Dominion Energy, Inc. (D) Q4 2006 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and welcome to Dominion's fourth quarter earnings conference call. We now have Mr. Tom Chewning, Dominion's 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 prepared remarks, we will open the floor for questions. At that time, instructions will be given as the procedure to follow should you want to ask a question. Before introducing Tom Chewning, I will turn the call over to Joe O'Hare, Director of Investor Relations. Joe O’Hare: Good morning, and welcome to Dominion's fourth quarter earnings call. Concurrent with our earnings announcement this morning, we have published several supplemental schedules on our website. We ask that you refer to those exhibits for certain historical quantitative results. From time to time during this call, we will refer to certain schedules included in our quarterly earnings release or to pages from our fourth quarter earnings release kit, both of which were posted this morning to Dominion's website. Our website address is www.dom.com/investors/ir.jsp. 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, included on 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 a reconciliation of these non-GAAP measures to GAAP on our Investor Relations' website under GAAP reconciliation. I'll now turn the call over to Tom Chewning, our CFO. Tom?Tom Chewning: Thank you, Joe, and good morning. Joining me this morning are Tom Farrell, our President and CEO; and other members of our management team. This morning, I will review our fourth quarter and full year 2006 results and discuss several other matters, including our future plans for earnings guidance. Tom Farrell will then provide his remarks, including the status of previously-announced divestitures, including the proposed E&P divestiture; and proposed changes to Virginia's deregulation law. Let me begin by noting that in my 20 years of service with Dominion, I cannot recall another year like 2006 in which the Company performed so superbly, and has been so well-positioned for future success. It was a defining year financially, operationally, and strategically. Dominion produced record GAAP operating cash flow of $4 billion and record operating earnings of $5.16 per share. In addition, we continue to make solid progress toward improving our credit metrics. As if record financial performance were not enough, these results were achieved despite absolutely horrible utility weather. Milder than normal temperatures across our system reduced earnings more than $60 million. Tropical Storm Ernesto reduced earnings another $11 million. Despite these weather-related impacts, the three core utility-oriented operating units -- Dominion Energy, Dominion Delivery, and Dominion Generation, which comprised the foundation for the new Dominion -- produced higher than expected earnings. In fact, on a combined basis, these three businesses exceeded internal plans by more than $100 million, excluding Virginia Power fuel impacts. On the weather normalized basis, therefore, these core businesses exceeded plan by more than $170 million, or nearly $0.50 per share. Obviously, when analyzing 2006 results, certain normalization adjustments should be made to arrive at base recurring earnings power. Dominion produced exceptional results in producer services at Dominion retail and in our gas transportation and processing businesses. Dominion Generation had another exceptional year in excess emission sales. However, even normalizing 2006 results to a more sustainable level of earnings, the core units exceeded plan. What this means for investors is that the income drivers in Dominion's core businesses are on track. It is for this reason that we believe the information we provided at our May 22nd, 2006, analyst meeting properly adjusted for commodity prices and other items such as acquisitions and divestitures, continues to provide a reasonable framework for modeling future earnings. Dominion experienced positive financial performance in the fourth quarter. We recorded operating earnings of $0.78 per share for the quarter and finished the year, as I mentioned earlier, with operating earnings of $5.16 per share. This exceeded our expectations for year end earnings provided on our third quarter call and was well within our original guidance range provided at the beginning of the year. Please note that fourth quarter earnings include a positive impact of $0.01 per share related to discontinued operations accounting for the Troy, Pleasant, and Armstrong peaking units that are being sold. The first, second, and third quarters have also been recast for a full year benefit of $0.05 per share. For comparative purposes, 2005 operating earnings have been increased by $0.03 per share to $4.56 per share reflecting this change in treatment of the peaking units. The positive earnings impact of the sale of these peaking units will continue going forward as operating losses have been permanently eliminated. On a GAAP basis, per share earnings were $0.09 for the fourth quarter of 2006 and $3.93 for the year. A significance in both the quarter and year is the classification as discontinued operations of the three merchant gas-fired peakers. $164 million impairment and a $19 million loss from normal operations are included in GAAP earnings, but excluded from 2006 operating earnings. Some of you may recall that we said previously that we did not expect to record a loss on the sale of the three CTs and State Line. That was because we expected to sell State Line at a large enough gain to offset the loss we assumed on the CTs. As Tom Farrell will cover later, we have decided not to sell State Line. A reconciliation of GAAP to operating earnings can be found on schedules 2 and 3 of our earnings release. Now I'll move on to our credit metrics and operating cash flow. At year end, adjusted debt to total capital was 54.5% compared to 51.2% at the end of the third quarter and 58.1% at year end 2005. The increase from the third quarter was driven primarily by a $500 million accelerated share repurchase program we launched in December to begin to reduce shares in conjunction with our proposed asset divestitures. This transaction was financed by short-term debt. In addition, we took the impairment charge previously mentioned of $164 million after-tax on the peaking units that are in the process of being sold. Also, effective December 31st, 2006, we adopted the new accounting standard FAS 158, which requires us to recognize the funded status of our benefit pension and other post retirement benefits plans in our balance sheet. While the new rules had no impact on our results of operations or cash flows, they decreased common shareholder's equity by approximately $335 million. Adjusted FFO to interest for 2006 improved to 4.2 times compared to 3.7 times at year end 2005. Core operating cash flow, defined as net income, DD&A, and deferred taxes, improved by $975 million year-over-year. We finished the year with approximately $3.2 billion in available liquidity compared to $2.2 billion at the end of 2005. A reconciliation of these non-GAAP ratios to GAAP can be found on our Investor Relations' Web site under GAAP reconciliation. Since our November 1st call, we did not hedge any additional natural gas and oil production in light of having already achieved our targeted hedge levels. On the electric side, we made progress toward our hedge targets as can be seen in our hedging schedule on page 31 of the earnings release kit. I should note that while hedging will continue to be an important part of our financial strategy, and we'll continue to publish quarterly updates of our hedge positions, post any E&P divestiture, this information will be less important due to a sharp reduction in earnings sensitivity to commodity prices. Looking out to the 2008 to 2010 time horizon, we estimate the commodity price earnings sensitivity of the new Dominion will be only about one-third that of the existing Dominion with E&P. In view of Dominion's strong financial position and positive outlook, at the January meeting, the Board of Directors declared a $0.02 per share increase to our quarterly common stock dividend, which results in an annual dividend rate of $2.84 per share. Now I'd like to briefly discuss how we plan to handle earnings guidance going forward. As many of you are aware, 2007 is a transition year for Dominion during which we will continue to pursue the E&P divestiture. For modeling purposes, we have stated our intent to use proceeds from any sale to retired debt and buy back stock. As a result of the divestiture process, earnings per share during 2007 will be difficult to forecast. In addition, we are aware that investors are looking past 2007 and are focused on the longer term earnings outlook for Dominion beginning in 2008. As a result of these factors, we will not be providing 2007 earnings guidance. We expect to resume our usual practice of providing earnings guidance in January 2008, following our Board-approved budget in December, 2007. When we offer full year 2008 guidance in January of next year, we plan to disclose in greater detail the drivers and characteristics of our remaining businesses to better highlight their earnings power and value. In order to help analysts model the new Dominion earnings beginning in 2008, we will post after the call this morning on our Web site an outline of an operating earnings model that adjusts our May 22nd earnings outlook for commodity price changes and the pro forma removal of E&P. We do not plan to discuss modeling details on today's call. However, as always, members of our Investor Relations team will be available to address your questions individually. We expect to issue updated divestiture modeling information following the close of any E&P sale, but we thought it significant to reference one of the key modeling assumptions investors have asked often about. The amount of debt to be retired will be driven by our near-term adjusted credit metric targets, FFO to interest of 4.2 times, a debt-to-capital ratio of 50%, and lastly, our FFO to debt ratio of 20%. That concludes our financial review. I will now turn the call over to Tom Farrell. Tom?

Good morning. One of the messages we emphasize to employees and to the investment community is that safety, ethics, excellence, and one Dominion are critical values to our success. During 2006, each business unit performed well in all of these areas. Dominion Delivery, for example, improved their safety performance almost 30% year-over-year. Dominion Energy exceeded their compliance goals by 20% in areas that make us better operators, including in-line inspections and compressor station audits. Dominion E&P drilled a record number of wells in 2006, a 13% increase over 2005, and production rose 22%; while Generation maintained a nuclear fleet capacity factor of over 90% for the third year in a row. Success in the services company through cost reductions, such as medical expenses, and continuous process improvements through Six Sigma were key to our operating segment results. Collectively, this performance from all parts of the Company led to us exceed expectations. While your and our interest in our performance is primarily forward-looking, we are quite pleased with how well our 17,000 employees performed last year. While a past is not necessarily prologue, it is at least an indicator of the direction we are headed at Dominion and our ability to achieve our objectives. 2006 was not only an excellent year for us financially and operationally, it was a pivotal year for us strategically. We took four major steps to ensure future earnings stability and long-term value for our shareholders. We highlighted return on invested capital as a guiding principal in managing our businesses. Focusing on the risk-adjusted returns from individual assets across all business units is a fundamental approach to running Dominion that is here to stay. This philosophy led to us sell the Peoples and Hope gas distribution companies as well as the three peaking units. In November, we announced the proposed sale of most of our E&P unit, signaling a sharpened focus in the strategic direction of the Company. We saw the passage of legislation that returns to a traditional pass-through of fuel expense to our customers beginning July 1. And finally, we have continued to prepare our entire fleet for environmental compliance and the implications of a impending regulations. Now let us turn to a couple of these issues to give you an update. With respect to divestitures, the sale of our three peakers, Troy, Pleasants, and Armstrong, is proceeding on schedule and is expected to close by the end of the first quarter. We have chosen not to sell our State Line plant and will make the capital investments and operational improvements necessary to run the station over the long-term. Lastly, we expect to complete the sale of the LDCs in the first half of 2007. In previous calls, we had projected a first quarter close, but the regulatory hearing in West Virginia has now been scheduled in May. Our proposed E&P sale is progressing as planned, with the data room set to open next month. This process is expected to be completed by the end of the second quarter. An important part of that process was to complete the 2006 year end reserve audit. As of December 31, 2006, our audited proved reserves were 6.53 trillion cubic feet equivalent, a 4% increase over last year. Reserve replacements for 2006 net of sales were over 150%. You should note that the unaudited probable and possible reserves, so-called 2P and 3P, are now estimated at 3.2 tcfe for the 2P and 3.9 tcfe for the 3P. These levels compare to year end 2005 estimates of 2 tcf of probable, an increase of over 50%; and 3.2 tcfe of possible, an increase of about 20%. Potential reserves, so-called 4P reserves, are now estimated at 25 trillion cubic feet equivalent, compared to prior estimates of 5 to 10. Now I'll speak to the status of the legislative activities in Virginia. As we mentioned, the fuel pass-through goes into effect in July, ending the fixed fuel rate that we have had in place since 2004. Virginia is one of the fastest-growing states in the nation. PJM has recently estimated a need to increase generating capacity in our control area by 4,000 megawatts over the next decade, the fastest growing in PJM. Legislators and officials in Virginia have determined that retail choice has not developed as hoped, that base load generation is becoming a more pressing need, and that the uncertainty of going to market in 2011 could result in rate instability for consumers. In the past few months, we have worked collaboratively with various parties to ensure that we are all doing our part to address these issues. The proposed legislation endorsed last night by the general assembly's oversight commission makes good strides to address those needs. Our engagement in this discussion with the Virginia legislature may have begun much earlier than many investors and analysts expected since cap rates do not expire until the end of 2010. You should know that I have a strong conviction to address issues that impact Dominion and its customers proactively. The need for new generation is one which we must begin addressing now with the proper legal and regulatory framework. Another example is why I lead the Company's effort to address its issues with the EPA over emissions from our Virginia generation fleet, which resulted in an agreement in 2000, long before we were compelled to comply. Others resisted and are now having to spend more to solve this problem. Virginians have benefited from much cleaner air during those year. Similarly, we are not going to spend time internally debating global warming. The possibility that we will have regulations governing CO2 emissions either on a regional or national level has been an important factor in our strategic planning process for some time. Given the recent developments in California and Massachusetts, the change of control in Congress, and the positions on the issue taken by many of the prospective presidential candidates, it is increasingly likely that the nation will face some kind of restrictions or taxes on CO2 emissions. As I have said on previous occasions, the expense to the United States economy of regulating carbon dioxide will be enormous. There are currently no viable CO2 control technologies on the market, and it could take decades and huge R&D investments to develop them. Climate change is a global issue that calls for global cooperation. At the very least, the United States needs a policy that is national in scope and does not single out the power industry which accounts for only about one-third of the nation's CO2 emissions. Nevertheless, we are already facing CO2 emission regulations in some of our operating areas. We took the possibility of these regulations into account, for example, when we established our purchase price for our New England power assets. In New England, where we are the largest electricity producer, the Regional Greenhouse Gas Initiative calls for emissions caps beginning in 2009. Massachusetts, where we have several fossil fuel generating units, recently joined RGGI and is currently enacting rules. We are actively engaged with policy makers in the region and will be part of that process. It is important to note that it is a regional process and potential impacts should be considered on a fleetwide basis. We have the largest nuclear capacity in the region, as well as gas-fired plants. This topic is an important one for us to address and address appropriately. We intend to be prepared early to comply with new regulations at the lowest possible cost and take preemptive action to benefit Dominion over the long-term. This is a hallmark of our proactive approach to regulatory issues. This concludes our prepared remarks. I am sure that you would like to hear more details about our potential E&P divestiture and the legislative activity in Virginia. I hope you will understand that we are not able to provide much more guidance that you have already heard. With those caveats, we are happy to take your questions.

[Operator Instructions]. Our first question comes from Shneur Gershuni with UBS. Please go ahead.

Good morning, everyone.

Good morning.

Just a couple of quick questions here. Just when we're reviewing the -- potential E&P sale and so forth, can you remind us of the tax rate that we should be applying from a tax leakage perspective? Joe O’Hare: Yes. Shneur, for modeling purposes, we have assumed 37%.

Can I ask why it's so high? Why can't it be a lower rate? It seems like a high rate based on -- Joe O’Hare: If you're considering the gain in relation to a capital gain, there is no differentiation between a capital gain and an ordinary gain tax for corporations.

I think we can handle this a little bit more offline, but the -- it depends on the level of the final sale as to what our capital gain is, as well as items that can be deducted from that 37% rate. And we actually will pay less than 37% rate overall. On the last dollar, though, we will probably pay 37%. So I think, we can handle that offline if you don't mind, and that's just the highest rate we use, but our effective rate should be under 30%.

Okay. That's great to know. I'll call Joe offline. Two other very tight, quick questions. Just with respect to reserves, you gave out the full reserves and so for would you be able to break out what Appalachia represents of that since those are the assets you plan to retain? Joe O’Hare: Yes, Shneur. Out of the 6.5, Appalachia is 1 trillion cubic feet equivalent.

Great. And one final question. Just with respect to your hedging strategy going forward with respect to Generation given the pending sale of most of the E&P segment, do you plan to still continue doing so, or are doing so, rather?

Yes. We plan to continue the hedging strategy we've followed.

Great. Thank you very much. That's the -- some of my questions.

Thank you.

Thank you for your question. Our next question comes from Paul Ridzon with KeyBanc. Sir, please go ahead.

Good morning. How are you?

Hi, Paul.

Good morning.

Just some background on what drove your decision not to sell State Line. Was it evaluations you were seeing in the market, or was there a change in your strategy around that plant?

It was really valuation in the market. We have a six-year contract left with the counterparty there, and we saw a different value than the several bidders that actually put final bids in for us.

And then just on your quarter-over-quarter reconciliation, there was $0.09 of other. Can you give a little more granularity around that $0.09?

Paul, that's going to be individually business by business. If we could talk about that after the call, I would appreciate that.

And then just lastly, just kind of get a sense of commitment to take what level of the proceeds from the E&P sale are going to be taken to the balance sheet to shrink it? And what you're seeing opportunistically as potential other uses?

I think we gave you the credit metrics that we would manage to. And our first dollars will go to get to those credit metrics. There's no percentage of proceeds that we're using. It's a dollar amount that we believe and we take the reduced risk profile of the Company will get us to those three credit metrics. With the one that we've given today, which was a 20% FFO to total debt, which we had not supplied earlier. and I think that that's all that we've given and want to give on that subject and obviously people come up with different answers, but we certainly don't have a percentage of proceeds and obviously part of that is because we don't know what proceeds will be. But our first dollar is to get us to a firm BBB or high BBB credit, which these metrics ought to do.

Okay. Great. And just -- sorry -- that was not my last question. Could you give the 4P prior and current, stripping out Appalachia?

Stripping out Appalachia, is what the question was, Joe, 4P. Joe O’Hare: Right.

5 to 10 is the prior and 25 is now total. Joe O’Hare: Right. And my recollection, Paul, is that we didn't identify 4P in Appalachia. I'm not sure that that is really the measure. I think its all non-Appalachia.

Okay.

Joe, this is Duane. That's correct. It's mostly non-Appalachia.

Great. Thank you again.

Thank you for your question, sir. Our next question comes from Hugh Wynne of Sanford Bernstein. Please go ahead.

Good morning. I just had a couple of questions that I would like to have answered in order to reconcile 2006 results to the expected results of the remaining utility businesses going forward after the E&P sale. Could you all tell me the after-tax earnings of Peoples and Hope in 2006?

I don't have that information available, Hugh. I can research that, and we can talk about it after the call.

All right. What was the after-tax fuel cost under recovery at Fedco in 2006?

It was $364 million.

$364 million after-tax. Great. Are you still expecting $970 million from the Peoples and Hope sale? And is that an after-tax number or --?

Yes. Joe O’Hare: Well, that was an agreed contract price subject to adjustments for CapEx and working capital changes.

That's right. But we expect that to be -- we haven't changed any part of that agreement, and we did have that as an after-tax number.

So $970 after-tax for Dominion -- for Peoples and Hope sale. Okay. And I guess the final question, is there any significant reduction in corporate overhead expected from the sale of the E&P business?

No.

Okay. Thank you very much.

[Operator Instructions]. Our next question comes from Jonathan Arnold with Merrill Lynch. Sir, please go ahead.

Sir, good morning, everyone. Joe O’Hare: Good morning.

Good morning. Just wanted to ask again about these credit metric targets and most to the new one you've introduced. And, Tom, I'm thinking about -- are you intending to hit all of them or most of them, or should we be modeling to actually hit all three of them? I just find it a little difficult to reconcile those numbers.

Well, obviously, one will be more important than another if you do your math, but I'm going to let Scott Hetzer for a broader answer in terms of whether we should hit them right away or not.

Yes. Jonathan. The FFO to debt is generally the constraint that we hit first, and as far as -- we mentioned these are near-term targets. Our long-term targets would be FFO to debt of mid-20s, FFO to interest of 4.2 times, and debt to cap of 50% or less. For the near-term coming out of the divestiture, we'd like to be at right around 20% FFO to debt based on what we see as the risk profile of the Company going forward. But that FFO to debt is generally the constraint.

So that's the one we should focus most on?

I think so.

And we're talking about 2008 numbers here?

That is correct.

And dose potentially change in the event that you say with E&P gone and a more regulated business in Virginia maybe that your business position somehow shifts, would you see these targets as something that could change over time?

Certainly we expect the risk position to shift with the divestiture, and I think the rating agencies have commented that that's their expectation. So we're currently a seven, we certainly think that we will move to a six with a potential sale -- with the sale of E&P, and then we'd have to look at any other risk-producing activities, such as the potential Virginia legislation. That could help reduce the risk further, and we would need to take that into account as well.

So would you consider these targets to be where you'd want to be if you were at a 7 or if you'd already moved to a 6?

These are considered the targets for a 6.

Okay. Thank you.

Thank you for your questions, Mr. Arnold. Our next question comes from Leslie Rich with Columbia Management. Ma'am, please go ahead.

Yes, I had a question on the State Line. And -- you know, did you allude to incremental spending there to get that compliant in terms of environmental regulations, or -- I'm not sure I heard exactly what you said there.

Leslie, the reference there really was we have some tube work to do in that unit and some terminal work to do in the next couple years. It will amount to about $45 million. We don't see any significant environmental expenditures this decade.

Okay. So that's already meeting all the mercury rules and that plant is in Illinois, right?

That plant is in compliance right now.

Okay. Great. Thanks.

In Indiana.

It's in Indiana, sorry.

It's on the line next to Illinois.

Hope the wind blows east, right?

Well, that's why it's called State Line.

Thank you.

Thank you for your question. Our next question comes from Sam Brothwell with Wachovia. Please go ahead.

Hi. Good morning. Could you quickly step through the update to the reserve breakdown again? And secondly, I just wanted to clarify, did I hear you say that the overall tax rate that you would apply in doing the proceeds calculation that the average rate would be 30% or less?

I'll answer that. This is Tom Chewning. I'll -- Sam, I'll answer the last part of it. It certainly depends on the level of gross proceeds. Incrementally, the last dollars we'll receive in our calculations, 35% federal and 2 state. However, you know, within a fairly wide band of potential proceeds, that number is reduced by credits that we have, any NOLs, et cetera. So in looking at our cost basis, which is fairly low, as you know, and looking at other shelters we have, we would expect to be somewhere in the 27 to 30% range overall or a wide range of values, but how you model it is your business. As we've said before, we do have some tax credits we're going to realize, but we also have the ability to use tax losses created by the sale of the peakers and other such situations where we create tax losses to help offset the tax that we'd have on the capital gain. So we're estimating, you know, if you wanted to use 30%, that's probably a pretty good proxy overall or you can do it with a lower rate for the first part and a higher rate for the latter part.

On the yearend reserves, the proved reserves, and this is as audited by Ryder Scott, as of the end of '06, 6.53. 6.53 trillion cubic feet equivalent. That's about a 4% increase over '05. Prior estimates at the end of '05 for the 2P, the probable, was 2 tcfe. Yearend '06 is 3.2 tcfe. The possible or 3P in '05 was 3.2. At the end of '06, it is 3.9. And then the so-called 4P was a range of 5 to 10. It's now estimated at 25. Joe O’Hare: Okay. Sam, we intend to post on our website the base and detail of 3P reserves. So that'll be available after the call.

Very good. Thank you very much.

Thank you for your questions, sir. Our next question comes from Dan Eggers with Credit Suisse. Sir, please go ahead.

Hi. Good morning.

Good morning.

I don't know if Duane is still on the line, but if he could comment on F&D costs in '06 versus '05 and kind of trend if there's anything to note between onshore offshore?

Sure, Dan. In the -- in the forecasts that we had given earlier in the year, we had said somewhere around $2.30 on F&D costs. Our ultimate F&D costs wound up around $2.40, a little over that. And the drivers were certainly the costs. It was a little bit on the high end on the F&D, but part of it was at the end of the year, because of performance -- positive performance that we saw in a lot of our areas, we booked additional PUDs, so we had more reserve adds than we had forecast at the beginning of the year. They came in higher than the embedded DD&A rate. So the overall F&D costs went up a little bit, but it was good because we added reserves.

Okay. Did you guys include the frontrunner impairment that Norsk Hydro had talked about in your reserve numbers?

We always do. And, again, we can't comment as to what Norsk Hydro had booked or allocated in value to frontrunner, but we have historically always had fewer reserves on our books. And we have had no significant change to our reserves or forecast.

I got it. On the Virginia progression of events there, is there any way for you to get recovery or seek recovery for the fuel shortfall you guys have encountered over the last couple of years, by way of cost incurred and an attempt to go to market that is no longer going to happen? Thomas Farrell: No.

So that's money under the bridge. Thomas Farrell: Yes.

Okay. Thank you, guys.

Thank you for your question. Our next question comes from Faisal Kahn with Citigroup. Please go ahead.

Good morning. I'm just wondering on -- with regards to your Appalachia Acreage, have you guys looked at some of the horizontal drilling successes some of the producers in the area have had?

Faisal, this is Duane. Yes. We've actually tried a few horizontals in a couple of areas and not had -- have not had significant success, but it's certainly something we're going to continue to look at. Most of what we're doing there is traditional work as well as some additional coal bed methane projects.

Okay. And then I read somewhere in a trade publication that you had some success in drilling in these Alabama Shales, whether it’s the Floyd or the Conasauga. Can you comment on that, have you drilled any test wells and have you had any success in some of those shales?

We have drilled some test wells there. We've had mixed results. It is part of the potential reserves that Tom quoted earlier. It is very thick shales. We still need to see operationally how to drill it and complete the wells. It's in a very early stage.

Okay. And then when you talk about the 25 tcf of this petroleum -- potential petroleum resources, is -- where are most of those potential reserves located, would you say?

Most are onshore. About 60% are onshore in various basins, and a lot of it is driven by some of our new projects in the shales projects and additional gas factory-type assets that we're developing, and about 40% of it is offshore. And of course, it's driven by the deep water exploration that we have in our program.

Okay. Great. Thanks for the time.

Thank you for your question. Our next question comes from Raymond Leung, Bear Stearns. Sir, please go ahead.

Thank you. Probably a question for Scott Hetzer here. Scott, can you prioritize those three credit metrics? I guess, is FFO to total debt the one you target in terms of looking at the balance sheet and can you talk about near-term, long-term, what's that time line? Three years, five years?

I would say in terms of prioritization, the FFO to debt is the most important, and then I'd say FFO to interest, and then third, debt to cap. As far as near-term, I said coming out of the divestiture, that's what we define as near term. A year or two out of the divestiture. And then for longer term, I'd say three to five years.

Okay.

And of course, we do expect continued improvement over the next several years as we exercise the plan. So we see strength in the years following the divestiture.

Okay. Great. And just a question on tax NOLs or offsets. Have you sort of reaped everything you have, and do you have an updated number on NOLs yet, or do I have to wait for the 10-K?

This is Steve Rogers. I think it's probably best to wait for the 10-K. But I will tell you that a lot of the NOLs and things like that that we disclosed in our 10-K last year -- excuse me -- got used in operations in 2006. But I think it's probably best to wait for that and as we continue to look at tax profile of any potential deal and some things that come out as a result of our asset review, you know, obviously we will update numbers and update our forecast.

I think it's important, here, too, to not just isolate the sale. The real question is what cash does Dominion have after it pays down debt to buyback stock or make superior investments. So if we happen to have a higher cash flow now and higher cash balances et, cetera, it really makes no difference whether we create them through higher earnings in the near-term or through this sale. So we're not unhappy if we applied a few more NOLs. And we have developed a few others, and I don't know that we won't develop a few more in the future, but those certainly cannot be predicted.

Okay. Great. Thanks, guys.

Thank you for your question, sir. Next question comes from Dan Jenkins with The State of Wisconsin Investments. Please go ahead.

Good morning.

Good morning.

On the Virginia fuel clause that's going to go in effect July 1, how much of an increase is that to customer's bills? Do you have a sense of --?

Yes. It has not yet been estimated. We won't file that case until late in the spring, and we will be taking a look at the forward markets at the time.

Okay. Could you give a little more color on, you know the legislation proposed? Would it be just essentially back to full regulation like you had before? And will it cause any impact on your Generation fleet?

It's -- I would -- it's not -- the proposed legislation is not all the way back to traditional cost of service regulation. It has incentives in it to meet the needs Virginia has to increase our baseload generating fleet. It has a variety of consumer protection measures in it, rate stability measures. It has a lot of very progressive thinking in coming up with a regulatory model that will meet the needs of our customers and the state.

Okay. Then on the State Line plant, I think you mentioned, you still have six years left on the contract for the output of that plant. How does the price of that contract compare to the recent auction in Illinois of about $65 a megawatt? Is it significantly less than that, or how does that compare to what the current marketplace is? Joe O’Hare: We don't disclose any contract information with the account authorities.

Okay. And then I was wondering if you -- is your proposed environmental CapEx, has that changed any going forward? Do you see that as -- a lot of utilities have raised the amount that they think they're going to have to spend. I was wondering if you could update us on that?

We don't have any change in that. Remember, Dominion has spent most of it. We went ahead and started complying in the early part of the decade. We didn't try to fight off the regulators.

Okay. Thank you.

Thank you for your question, sir. Our next question comes from Rebecca Followill with Howard Weil. Madam, please go ahead.

Hi. Duane, question for you. What percent of the reserves at year end 2006 were PDP versus PUDs?

I believe the final number was right at 27%, Rebecca.

20% PUDs?

27% PUDs.

Okay.

Which is in-line to what we've historically held, somewhere between 25 and 30 is what we normally run.

Right. And next question, assuming that everything is blanched up in Virginia, how quickly would we see you guys announce a new build program?

We're -- we have a variety of plans under consideration. We're not going to wait and see what happens. We're -- we're looking at it, and we will come out with something once we see how the regulatory issues work themselves out.

Okay. Thank you.

Thank you for your question, madam. Ladies and gentlemen, we have reached the end of our allotted time. Mr. Chewning, do you have any closing remarks?

Yes, Lindsay. Thank you. Just a reminder that our Forms 10-K will be filed with the SEC on or before March 1st and our first quarter earnings release is scheduled for Wednesday, May the 2nd, of this year. I like to thank everybody for joining us this morning. Please enjoy a safe, healthy winter. Good day.

Thank you. That does conclude today's teleconference. You may now disconnect your lines at this time. And please have a wonderful day.