Dominion Energy, Inc. (D) Q4 2005 Earnings Report, Transcript and Summary

Good morning ladies and gentlemen, and welcome to Dominion Fourth Quarter Earnings Conference Call. We now have Mr. Tom Chewning Dominion Executive Vice President and Chief Financial Officer in conference. Please be aware that each of your line is in listen only mode. At the conclusion of Mr. Chewning’s presentation, we will open the floor for question. At that time instructions will be given as procedure to follow, if you would like ask a question. I’ll now turn the conference over to you Mr. Tom Chewning, sir you may begin.

Good morning and welcome to Dominion fourth quarter 2005, earnings call. Joining me this morning are Tom Farrell our President and CEO and other members of our management team. This morning I’ll first review actual fourth quarter and full 2005 earnings. Tom Farrell will give his review of 2005 operations, as well as offer his perspective on Dominion's focus for 2006. Following Tom's remarks, I will provide 2006 earnings guidance and reconcile the 24 month period from January 1st, 2005, to December 31st, 2006, to the outlook we had discussed during our last call with you on November 3rd, 2005. Before answering your questions, we will offer our current perspective on the drivers that will create a significant uplift in Dominion's earnings in 2007 and beyond. Concurrent with our earnings announcement this morning, we've 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 2006 earnings guidance kit, both of which were posted this morning to Dominion's website. That website address is www.dom.com/investors Let me start by providing the usual cautionary language. The earnings release and other matters that may be discussed on the call today contain forward- looking statements and estimates that are subject to various risks and uncertainties. Please refer to our SEC filings, including our most recent annual report on Form 10K and quarterly report on Form 10Q, for 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 differs from those recognized by GAAP. You can…

Thanks Tom, and good morning everyone. 2005 operations and results met or exceeded the goals we established at the beginning of the year, except for oil and gas production delays resulting directly from hurricanes Katrina and Rita. During 2005 we successfully integrated an additional 3,300 megawatts into our generation fleet, an increase of 13%. This includes Dominion New England with units at Brighton, Manchester, and Salem, as well as the Kewaunee nuclear plant in Wisconsin. It made us the largest generator of electricity in New England. Our nuclear fleet had an outstanding year in 2005, achieving a capacity factor above 92%. In Virginia we achieved record nuclear generating performance of 28.6 million MWh compared to the previous record of 28.3 million MWh accomplished five years ago. All of our merchant nuclear plants exceeded expectations Our fossil units performed extremely well during our first year in PJM, achieving a peak season equivalent availability of 96%, the highest since 2002. At Energy, we successfully integrated into PJM effective May 1st, and met 15 new peak days without any operational incidents. We received approval for new rate structure at Dominion Transmission for a five year period, and mitigated the financial impact through operational efforts, including producer services and near record results in the gathering and by products businesses. The Delivery business in 2005 connected over 75,000 new electric and gas customers, set four new electric load peaks on its system, and saw its four year average annual growth in electric demand increase to almost 4.7%. Virginia continues to have a thriving economy. While meeting this increase in demand we were also able to improve our electric service reliability by 8%. Turning now to our E&P business. During Q4 we were able to restore Gulf of Mexico production from a pre-hurricane level of 435…

Thanks Tom. Our guidance for 2006 is $5.05 to $5.25 per share. When added to the $4.53 per share of actual earnings in 2005, the total 24 months operating earnings for 2005 and 2006 will be $9.58 to $9.78 per share. Page 4 of our 2006 earnings guidance kit reconciles this range to our 24 months outlook discussed during our last call with you on November the 3rd, 2005, which was based on our May 2005 assumptions. The projected total operating earnings of $10 to $10.35 per share less the lost income experience during our business interruption insurance deductible periods. Implicit in our projection is the assumption that other than the deductible periods, earnings related to our pre-hurricane gas and oil production forecast will be recognized either through physical production or through business interruption insurance. We now calculate that the lost income during the deductible periods was $0.25 per share. You can see that we have benefited from higher commodity prices and realizing market prices on volumes of oil and gas de-designated as a result of Hurricanes Katrina and Rita. Offsetting much of this gain have been large increases in vocational basis differentials. As Tom Farrell mentioned earlier, the potential oil and gas production for 2006 has been reduced by phase out of royalty relief, a longer decline curve for the production at Front Runner, and continued delayed production as a result of Hurricanes Katrina and Rita. Business interruption insurance costs have grown as a result of the loss experience of our offshore underwriters. The company has lowered the discount rate used in our pension and benefit calculations, which causes an increase in this expense. Finally, please recall that our original 2006 guidance range incorporated upside potential from three drivers integration into PJM, the benefit of the establishment of a…

At this time we will open the call for questions. If you would like to ask a question please press the “*” followed by the “1” key on the touchtone phone now, if any time you would like to remove yourself from the questioning queue please press “*”, “2”. The first question comes from Greg Gordon.

Hi good morning guys.

Good morning Greg.

Good morning. On the, just sort of make sure I heard it right. You guys did actual production in Q4 95 Bs; correct?

That's correct.

And you indicated that you had 43 Bs of production interrupted. Am I recalling that correctly as well?

Yes. Greg, this is Duane. Yes.

So I still don't understand exactly how we reconcile that with your production forecast if we assume that you're back to your prior level of forecasted production by fiscal year ‘07, that would be a run rate still significantly in excess of your 5 to 515 Bcfe production forecast today. You did indicate in your comments, Tom that you were backing off or netting against your production forecast, the royalty reduction impact. But can you reconcile why the forecast doesn't seem to, seems to be conservative relative to sort of the pre Katrina pre Rita expected production?

Sure Greg. What you’re doing and you're absolutely correct, in fourth quarter that would have added up to close to 140 Bs, but that would have been peak production. I mean, we don't ever keep, those Gulf of Mexico wells, they decline relatively rapidly. So you're looking at the peak and taking it times four. When you actually look at the average production, it would have been substantially less than that and into our forecast. What we've essentially done and you in some of your analysis had looked at it and said you had expected more than 5% to 6% in 2006. What really happens is because of the delays, that all moves to 2007.

Okay, thanks.

It's a timing issue then.

Understood. We have additional questions. Actually Faisel Kahn has got a few questions. Faisel?

Yeah, Duane, do you have an updated reserve amount for your proof probable on possible reserves? And can you talk about where most of your proved reserves growth came from for the year, and what's your peak proved developed producing to PUD ratio?

Sure. Let's, first of all talk, I don't have the probable, possible. We're in the process of finalizing it, but it should be somewhere similar or a little bit larger than what we had a couple years ago. We've normally only done it every couple of years, but it would be probably over 4Ts probable and possible, in that range. And on the reserve additions it was pretty much across the board except in the Gulf of Mexico, and that's due to timing of when you book the reserves. You know, earlier we booked a lot of the Front Runner, Devils Tower reserves. We spent the money last year and some of it this year. So that's just a timing issue. But the programs across the board have done very, very well. We can get you the undeveloped to do, but it was somewhere in the 25% to 30% range which I think will put us certainly below the midpoint of most of the companies.

Okay. And then can you talk about these deep wells in Oklahoma? How big are these wells? What kind of reserves are you talking about with these wells?

Yeah. It's a program we actually started about 18 months ago in the deeper Anadarko. We currently have four rigs. We've been accumulating a lot of acreage, so we haven't said anything. But we have four rigs running there. A typical well is four to $8 million, and we're talking five to ten Bcf, but we have quite a bit of acreage there. It's been a very successful program for us.

Thank you.

Thank you.

Thank you. Our next question comes from Steven Fleishman with Merrill Lynch.

Hi guys.

Hi, good morning, Steven.

A couple of questions. First, on the locational basis differential, sounds like you expect kind of same impact 2006 versus 2005. I’d be curious, though, how much are you, how can you be confident that there isn't going to be some ongoing basis differential? We used to model one in a year or so ago for your E&P, and then it kind of had went away versus Henry Hub. Should we assume there's going to be some ongoing basis differential?

Steve, we think it's going to stay through the course of the year and decrease in pieces and parts as it goes along as more infrastructure comes online resulting from last year's hurricanes. There's, as I said, we saw $0.40 in the fourth quarter, and we're looking forward. We think it will be somewhere between $0.30 and $0.40 total for the year. So obviously it will be decreasing as we go along. We believe, we can't guarantee, but we believe that the differential will revert to the norms that you see traditionally by the end of the year.

Okay. And then secondly, the marketplace on de-designated hedge volume number, the dollar over the two years, how does that break out between 2005 and 2006? It's not really mentioned as a factor in the 2006 to 2005 differential.

Steve, this is Joe. We haven't de-computed what the benefit of the early return to production; say from at market price was in 2005 versus what we'd expect in 2006. And because the business interruption insurance claims are not final yet, we just haven't parsed that amount out between either year or claims versus early return to production. It's just we expect to recognize the de-designated amount in both of those fashions?

One of the things obviously that we did have a gain this year not only in mark-to-market at year end, but part of it also was marked in October, November and December from the mark. So somewhere in the neighborhood of about half of it, Steve.

Is already in there, okay.

For 2005, and we've accounted for in terms of our prices received in ‘06. So it reconciles to the 24 months.

That's right. You also do see it in price from the early return to production in 2005.

Okay.

Those three pieces.

Okay thank you.

Thank you.

Thank you. Our next question comes from Hugh Wynne with Sanford Bernstein.

Hi.

Hi, Hugh.

Hi, Just a quick question, if I could, on page 8 of your 2006 earnings guidance kit of the reconciliation of 2005 operating earnings to the 2006 guidance range. The line for E&P production and BI insurance is about $0.95 to $1.05. I guess it's correct to say that this is your collection of business interruption insurance in 2006 in excess of production losses in 2006. In other words, it's collection of BI insurance for production lost in 2005?

Correct.

Okay. So when we subtract that out from the 505 to 525 guidance range to come up at what you might think of ongoing earnings power in the absence of BI insurance collections, we're down then to something closer to $4.25.?

It’s not all BI. It's production growth and BI. I don't think that model is going to work, Hugh. I think we can work with you offline, but I think 2006 versus 2007 that we can reconcile and we will in May in terms of mainly a production uplift. We do, as we’ve mentioned earlier, we do have a fairly significant uplift in production in ‘06 versus ‘05 in addition to collecting some of the BI insurance claims. So that number.

Okay. So what is the, what is the breakdown?

We didn't want to break that down. You can appreciate the fact that we still have negotiations in front of us with insurance underwriters. So we deliberately lump those together.

Okay. Is there, is there a figure beyond which the insurance underwriters wouldn't even considering cutting a check that we can perhaps use here to figure out what portion of the increase is…

Probably.

Alright, I will call back latter.

Thanks.

Thank you. The next question is from Dan Eggers with Credit Suisse First Boston.

Hi good morning.

Good morning Dan.

First question is on, hedging philosophy going forward, if you could give a little more color. Obviously you guys didn't really add the hedges anywhere in the fourth quarter. How were you thinking about what the right hedge percentages need to be for E&P for the merchant generation business, and then along those lines what kind of imputed or implied returns on capital do you guys want to target as you think about future investment in those businesses?

Hugh, I'm sorry. I apologize, Dan. We don't plan on changing our previously announced hedging policy. If you look at the percentages, as you go out into the future, we're hedged at about levels right about the levels we said we would be as we exited one year going into the other when you take into account the internal hedges. So we're hedged about where we thought we would be for ‘06, ‘07 and ‘08. And as we go through the year we will continue to roll into more hedges. We're going to probably shape them a little bit differently than we have in the past, but the percentages will fall in those categories that we've talked about previously. Returns on invested capital will vary from business unit to business unit depending upon what the risks are that we're looking at. But all of them are going to be seeking, anything we do, anything we invest in is going to be seeking to increase the returns on invested capital, and that's one of the reasons why we're looking at all of our assets to see what's dragging on our return on invested capital. And if they are drags, then we're looking at disposing of them. But giving you a specific target number, I'm not sure we'll do that in this morning's call. We're not interested in investing something that's not going to improve the return on vested capital unless it's obviously maintenance related.

When you talk about, no major shifts or no asset sales in the short or near term, I think is what you said, any handle on what near term can be translated into meaning?

I didn't, first, I don't believe I said there wouldn't be any asset sales in the near term. We're not commenting one way or another on anything we're looking at selling or anything we're looking at buying. What I was trying to convey was that the business model that Dominion has and has developed over the last ten years, our geographic region focus, not different assets scattered around the world or in widely disparate regions of the United States, fully integrated across the energy chain from E&P, pipelines, distribution systems, generating assets, electric transmission, gas storage, LNG importation facilities. That business plan wasn't dreamed up by a single individual or implemented by a single individual. It was carried out, it was thought up and carried out by a group of folks all of whom are still here or most of whom are still here. We intend to continue forward with that plan. As we go along, there are certain aspects of it that we are thinking about whether it should be, we should shade them differently or do something a little bit differently. But we're not going to do anything about that in the near term. I think I'll just leave the definitions up to you, but the near mid-term are certainly for a course of many months.

Got it. And then not taking too much time, but one last one. You mentioned AEP's success with their Virginia fuel clause. Given that it's been pretty contentious in other states with the transition and passing on rate increases for the first time in a number of years, which you guys will be facing, how are you going about dealing with the commission, dealing with your various stakeholders to brace people for the increases coming?

Well, we have met with lots of people. We have kept the staff informed, the staff of the commission informed about the programs that we are implementing on coal purchases and other things. They're kept informed of the performance of our generating units over the period. They're kept informed of the growth we have. They see the actual fuel expense. So everybody, everybody is kept very well informed on these issues. We need to keep all this in orders of magnitude. The electric customers in Virginia aren't going to see anything near what's happening to gas customers here and in other states. Some of the fuel requests that we saw I think we mentioned in the third quarter call, I had seen one in Florida seeking a 20% increase. I mean, ours are not going to be anywhere near that order of magnitude. And also recall in Virginia the average monthly bill, including fuel today, is only about $85 a month.

Got it, thank you.

Thank you, Dan.

Thank you. The next question comes from Paul Fremont with Jefferies.

Hi, Paul.

A couple of questions. The first, I guess, relates to, it looks as if there's a fairly significant increase in the amount of spending, CapEx spending, that you plan on doing in the E&P business. If I take sort of Tom Chewning's earlier comment, should we assume that additional spending will all be debt financed, it looks like about a $500 million increase?

Yes, Paul. I'd like to, if you give me a minute or around a minute. I know people have already taken a look and said you had negative cash flow in 2005 and you still have it in 2006. First it's always desirable to run a company to be free cash flow positive after CapEx and dividends, and we're committed to doing that. Obviously there's two areas of capital expend, maintenance and growth. We must continue a fairly high level of maintenance CapEx. As we define maintenance CapEx, part of that is replacing lost production, and as you know, the cost of replacing that production has risen significantly in the last couple of years. The interesting phenomenon for us is that because of our legacy hedges we're not able to receive the cash flow that's commensurate with the market prices and yet we're paying the capital costs to drill at current market rates. That's not a good thing for us, but we will wear out of that in ‘07 and ‘08. Also, it's interesting that our cash flow has been impacted by the fuel factor in Virginia. We began to work out of half of that in ‘07 and the other half in ‘08. And then thirdly, part of our growth CapEx next year is the Cove Point expansion, which doesn't return any cash flow until mid year or later in 2008, as well as increased spending at Dresden, another plant which doesn't come on line until ‘07. So Paul, we would be foolish to tell you that we don't, we won't be spending at these capital levels. We will not make a long-term CapEx decision based upon a short-term goal of being cash flow positive, although it is certainly our goal, we would expect to be about breakeven in 2007 and very positive in 2008 as a result of higher cash flows and some lower growth CapEx figures.

Okay. Then the second question is, in terms of, in terms of the hedging gains, I just want to understand, in terms of the accounting, is, is a significant amount of that showing up agency the FAS 133 hedge ineffectiveness credit that you're showing under, I guess as a credit to O&M in the E&P business, or is that something else?

Paul, can I ask you what schedule you're referring to?

I guess it's page 14. It looks like it's a 60 million benefit from 2004 to 2005.

That must be it. I believe that's the line item where it would be, yes.

And just so I understand you, when I look at 2006 there will be a similar amount of credit in roughly in 2006 as there was in 2005?

Could you ask, ask that question again.

Should we expect a similar credit to O&M in 2006 based on your guidance of that expected benefit that you plan on recognizing $1 over I think, over the two year period?

Hi, Paul. Would you please, I will call you back after the call and try to go through the details of that question. It's just not clear. So I think it would be more productive if we just took it offline.

Okay. And then the last question I have is, generally I'm not sure I understand, it looks like a lot of the hedges in 2005 for the non-regulated businesses were being booked in VEPCO. I just don't understand the rationale there.

Paul, I don’t know if you're talking about some of those hedges being done at VPEM, and if you are, that was causing a large negative market in Virginia Power, but not at Dominion consolidated.

Okay. So those would only be then generation hedges? Those would not be for any of the other businesses?

There's a lot of generation, but it doesn't mean it's all generation. Importantly VPEM was moved out of Virginia Power and into Dominion at the end of the year and we filed an 8-K giving details. It's significantly improved both debt and equity for Virginia Power and net income as well.

So at least, on a going forward basis the Virginia Power financial statements won't show significant activity for hedges?

That is correct.

Thank you.

Thank you the next question is from David Schanzer with Janney Montgomery Scott.

Okay, Hi David.

Hi, good morning. Couple of questions. Could you give me an idea of what the capacity factors were for both generation nuclear units and utility nuclear units?

The nuclear capacity factors were 92% in 2005 for the nuclear units. And on the fossil units, equivalent availability is probably a better indicator; it’s about 96% as Tom said, in the peak season. If you look at the big coal units for the utility, capacity factors were about 79% and if you look at the small coal unit’s capacity factors were about 72%.

Okay, great. Also, has there been any attempt at resolving the dispute between Dominion and WGL with regard to the negative impact of unblended LNG as it goes through their pipes?

No.

Okay. You don't have a schedule for resolving that, I take it, or you're not just addressing it?

We'll let FERC resolve it.

Okay.

We're not going to resolve it with Washington Gas Light.

Okay great, thank you.

Ladies and gentleman we have reached the end of our allotted time and Mr. Chewning do you have any closing remarks.

I would like to thank everybody for joining us this morning. Just a couple of notes, we expect to file our form 10-K with the SEC on March 1st. Our first quarter Earnings Conference Call, is scheduled for 10:00 AM Wednesday, May the 3rd. And let me give you one more reminder of our Spring Analyst Meeting to be held in Boston. It will be on Monday, May 22nd. Those who’ll be for rest of the day good morning.

Thank you. That thus concludes today’s teleconference. You may disconnect your lines at this time and have a wonderful day.