes.

David.

We can hear you, sir.

Okay.

What drove the $0.40 increase in Virginia Power fuel versus expectations?

Can you kind of break that down into weather versus maybe some of the emissions allowances?

And what can we expect going forward from -- from the fuel cost?

This is Mark McGettrick.

In terms of the third quarter fuel, we were about $139 million under-recovered.

Breakdown on that is about 50 to 52 million in hotter weather and sales, and on commodity prices about $84 million for the quarter.

In the fourth quarter guidance we've shown our assumptions forecast in -- in oil prices and we're looking to have gas and oil in combination about 10 BCFE for the fourth quarter.

So the driver is predominantly on the gas and oil side?

And purchased power, which is driven by gas.

Right.

And then on the E&P side, what's driving the better than expected performance out of Western Oklahoma and South Texas?

Dave, this is Duane again.

A couple of things.

If you remember a few years ago, we bought some assets in Western Oklahoma and used it as a base of expanding and acquiring quite a bit of acreage in that deeper Anadarko trend and we have four rigs running in that trend right now and we've had a great deal of success for the last year.

And to put it this way, the -- the -- the incremental production rate per dollar spent is higher in Western Oklahoma, say than some of our other areas.

So we've reallocated some capital to there and we -- and that's why we're picking up some production.

Same thing in South Texas on a couple of things.

We've had some development field opportuni -- in-field development opportunities that we've accelerated, and we have some discoveries that we've had in the last couple months that we'll build -- will build on next year.

So all of those programs are just going great at this point in time.

Can you quantify for us how much production impact there's been relative to expectations and how much capital you're shifting between the segments?

From -- I think the year-to-date to Western -- or Oklahoma, I think we expect the Oklahoma group to be up almost 10 B's for the year.

I don't have the data here on shifting capital, but it's still within our total capital budget.

It's not like we're moving $100 million.

It's -- it's two rigs versus four rigs type of thing.

And what's the -- the base production in Oklahoma roughly?

I don't have it here by state.

I mean, we're -- we're operating about 500 million cubic foot a day out of Oklahoma.

Okay.

And switching back to the power.

Just want to make sure I haven't missed something here on this -- on the emissions rounds position.

You have not provided any metrics to understand the inventory or the inherent long position that's generated over time, is that accurate?

That's accurate.

Okay, thank you.

Our next question comes from Paul Ridzon with Key McDonald.

Sir, please go ahead.

Previous to the hurricanes, kind of the sum of '05 and '06 is maybe 5.25 or -- or $10.25 of earnings.

Is -- is that still intact or do we need to think about that with regards to deductible periods?

I think we feel it's still intact.

I mean, the lesson here is that we have delay rather than lost cash flow and income.

And so we -- we -- we really think that we still have the gas, we -- it will be produced and what we don't produce during this period where we've given you this two years' guidance, we will -- we should be recovering insurance -- business interruption insurance.

So yes, we haven't lost anything.

It's just kind of been squeezed from one part of the balloon to the other.

A separate question.

As you look at kind of the -- the price drip into '07 and '08, how -- how do you view that relative to kind of your fundamental view?

And -- and how does that influence your hedging strategy?

The strip now is -- is not inconsistent with our fundamental view, it might be I'd say a little higher than our fundamental view.

We will continue to hedge along the same path we announced earlier this year, which is, you should expect to see us 65 to 80% hedged as we go into a year.

So as we exit '05 going into '06, you ought to see us in those levels, about 20% less two years out, and 20% less three years out.

We still are not completely consistent with that as we roll into '06 because of the prior hedges that we had put in place, but that -- that's what you ought to expect to see as we go along.

We're going to continue a hedging program, but shaped in the way we have previously discussed.

As you see events like Katrina kind of maybe push things beyond fundamentals,do you -- are you willing to deviate from that strategy just to be opportunistic?

We are considering different ways of hedging instead of doing yearly strips.

We're go -- we're looking at other ways of hedging, and we don't always do yearly strips.

We ha -- the older hedges were yearly strips.

There are different ways to deal with that, and we are -- all of that is under consideration as we have -- as we come into a period when more is going to be available for us to -- to have more flexibility.

And I think yes, if we felt there was a serious disconnect between our forecast of what we think prices are and what the market is paying, we would take advantage, but we're not going to put all of our money on -- on -- on one day going out.

We -- we're going to try to average in.

Thank you.

Thanks, Paul.

Our next question comes from Dan Eggers with CSFB.

Sir, please go ahead.

Hi, good morning guys.

Hi, Dan.

Hi.

First question, just help understand the business interruption insurance a little better.

You have a 30-day lag on the first hurricane, then 45 on the second.

Is there any way to -- to parse out what volumes out of -- out of the pot you guys have lost or associated with each storm?

Just trying to understand what the gap may be.

First, I don't think there's a gap.

We -- we had coverage in both places -- both -- for both events.

One was on one policy or Katrina, and the second was on Rita -- was on the second.

We haven't gotten that full breakdown yet, but I think that -- that there's enough capacity under either policy for us to safely say that we're going to be adequately covered.

We don't really have a gap in coverage.

We do have a step down from the Katrina 700 million to 350 million for Rita, but obviously, much of our damage was under Katrina, much of the delay for the infrastructure under Katrina.

So the -- the hurricanes perform more or less like the limits of our policy.

Okay.

Maybe just for Mr. Farrell, but philosophically thinking about how you allocate spending dollars to E&P in the future with costs on the rise, I know -- know you guys don't want to talk about it today, but with costs on the rise, commodity prices higher, how are you guys thinking about allocating capital back into E&P?

Is it on a reinvestment of cash flow generated basis?

Is it a return on capital basis?

Or is there something else fundamentally driving that versus -- it used to be $1 billion cap on CapEx?

We, Dan, look at both factors that you just mentioned.

We are getting our highest returns right now in E&P, so obviously, we have to take that into consideration, but we have many other calls in this Company on capital.

We have the Cove Point expansion coming.

We have record new customer growth in Virginia.

That takes capital to hook up the new customers.

We're spending capital in installing pollution control equipment in New England.

So there's lots of areas where capital is required and it's -- that -- we don't have all we want, so we have to allocate it, and we will continue to do that, but we -- first dollars come out of our capital go for plant, safety, and ma -- taking care of our customers.

Then when it comes to what we can do for growth, we take a look at, we're going to sit and we sit as a team and allocate it out as we go through the year, and we're flexible as we go along, but that there's certain requirements we have that aren't going to change as we go along.

And also, Dan, I'd just like to add that I think we -- we don't have any intention of reducing our drilling program because prices have risen.

We'll just find the capital necessary to replace and grow our production and reserves.

Great.

I guess one last question on the emissions credit side.

Historically, how much has -- have these sales contributed, or is there a way to kind of gauge how much money on a conceptual basis comes in from that piece?

I know it doesn't come every quarter but just something we can gauge?

Dan, this is Barry, over the years from quarter to quarter, we see -- we have excess allowances in banks.

We create excess allowances when our pollution control equipment performs better than expected.

So when we see a really high -- we see a good price, we saw some very good prices in the third quarter, we will go ahead and take advantage of that as we go along, but as I said, it's not -- we're not going to necessarily do it every quarter.

We -- it's more opportunistic monetization of those -- those assets.

Got it.

Thank you, guys.

Thank you, Dan.

Our next question comes from Michael Goldenberg with Luminous Management.

Good morning, guys.

Hi, Michael.

Hi, how are you?

Just try -- still trying to understand a couple of things.

The business interruption insurance most likely will come in 2006, making your numbers higher.

I mean I understand there is no guidance, but versus original anticipation, that shift should increase the 2006 numbers.

Is that -- am I correct in understanding that?

Yes.

Okay.

Secondly, I wanted to talk about Virginia fuel costs.

The high price, since your revenues are fixed, obviously the hottest summer in all of that cost, the gross margins, should decrease offset by the FTRs.

Do you expect this correlation to continue every time that it's hot, basically, that you will see lower margins because you're paying higher for gas and mega -- and heat rate, but that will generally always be offset by FTRs?

Are they correlated?

I think I understand your question.

As we go along-- let's back up.

When the fuel is reset it's going to redeflect forward commodity prices.

As we've said before, we anticipate that we will largely hedge out the coal exposure.

Once we have that price determined, and we will have done some of that in advance of the fuel case, as we -- as we go into the case, we will have contracted for some of the coal as we -- in 2007-2008.

That'll become part of the case.

Once we have the coal price fixed, we will then take most of that off the table.

Oil and gas prices will -- they have certainly in the last few years, as you get a really hot summer, they tend to drift -- they -- they -- prices spike, and we have our offsetting positions at E&P.

And we will continue to leave more than enough E&P production available, unhedged, to match what's going on in the fuel case -- in the fuel clause -- fuel recovery, as we go out past 2007.

Michael, the other part of that -- think -- you're really asking an after-fuel reset will abnormally hot or cold weather --

No, no, I was thinking before the fuel reset if abnormally hot weather.

Since you're providing higher volumes at prices that are unfavorable to you, if FTR correlation is there or do you expect FTR correlation to hold up so whatever you're losing because you're supplying more megawatt hours, if you're going to be making in that up in FTRs?

Well, the -- the FTRs will make us hold for not so our units that are economic units not being dispatched, which is the reason it's there.

When -- when PJM decides that -- that they because of constraints can't use our units, we're -- we're compensated for that.

But if in '06 we had an abnormally hot or cold period of time, we would certainly have a negative impact, because we'd be using more fuel than normal.

All of our -- all of our forecasts are based upon normal weather.

On the other side, if it could work the other way where if the weather was milder in the winter and cooler in the summer, then we would use less fuel than normal and it would be a positive variance for us.

So FTRs generally did not make up whatever you win or make on fuel during abnormal weather?

Now -- what -- Mike, what you -- what you are leave -- leaving out is the other electric utility revenues.

As -- if it's very hot, we are -- we are selling more electricity.

That means that more is going across the big wires and more is going across the small wires than anticipated.

So you will get more revenues there.

That is one of the offsets to the increased fuel.

The other primary offset is what we've left open in our oil and gas company.

What the FTRs do for you is if you are in a situation where our Mount Storm Coal Fire plant, which is one of the cheaper plants in PJM, has 1,500 megawatts of capacity bids in and is economically ready to dispatch all 1,500 megawatts, because of congestion on the grid, we can only dispatch 1,200 megawatts that extra 300 megawatts we have to run some other unit to -- to cover the load.

The FTRs compensate us for having to burn a more expensive fuel than we otherwise would have.

Okay.

That's how that all -- that's how all those pieces works together.

I think I understand now.

And finally, one last question.

I'm sorry for taking up so much time.

On the slide -- on the page 30 where you talk about hedging.

From an economic perspective, not accounting perspective, for 2006, the effect -- effective hedges, is it 303 plus the desig -- the designated hedges or are the dedesignated hedges already included in that 303?

Michael, this is Joe.

Those are separate numbers.

The 303 equivalent are hedges that relate to the average price below it.

The 23 BCS is independent of that.

So if I add 303, 23, and everything that you use internally, you're pretty much 100% hedged for 2006, so if for some reason production was further interrupted, would you -- you would actually be short or is there more that you -- that you can do from a hedging perspective from trading so as to not end up short if something isn't -- if there's like production interruption?

Not sure I understand the --

If I add up 303, 23, and then 54 and 20 and 15, I'm pretty much at 100% hedged?

Right.

Right.

So I -- I'm just trying to understand, are you certain that 2006 production will be back on line exactly as expected?

And if something happens where it's not, ca -- can you do anything from trading perspective, like buying coals or whatever, just to make sure you're not short of gas commodity?

Michael, there's two effects there.

We are -- I believe if you look at that, we will really be in that long position in 2006 when you consider the fact that we would expect to recover revenue from delayed production through business interruption or an early retirement production.

We also would expect to hedge some additional coal for 2006, and that would take the natural hedge requirement --

Okay, that makes sense.

Of the 20 by the time we get into '06, so actually be zero or something close to zero.

Possibly.

Got it.

Thank you very much, gentlemen.

Good luck.

Thank you.

Our next question comes from Paul Patterson with Glenrock Associates.

Hi, guys, how are you?

Fine, Paul.

How are you?

All right.

Just -- just from a bigger picture question.

With the insurance costs having, obviously the insurance industry getting a little hit by this stuff, what do you think going forward is going to be the situation with respect to obtaining the insurance?

Or are you expecting costs to go -- what are you -- what are you guys encountering when you're talking to your underwriters about -- about the potential for increased costs in insurance and what have you?

Paul, this is Scott Hetzer.

We -- as you probably know, we renewed our policy as of September 1st, and after the Ivan loss, clearly, coverage went down from a limit of 700 to 350, and the cost of that insurance went up.

And of course, with the underwriters being hit again with these two large hurricanes, when we go to renew next year, we would -- we would expect clearly the cost will go up.

As far as how many of the players will stay in, we'll just have to wait and see.

But insurance, of course, is cyclical, and many of the underwriters that are taking it -- taking losses because of these storms will, you know, some of them may choose to scale back and exit, but certainly, others are going to step in and -- and want to take advantage of some of this higher-premium to write these policies.

So, it's -- we expect the -- the replacement next year to be difficult and more expensive, but we're also looking at alternative ways to -- to insure other than just going straight to the market in London.

Okay.

Okay, let me just ask you this one sort of tactical question.

Why is the gain on the sale of -- of emission credits allowances, why is that in the cash flow statement seen as a -- a non-cash item?

The reason it is is because it's -- it's listed in "investing activities."

If you look in the investing activities.

But Steve Rogers is our Chief Accounting Officer can explain to you and to me why it's not regular cash flow.

Paul, this -- this is Steve.

It's -- it's in investing activities because of where we classify it on the balance sheet.

It's -- it's -- it's classified as an intangible asset, and as a result, when it gets sold, it is down in investing activities, as opposed to as classified as inventory or something, it would be up in operating activities.

It's the GAAP convention of where we need to classify that item.

Okay -- so it -- okay, great.

That explains it.

Thanks a lot, guys.

Thanks, Paul.

Thanks.

Our next question comes from Faudi Shaddid with Friedman, Billings, Ramsey.

Hi, good morning.

Morning.

I'd like to hear more about the Generation quarter.

One -- one question I have is, revenues, non -- non-regulated sales about $1 billion, the cost number on the expense side $1.7 billion for all of Generation.

What -- what were the drivers there?

How much -- for example, how much purchase power was -- you know, are in those numbers?

Faudi, this is Joe.

The -- the detail of the segment income and so forth is going to be covered in our form 10-Q, which is to be filed after the market close today.

We're not really --

Okay.

Prepared to discuss income statement line items on the call.

Okay.

How about O & M, $68 million, why -- why so low?

Same answer.

You really have to look at the 10-Q.

I would just ask for your patience for the filing of the 10-Q.

Look at that this afternoon, and if you have questions thereafter, please give me a call.

Okay.

And -- and in general, you know, what -- what -- what plants on the merchant side did well?

What -- what were the markets like?

How were -- how did the New England fleet do versus PJM on the merchant side?

We -- the New England plants performed extremely well, as did the Fairless (ph) Work plant was dispatched a lot through the third quarter.

So it was all across -- all across the Company.

Okay, thank you.

Thank you.

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

Mr. Chewning, do you have any closing remarks?

Yes, Lindsay.

Our third quarter 10-Q, as Joe said, will be available after 4:00 this afternoon.

You'll also be looking forward to seeing many of you next week as we attend the EI Fall Financial Conference, and our fourth quarter earnings release and conference call is scheduled for Thursday, January 26th, 2006.

Thank you for joining us this morning.

Please enjoy the rest of your day.

Thank you.

That does conclude today's teleconference.

You may now disconnect.