Questar Corporation Q4 2006 Earnings Call Transcript

TRANSCRIPT SPONSOR

Questar Corporation (STR)
Q4 2006 Earnings Call
February 14, 2007 9:30 am ET

Executives:

Stephen E. Parks - Senior Vice President and Chief Financial Officer
Keith O. Rattie - Chairman, President and Chief Executive Officer
Charles B. Stanley – President and CEO, Questar Market Resources
R. Allan Bradley - President and Chief Executive Officer, Questar Pipeline
Alan K. Allred - President and Chief Executive Officer, Questar Gas

Analysts:

Brian Singer – Goldman Sachs
Shneur Gershuni - UBS
John Mansfield - SAC Capital
Carl Kirst - Credit Suisse
Faisel Khan - Citigroup
Alex Mayer – Zimmer Lukas
Raymond Deacon - BMO Capital Markets
Michael Heim - A. G. Edwards & Sons
Marshall Carver – Pickering Energy Partners
Richard Sulles - Capital One South

Presentation

Operator

At this time I would like to welcome everyone to the fourth quarter, year end 2006, earnings release conference call.

All lines have been placed on mute for preventing a background noise. After the speakers' remarks, there will be a question and answer session. If yow would like to ask a question in this time, simply press star and then the number 1 on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you.

Mr. Steven Parks, Senior Vice President and CEO, I'm sorry, CFO. You may begin your call.

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Stephen E. Parks

Thank you Marcus.

Good morning and welcome to Questar Corporations year end 2006 conference call. Yesterday, we reported the Questar's 2006 net-income was at 36%, driven by increased volumes and realized prices for natural gas oil and natural gas liquids.

Questar 2006 net-income was $444.1 million or $5.07 per diluted share. These results included a $15.8 million for $0.18 per diluted share after tax gain in the sale of assets in 2006.

You can access more details in our earnings release at our website at Questar.com.

Following my remarks this morning, Keith Rattie, our Chairman and CEO, will comment on operations and update our earnings and production guidance for 2007. After Keith's comments we'll take your questions.

Other members of Questar senior management are with us today to answer your questions, including Chuck Stanley, President and CEO of Questar market resources, Allan Bradley, President and CEO of Questar Pipeline and Alan Allred, President and CEO of Questar Gas.

Our remarks this morning will contain forward looking statements about future operations and expectations of Questar Corporation. These statements are being in good faith, we believe they are reasonable representations of the companies expected performance at this time. Actual results, of course, may vary from our standard expectations and projections due to a variety of factors that are described in our form 10K filings with the SEC.

Now let me very briefly review our financial results for the full year 2006. Questar net-income was $444.1 million or $5.07 per diluted share, compared with $325.7 million or $3.74 a year ago.

There were $87.6 million weighted average diluted common shares outstanding during the 2006 period compared to $87.1 million in 2005.

Our Market Resources subsidiary drove the increase with net-income of $356.1 million, up 38% compared to a year ago.

Market resources 2006 results included $15.8 million of net-income from assets sales, $16.5 million of after tax charges for unsuccessful exploratory wells and a $1.2 million after tax charge for net market to market losses on outstanding natural gas basis only swaps.

Our four Market Resources subsidiaries, Questar E&P, Wexpro, Gas Nanagement and Energy Trading, all have double digit increases in earnings for 2006.

Questar E&P net-income was up 47%, driven by a 13% increase in natural gas and oil equivalent production and higher realized prices for natural gas, oil and NGL.

Wexpro net-income was up 14% driven by a 26% increase in investment base over the past 12 months.

Gas management net-income was up 19%, primarily due to higher prices and volumes and margins.

Energy trading net-income was up 60% due to higher marketing margins and fees.

Questar Pipeline, our inter-state pipeline and storage business earned $42.4 million in 2006. Now was that up 74% over 2005.

Net-income for 2005 included fourth quarter non-cash charge of $10.4 million for impairment of a pipeline, excluding that impairment, Questar Pipelines 2006 earnings were up 22% over the prior year, driven by new transportation revenues from its Southern system in Central Utah and from Overtrust Pipelines in South Western Wyoming and by higher NGL prices.

Questar Gas, our retail gas distribution utility, reported 2006 net-income of $37 million, 3% higher than a year ago. The improved results were from higher margins from customer growth.

Now I’ll turn the microphone over to phone over to Keith Rattie, Questar Chairman and CEO.

Keith O. Rattie

Good Morning everyone, I'm going to briefly summarize and try to add some color to our ‘06 results, then I'm going to turn to our outlook for 07', explain our revised earnings and production guidance and then give you some important updates on key projects.

So Steve’s already covered the highlights. The bottom line is that Questar Corporations and all six Questar business units posted record net-income in 2006.

And when you strip out the net after tax gain from the sale of non-core assets, we earned $4.89 per diluted share in 2006, and that compared to our guidance of $4.65-4.75 per diluted share.

One thing to add, our 2006 net-income was net of after tax charges totaling $16.5 million related to unsuccessful exploratory wells and of course the most significant of that being the Pinedale deep test.

Steve noted that market resources generated about 80% of our ‘06 net-income and that all four market subsidiaries achieved record net-income.

Steve mentioned that Questar E&P grew net-income 47% in 2006, that of course is driven by a 13% increase in production and a 28% higher margin on equivalent production.

Margin was up despite lower prices and higher costs, that's because hedging helped increase revenues in a falling price environment in 2006, of course and hedging reduced the revenues in a rising price environment in 2005.

Hope you note that Questar E&P’s total cost of production was up 6% from $2.83 per MCF equivalent in 2005 to $2.99 per MCF equivalent in 2006.

From what we've seen in the reported results of other US independents, we think we're going to again rank in the top ten among about 45 US independents. We were number six in 2005.

Questar E&P again grew production 13% to 129.6 billion cubit feet of natural gas equivalent in ‘06 that compared to 114.2 BCF equivalents in 2005. And it was above the top end of our guidance.

Let me talk about our year end reserves. Questar E&P replaced 217% of its production in 2006.

Year end ‘06 improved reserves were 1631 BCF equivalent, that's up 10% from 1480 BCF equivalent a year in ‘05.

Pinedale year end improved reserves were of 19%, to 932 BCF equivalents from 780 at year end 2005. And please note that 61% of Questar E&P's year end improved reserves were proved developed and 641 BCF equivalents or 39% of our year improved reserves are proved undeveloped PUDs. But more importantly 91% of those PUDs are at Pine Dale.

At year end 2006 we had booked PUDs on 316 well occasions at Pinedale, that compares to 203 at year end ‘05.

Please note, we booked PUDs on 119 ten acres locations and converted 77 existing 20 acres PUDs to 10 acres PUDs on the southern part of our increase block. And as you know when we book PUDs on 10 acres, we haircut the reserves compared to the 20 acres location in the staging units.

We still have over 430 un-booked locations yet to drill on the 10 acres density at Pinedale.

Recall that all of our estimates approved reserves are prepared by independent reservoir engineering firms. And I would add that our Pinedale team completed 51 wells at Pinedale in 2006, at the same average cost, about $5.8 million as two years ago.

In short productivity improvement have offset the severe increase in service cost and thus protected our margins.

And what about the results in the mid-continent? Our mid-continent team grew production 21% in ‘06.

I believe in our February call a year ago, we told you that the mid-continent production could be about flat for the year I guess, they're making it look like we don't know how to forecast our production. A great job for our mid-continent team.

Wexpro reported record net-income. Wexpro invested a record $83 million in 2006, increasing it's year end investment base by 26% to $260.6 million, that's also a record.

As we've been highlighting in our IR presentations, Wexpro’s future remains bright. We've now identified over 750 rift well locations yet to drill on the rocky properties governed by the 1981 Wexpro agreements. Of course that’s good news for our utility customers.

In 2006 Wexpro produced about 41 BCF equivalents, the all in cost of service delivered by Wexpro to Questar Gas was $3.74 per MCF in 2006. That cost of service of course includes Wexpro’s 19% plus after tax un-levered return on its net-investment base.

Please note that Wexpro cost of service reserves grew 24% to 647 billion cubic feet equivalent at year end 2006. Gas management, our midstream gathering and processing services business grew net-income 19% to another record $42.6 million in 2006.

Key drivers, the frac-spread margin was 83% higher in '06 than in '05. And of course higher frac-spreads drive the gas processing margin. Gas processing margin was up 72%. Gathering margin was up 9%. I should add that gas management has another very busy year ahead of it with major expansions of the gathering systems serving Pinedale and mid-continent.

Market Resources CapEx in 2006 totaled $753 million. That breaks down Questar E&P $587 million, Wexpro $83 million, Gas Management $82 million and Energy Trading $1 million. Please note that our current market resources CapEx budget for '07 is about $700 million. That’s about 7% lower than 2006.

We turn briefly to our regulated businesses. Steve noted that Questar pipeline grew net-income 74% to a record $42.4 million in 2006. When you back out the 2005 charge for partial impairment of the California segment of Southern Trails Pipeline, our pipeline company net-income was up 22% in 2006.

I'd like to draw your attention to our pipeline teams' significant productivity improvement. O&M plus G&A costs per decatherm transported declined by over 20% and that's due to a combination of higher volumes and lower expenses.

Also note that in December, Questar pipeline completed phase one of a two phase expansion that will serve as the western segment of the Rockies express pipeline. That's the extension of over thrust pipeline west to Aupau. The project was completed and in service on schedule and on budget despite a delayed start.

Pipeline CapEx in 2006 was $76 million. Our utility, Questar Gas grew net-income 3% in 2006 to $37 million. That's driven primarily by the addition of 26,000 customers. At year end, our utility was serving over 851,000 homes and businesses in this region.

Questar Gas CapEx in '06 was $87 million. I'd also like to highlight our utility change of improved productivity. O&M expense per customer declined from $137 in 2005 to about $135 per customer in 2006.

We expect that the AGA surveys will again show that Questar Gas employees are among the most efficient and productive in the industry. We should also give credit to our people for a significant increase in customer satisfaction. That's not easy to do given the high price environment we've been in and the pounding that utilities get from the media.

Returns on invested capital, as we stress drive long term value in the energy business in 2006, every Questar business unit improved returns on invested capital.

Questar corporation consolidated ROA which we defined as EBIT divided by average total assets, grew to 16.4% from 14.5% in 2005. Market Resource's ROA was 20.3%, pipeline ROA was 11.4%, and Questar Gas ROA was 7.5% in 2006. Our year-end balance sheet, frankly has never been stronger.

Questar corporation total consolidated debt at year end 2006 was down to 33% of total capitalization. Market Resource's total short term and long term debt to total capital was just 26% at year end '06.

'06 is now in the books so let me turn to 2007 and beyond and let me first get the negative news out of the way. Note that we now expect 2007 net-income to range from $5.15 to $5.35 per diluted share. That compares to the $5.20 to $5.50 guidance we gave in late October.

We're going to go ahead and trim guidance for several reasons. First, remember that we sell most of our monthly gas production during bid week at the end of the prior month. Because of low prices in late December, late January, realized prices in January and February on the physical sale of our natural gas and oil production were well below the levels assumed in our earlier guidance.

Second, you hear us focus a lot on Rockies natural gas basis differentials but the Rockies oil basis differential has also widened significantly in the past year due to a variety of factors: A lack of refining capacity in this region, pipeline bottlenecks, competition from Canadian crude, and others.

Unlike our natural gas hedges, which you recall are fixed-price swaps settled into the regional pipeline where we sell our production. Our oil hedges are all Nymex swaps. There isn't an adequate regional market in the Rockies with the liquidity that would allow us to hedge oil basis.

To account for this wider basis, we've had to go back and cut our estimate of the net to the well price on our existing oil hedges. And you can see this if you compare the net to the well estimates on hedged oil volumes on the table at the end of our release yesterday with the estimates in the table at the end of our third quarter release.

Third, we're a little concerned that Questar E&P's 2007 DD&A rate could be higher than we were projecting back in October. Note the increase in the fourth quarter.

And fourth, our operations people in Questar E&P, Wexpro, and Gas Management, have had their hands full this winter with well freeze offs, compressor problems, contractor labor shortages…that have delayed completion gathering and processing projects and similar things.

So that's behind us. Note that we've now hedged about 73% of our forecast 2007 natural gas and oil equivalent production. We've taken commodity risk mostly out of the equation. We estimate that $1 per million BTU change in the average Nymex price of natural gas will change net-income by about $0.11 per diluted share.

Similarly, with the correction for oil basis that I've just discussed, we now estimate that a $10 change in the average prompt month Nymex price of crude oil will move EPS by only $0.05 per share. Please note, that we're increasing Questar E&P 2007 production guidance to133-136 billion cubit feet equivalent. That compares to previous guidance of 132-135 BCF equivalent.

We're raising production guidance because our Pinedale and mid-continent teams are off to a good start in 2007 after a stellar '06. Recall that the key assumption in our production guidance, we plan to drill 48 wells this year at Pinedale. That's three less than a year ago. The BLM is allowing us to operate just six rigs this winter compared to seven a year ago.

Let me briefly comment on the Pinedale supplemental EIS. The BLM Pinedale office, some of you may have noted, has extended the Pinedale anticline project area FCIS public comment period to March 15, 2007 and frankly it could be extended a bit longer to accept comments on the ozone portion of some air quality modeling work.

The BLM intends to allow time for comment on these air quality issues. And from our vantage point that's a good thing. The BLM is going the extra mile to cross the T's, dot the I's, and allow everyone who wants to comment to do so.

Questar and the other operators have chosen not to discuss the draft FCIS in detail while the public comment period is underway. We expect the BLM to issue the record of decision this summer. Note that our production guidance assumes that the ROD has no impact on our 2007 Pinedale drilling program.

Let me give you an update on our ongoing evaluation of our potential new play in the Vermillion basin and you recall that the primary targets here are the thick over-pressured shale that dips down to 13,000 feet and the frontier and Dakota formation tight sandstones at depths down to about 14,200 feet.

We now have 16 Vermillion basin wells flowing to sale. In general that's a pretty good sample of the large geographic area this play. All 16 of those wells are vertical wells completed in both of the Baxter in one or both of the deeper formations.

These wells have averaged about 670 MCF per day after six months of production. We continue to believe these wells could ultimately recover 2-4 BCF equivalent per well. But we don't have enough production history to establish a type curve that we can rely on to predict long term performance. The oldest of the 16 wells has been on production for just about 20 months.

As we have stressed in the past, it's not a question of gas in place. There's a lot of it. It's all about rate recovery and costs. Please note that at current well costs, rates, and recoveries, we need a well head price of about $6 per million BTU to realize a 15% after-tax rate of return.

But we are making some progress with drilling productivity. We drilled the latest well in 39 days from spud to rig release. We've also drilled three wells under a cost-sharing arrangement with the working-interest owners in the shallower Mesa Verde formation.

Cost-sharing can cut about $1 million off the cost allocated to the deep horizon in each well. Our plan currently is, after a few months, the Mesa Verde zones will be completed and commingled with gas coming from the deeper formations. Also, keep in mind that the shallower Mesa Verde formation production overlies a good portion of our deeper plane. And you can get a feel for the extent of that by looking at slide 16 on our latest IR presentation.

Next step on our still steep per-million-basin learning curve is horizontal drilling. Note that in late January, we spudded the Canyon Creek 79H well. This is our first horizontal well on the Canyon Creek structure. We've planned a 3000-foot horizontal leg, targeting what we think is the sweet spot, it's a relatively thin interval near the middle of the Baxter section.

You know that in other major US shale planes, the operators have seen somewhere in the neighborhood of a five-fold increase in rate from horizontal wells compared to vertical wells. And if you'll ask Chuck in Q&A, he'll give you four good reasons why we think horizontal drilling could significantly improve rate and recovery from the Baxter shale.

Last year we focused investor attention on a couple of important delineation wells, the Alkalide Gulch unit #3, which you can see on our slide. It's located on this incline about halfway between the Canyon Creek and Hiawatha structures. And the second well was the Sparks Ridge unit #1 well, located near the edge of the overpressure on the southern end of the play. And again, see slides 16 and 17 in our latest IR presentation, which you can also find on our website.

The Alkalide Gulch number well has averaged about 600 MCF per day over the first 90 days. That's a little below average, primarily because the production is coming from the Baxter only.

We're getting a lot of questions about the Sparks Ridge unit #1 well. You'll recall that this well was a big step out to the southwest. And it's also a long way from any modern well control. We drilled this well to test the shallowest portion of our leasehold in an area we suspected would be near the edge of the over-pressured Baxter Fairway.

This area appears to be oil-prone in the Baxter. We've produced it now, this well, for about 70 days, and an average of about 250 MCF per day, and about 70 barrels of oil per day, again, from the Baxter Shale.

These rates are low, in part, because we've been testing individual zones. Our current thinking is that the oil-prone portion of the play probably covers less than 10% of our total area. And it's most likely limited to the shallowest portions of our acreage. Now, frankly, an oil rim might not be bad news, and I'll let you ask Chuck to explain that in Q&A.

Let's turn quickly to the Uinta Basin deep play. Our fourth deep well appears to be a keeper. We've completed this well, and only the upper third of the Mancos, plus the Mancos B silt, and the Blackhawk. It came on reasonably strong at about 3.2 million cubic feet a day equivalent, and it has averaged about 2.5 million cubit feet equivalent per day for the first 37 days.

We have another deep well at 2D. It's waiting on completion, it's in the southeastern part of the play. And we're currently drilling our sixth well. We may drill up to twelve wells this year to continue our evaluation of deep potential on our extensive Uinta Basin acreage.

Turning briefly to Questar Pipeline, big year for our pipeline company. We're planning to invest over $300 million this year to complete two key projects, both of which will help protect our E&P business by addressing some pipeline bottlenecks.

We'll extend Overthrust pipeline, about 80 miles east from Canada to Wamsutta. This is the second phase, as I mentioned, of the westernmost segment of the Rockies Express pipeline. The Rex Partners have least capacity on Overthrust, from Opal to Wamsutter.

We'll also expand our southern system in central Utah to move gas from the Uinta Basin west.

Returns on invested capital for both these projects are underwritten by long-term contracts, as I noted.

Finally, Questar Gas plans to invest almost $100 million this year to connect new customers, and continue ongoing system enhancements. This is a lot of capital for a relatively slow-growing business. Of course, we have an obligation to connect new customers and an obligation to make investments to enhance system reliability.

And, in fact, the investments we've made in that regard have proven themselves recently. During a cold spell in January our utilities set new records for daily volume, eclipsing the old record by over 15%. We could not have handled this volume if not for the capital we've put into system enhancements in recent years.

In summary, we're coming off a pretty good year in 2006 with a lot of momentum. We stumbled a bit in January and February, but we're stepping over it and moving on. But we have over ten months to get back to where we think we need to be this year. Our people got the job done in 2006, and despite some challenges we expect they'll continue to do so in 2007.

And we're now ready to take your questions.

Question-and-Answer Session

Operator

Thank you, sir.

Okay, at this time I'd like to remind everyone that if you would like to ask a question, please press star, and then the number one on your telephone keypad. We'll pause for just a moment to compile the Q&A roster.

We have a question from Shneur Gershuni with UBS.

Shneur Gershuni - UBS

Hi, good morning guys. I guess I wanted to start off with the Vermillion basin and so forth. I mean, given the amount of wells that have been drilled at this point is it time to start considering possibly ordering purpose-built rigs so that you can drive the costs down even further? Or do you still need to test the area a little bit further?

Keith O. Rattie

We'll let Chuck handle that, thanks for the question.

Charles B. Stanley

Hi, good question. The fundamental understanding of the type of well we are going to drill will drive exactly what size purpose-built rig we choose. Keith mentioned in his prepared remarks that we're embarking on a new well design, a horizontal well, to test the sweet spot in the Baxter.

We really need to know if we're going to drill horizontal wells or the deeper vertical wells because it will affect the overall size of the rig and the type of rig that we would order.

Ultimately, as we've described to you and to other investors, the Vermillion play is all about costs and a significant part of the well cost is just physically moving the rig from well location to well location. So, purpose-built rigs that move quickly are part of the cost solution. Not the complete cost solution, obviously, the well design is the other part of it.

Shneur Gershuni- UBS

Can you share with us the four good reasons to drill horizontally, as Keith mentioned in his prepared remarks?

Charles B. Stanley

I think I've got four fingers, sure...

Keith O. Rattie

I didn't give him a heads-up that I was going to put a number on it.

Charles B. Stanley

The first is, as I mentioned, from our vertical wells that we've drilled, we've begun to see from well to well that the center part, basically, the middle Baxter, seems to give up a disproportionate amount of gas relative to the total 3,000 foot thickness.

We see evidence during the drilling phase and a sudden increase in gas shows as we drill through the Baxter formation in the middle section. And then after we complete the wells and put them on production…production along the wells after they stabilize and we see a disproportionate amount of the inflow of gas coming from the middle Baxter zone.

Why is this middle Baxter better? It doesn't look any different on the logs. It maybe has a little interval in it or two, but it doesn't appear to be unique. Although we do see from production logs that it seems to be better.

So, theoretically, if we can target that center zone and put a horizontal well through that zone, we should see a disproportionately better inflow of gas compared to the vertical section.

The second reason is, and this is a bit of circular logic, so bear with me. Other operators in other shale plays have seen a substantial increase in rates, up to five or even seven times the initial production rate from horizontal wells versus vertical wells. Now, a lot of that is simply exposing more of the shale formation to the well borer by 2 or 3 or 4 thousand feet out in the shales versus a 300 or 400 hundred foot thick vertical penetration of the same interval. Keeping in mind the Baxter is 3000 feet thick, so if we do a vertical well we’re already seeing 3000 feet of vertical sections, so the argument of just KH or permeability feet or permeability height is not a compelling one. But if we target that thicker, or better interval in the middle that seems to be contributing most of the gas, perhaps we’d get a set change in production rate.

Third reason is that, we do believe that there is a natural fracturing in the Baxter shale, and these fractures are near vertical, or slightly inclined, and the probability of hitting one of those with a 5 or 6 inch diameter well borer is pretty small, but if we turn the well borer horizontally, and drill it in a direction that we believe will intersect a large number of these fractures, it further connects the well up to the massive shale section.

And the final reason is that, as you’ll recall from previous calls and individual discussions with you all, we’ve been concerned that we aren’t doing a very good job of fracting these wells, of pumping fracture stimulations, and getting any lateral extension away from the well borer. That’s because there’s really not a lot of vertical barriers to confine the frac and make it go outward, away from the well board rather than vertically, since the shale is pretty homogenous.

So by drilling a horizontal well and then fracting that horizontal well and letting the fracs grow vertically, we hope that we will complete, or stimulate more of the rock body from the well borer then we would in a vertical well.

The tradeoff is of course we give up the opportunity to produce the Frontier and Dakota formations, which as you’ll recall in the best wells, we think could be contributing up to half of production, and half of the reserves. So this experiment, if you will, requires that we make back up, that production and reserve that we could ultimately recover from the Frontier and Dakota, with better initial rates, and higher recoveries from the Baxter.

Nobody’s every drilled a horizontal Baxter well before, so standby, we’re about 4900 feet this morning, we haven’t gotten to the top of the Baxter. This will be late third quarter, forth quarter, result by the time we get the well completed, and get enough meaningful production information from it to talk to you about it.

Shneur Gershuni- UBS

With the cycle times coming down to 39 days in the most recent well, do you have any costs that you’d like to share with us, and what its costing to drill a vertical well now in the Vermillion? Like is it below $4 million now?

Charles B. Stanley

Yes, there’s still $5 million wells in there. The real cost savings, there’s two things that will help with costs. One is, as you mentioned, going (inaudible) built rigs, the other is continuing to refine our bit programs, and overall well design, as we have been very successful with doing at Pinedale.

The Pinedale success, I just wanted remind you, the Pinedale success going from 80 plus days down to the low 40’s and in fact our Pinedale team informed me this morning that we’ve broken our old record, we actually drilled a well from pud to TD in less than 30 days. And we’ve actually done another well from pud to rig-release in a little under 33 days, or 32.5 days.

So those accomplishments and that improvement didn’t happen overnight, there were some break through things that we were able to apply at Pinedale, we’re not sure if they’re going to be the same things. But we hope to build a transfer of this sort of continuous improvement process that we’ve learned at Pinedale, to Vermillion, to Uinta, and these other resource plays, to look for ways to continuously improve drilling performance.

The other key to reducing well costs here is, as Keith mentioned in his remarks, is over a significant portion of this area, there is shallow production, and that shallow basin development is incomplete. We think there are a lot of opportunities there. Wexpro is a major participant in those reservoirs. And there’s an opportunity to share costs between Wexpro and the other shallow owners and Questar E&P in order to reduce the allocated costs of the deep play which further enhances the economics. About a $1 million reduction through the sharing of costs, that will not ultimately burden the deeper section.

If you get a feel for that, you can go back as Keith mentioned and look at, I think its slide 16 in our IR presentation to see the red stippled area, the red dotted area that would represent the shallow gas accumulation where that economics works.

Shneur Gershuni- UBS

Ok, if I could just ask one last question, you mentioned you went to basin and so forth and that you’ve drilled a couple of successful wells that are keepers. Do you have any data to share with us in terms of what it could look like in terms of how many BCF you can achieve from a well and what the well cost for them is as well too?

Charles B. Stanley

Generally, these look like three to five BCF wells, all in, not just the lower section, but combined with basically (inaudible), the Blackhawk section, the upper and lower Mesa reserve section, and the shallower sands. The Uinta basin is heterogeneous, we see all of those zones present in some areas, and some areas it’s a subset all of the zones present. Right now we’re looking at these wells with deep completions only to try to develop a type curve on them, we haven’t done a lot of shallow re-completions.
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But I think a number of 3-5 BCF is a reasonable number. In these wells, depending on their depth, in the deepest parts of our reserves, $6 or $7 million wells right now. In the shallower portions, there are $4 or $5 million wells. And we’ve got from southeast we’re at shallowest to the extreme northwest portion of our acreage. Almost 3000 feet of difference in drill depth, and therefore different well design, and different costs.

Keith O. Rattie

I think the critical theme in Chuck’s comments about both plays is, you know one of the management judgments we have to make, is how hard to we drive capital into the evaluation of this play, ahead of moving along the learning curve.

I think what we’ve conveyed this morning is we’ve made some important progress in both plays.

Shneur Gershuni- UBS

Great thank you.

Operator

Your next question comes from Brian Singer, with Goldman Sachs.

Brian Singer – Goldman Sachs

Thank you, good morning.

Charles B. Stanley

Morning Brian.

Brian Singer – Goldman Sachs

With regards to reserve bookings, can you provide any more details on any revisions to reserves per location you booked at Pinedale for 10 acre versus 20 acre wells, and whether your reserve engineers give you any increase as to gas in place at Pinedale?

Charles B. Stanley

Well Brian, the actual mechanics of the booking this year for the first time of 10 acre PUDs at Pinedale’s was pretty convoluted. Let me just tell you a couple things philosophically that we’ve done.

We’ve only booked 10 acre PUDs in the areas of between the original 40 acre well, ISOEUR contours. And you’ll recall how we originally developed the reserve booking methodology here as we used the older 40 acre wells to develop an ISOEUR contour map. Then we booked 20 acre and now 10 acre wells inside those contours by using a reduction in the reserves assigned to the original 40 acre well.

In the case of the 20 acre well, it was 75%. Originally, we thought in the case of a 10 acre well, we’d be at 60%, we’re booking them closer to 65% of the 40 acre parent well. We only booked 10 acre PUDs this year between the 4 BCF and 8 BCF E gross ISOEUR contours.

So in other words, we didn’t book any PUDs in the lowest EUR areas of the field, and we didn’t book any PUDs in the highest EUR portions of the field.

Frankly we haven’t drilled enough 10 acre wells along the crest of the structure yet to be absolutely comfortable in our methodology. As you know, we’ve been spending the past several years delineating the field, particularly along the edges, in order to get at the ultimate spacing, and the ultimate drill-out plan in preparation for the supplemental EIS.

Keith mentioned to you the numbers, we’ve added 119 new locations, and we converted from this 75% haircut to a 65% haircut 77 of the previously booked 20 acre PUDs. If you go through the gyrations of what we did, we added an average of 4 BCFE gross for those 10 acre locations, keeping in mind that that’s a deliberate subset of what will be the total distribution of results across the incline.

I’ll also tell those of you who get at this number by thinking of the number of locations we added and taking our working interest and reducing it by our net revenue interest, you know, using the averages that we provided to you in the past, that math will frustrate you because we booked PUDs in several areas were Questar E&P has a very small interest for instance in the Pinedale PAR, the maintaining unit PAA. Wexpro has a large interest. Questar E&P only has an override, we booked the reserves associated with that override but its not the typical 62% interest.

The other area that we booked a significant number of 10 acres PUDs is in state section 16, down in the southeastern part of our acreage where Questar's E&P’s interest is about 46% and Wexpro has a similar interest.

So you really need to look, when you look at these reserves as associated with the 10 acre bookings in Pinedale, look at the big increase in Wexpro that Keith mentioned as well as the increase in Questar E&P and you really have to add those numbers up and do the math in order to get at the total reserve hits.

Does that help Brian?

Brian Singer – Goldman Sachs

Yes, it did. Second, how should we look at the rising DD&A rate relative to your expectations? Is that being driven more by exploratory activities that your doing per million in Uinta or is Pinedale a factor as well?

Charles B. Stanley

Let me go back first and answer your other question as to gas and place, I forgot to answer that.

Brian Singer – Goldman Sachs

Oh ok, thanks.

Charles B. Stanley

Gas and place number will likely go up over time. Our independent engineers look at gas and places that check against the total amount of reserves booked in a section, we're still well below the original gas and place numbers and in what we consider to be reasonable recovery factor per section bases versus our gas and place number.

We're still working on our reservoir model given the results not only of the recent 10 acre wells that we've drilled but also of those 4-5 acre pilot wells we drilled last year.

I don't have a new number on gas and price, it's a moving target, we'll update that when we think it's a meaningful change, at this point it’s still work in progress.

On your DD&A rate question, you know, remember DD&A is driven by a couple of things. First of all, it’s driven by your existing pools, existing producing fields and this company is blessed with a number of very low cost pools. That being said, those pools are constantly depleting and the reserves in them are being replaced by higher cost reserves and that's particularly true across the mid-continent were we have a number of sub-one dollar DD&A pools and as we drill new wells on an average $2.00 or so finding cost and replace that production with higher cost we're driving up a higher DD&A rate.

Pinedale DD&A rate intuitively shouldn't go up if our well costs remain the same. The reality is that as I described to you earlier, we've been spending a lot of time drilling on the edges of the field, we've been drilling five acre wells, pilot wells, we've already told you about our booking methodology on those wells, all of which lead to a sub-sampling or under sampling of the average EUR for the field which will have an affect over a certain period of time on DD&A rate.

When we finally get to the FCIS drill out plan, assuming that that's approved by the BLM, we'll the slice the field across it's width in a series of slices which should intuitively sample the full distribution or the average distribution of EUR’s and skew the DD&A rate back.

But you know, look, DD&A rate over time will go up at Pinedale as we drill increase density wells, that's just because the increase density wells will ultimately recover less reserves than a 40 acre well or an 80 acre well would.

Brian Singer – Goldman Sachs

Great, thank you.

Operator

Your next question comes from John Mansfield with SAC Capital.

John Mansfield - SAC Capital

Hey good morning guys.

Charles B. Stanley

Good morning.

John Mansfield - SAC Capital

My question is actually on the Vermillion, I guess Chuck, one of the things you guys talked about is that you'd need to see an increase above and beyond what you were getting out of the Frontier and Dakota that made it worthwhile doing horizontals.

But isn't it true that most of the acreage actually is not perspective for shallow production anyway? And most of the acreage in that basin would be directly targeting just the Baxter shale?

Charles B. Stanley

Okay, now let me just make sure everybody understands. The deepest horizons that we target are the Dakota and Frontier and a little bit of nugget production only on the close structures that primarily are at Hiawatha and over at Kinny which is to the northeast of the trail area that we've been drilling in.

The Dakota and Frontier sands don't appear to be structural accumulations. We see gas even outside of the structural closures at Hiawatha and at Kinny creek trail. So those are the deepest horizons and then the shallower section, the Baxter section, the primary target that has a lot of gas in it would be the target of a horizontal well.

So by drilling a horizontal well we foreclose the opportunity to drill the deeper section. The overlying section, the Mesa Verde, which contains sand or locally called the Kinny creek sand, the trail sand, those formations are a structural accumulation of their productive inside, the closed portions of the Kinny creek trail and the Hiawatha circular structure to the south. And in those areas, it's a third or so of the total acreage position we have out there.

There's a significant opportunity for infill development of the shallower producing horizons. So in drilling a horizontal well, we give ourselves the opportunity to develop the Baxter in the shallower Mesa Verde section in those areas on slide 16 in our IR where that red stippled area is. We give up the Frontier or Dakota because of course we couldn't get to them. But it is that trade-off and that economics that will ultimately drive the decision on vertical versus horizontal wells.

John Mansfield - SAC Capital

Okay.

Charles B. Stanley

Did I clear that up for you?

John Mansfield - SAC Capital

Yeah. I mean...pretty much. My next question just relates to the MLP of the pipeline business. Any new thinking on that?

R. Allan Bradley

Nothing significant to report. Our focus this year is going to be on the build out of the Overthrust pipeline. Once that project is completed it's an asset with high tax basis, might be a good asset to contribute to an MLP. There's a crowded runway of new IPO's and the MLP space ready to launch. We're going to keep our eye on how those are received in the market place. But our focus this year is going to be going execution. We'll look at the MLP in much more detail as we get to the latter part of the year.

John Mansfield - SAC Capital

Okay and when do you expect the Overthrust, can you just remind me when that's
supposed to be completed?

R. Allan Bradley

Tail end of this year. It should be in service the first of January.

John Mansfield - SAC Capital

Okay. Thanks very much, guys.

Operator

Your next question comes from Carl Kirst with Credit Suisse.

Carl Krist – Credit Suisse

Hey, good morning everybody. Just a few follow ups with respect to the Vermillion basin and the net-economic cost to make our 15% after tax return. The $6 permanent BTU, just to clarify, with that net to the well and with that before cost share?

Charles B. Stanley

That's well head and after cost sharing.

Carl Krist – Credit Suisse

That's well head and after cost sharing.

Stephen E. Parks

We look at it as an average well. So that would include wells drilled off outside the closure that would not have pervasive earth section and wells drilled inside the closures. So the average well, some of them would have cost sharing and some wouldn't.

Charles B. Stanley

And that, Carl, you put your finger on the reason why we're being fairly deliberate with the allocation of capital. As you know, our investment criteria requires a 15% risk IRR at $6 Nymex price.

Carl Krist – Credit Suisse

I understand and really appreciate the clarification. Chuck, you talked a little bit about the Pinedale, the extension of some of the economic limits. I'm not sure if I've got the specific well correct. The Masa 10C on the southwest, you seem to indicate in December that, you know, that was a well that was coming in a little bit better than what you were expecting, that could have potential of pushing the economic limit out to the southwest. I was wondering if you could give us an update on what your thought is there.

Charles B. Stanley

Well the interesting thing is that well Carl, performed quite well for the first month or so, it obviously had a couple of sands in the Mase Verde section that were since that time, by year end, it sort-of fell back into the way we originally predicted it would perform. So, we left, for now, our ISOEQT contour maps alone and have increased the reserve potential out on that west side. Interesting early result, but it didn't hold up, in other words.

Carl Krist – Credit Suisse

Okay, fair enough. Thirdly, just to, we talked a little bit about this last week, we've now got a couple of, or four data points here on the DP Uinta looking very strong. Obviously we've got 1,800 potential sites that you guys have identified as kind-of a resource number.

The question again was just, how much well control do you need? Is it the 12 well points perhaps of this year, or do you need more like 22 years of drilling, before we potentially see some migration of the DP Uinta resource potential acting to a 3P number?

Charles B. Stanley

Okay, first of all, if you recall our IR presentations...So, let's see, that would be slide 18, I guess, in the Uinta Basin slide... Don't look at the number, look at the title, “Uinta Basin slide”. The one that's out on our website, you’ll see that three out of the four producing wells are very close together and are sort-of down in the southwestern part of our acreage, 120,000 contiguous acres there in that contiguous northern block. So, a fairly small spatial sample with three wells very close together.

The most recent well, the one Keith mentioned, up to the north, a good northerly control point. Unfortunately we didn't get all the way through the Mancos with that well. We've had so much gas and so much pressure, we called a short TD on the well, and went ahead and completed it. We just didn't have the casing designed right to handle the pressures in the gas that we were seeing. We were concerned about losing the well borer and not having a control point at all.

The most recent well, which is not on your maps, and we'll get that updated this week and we'll put that out on the website, is off to the southeast. So it's another sort-of remote step-out.

But just right now, with that small data set, we see some things that are encouraging. We see the Mancos is fairly well behaved and homogenous. We're seeing significant production rates from the Mancos, in fact, it looks very, very similar to the Baxter and the Vermillion basin, as far as its initial behavior.

In addition to the Mancos, these sands or silts in the upper part of the Mancos which we call the Mancos pre-silt, and then the sands of the Blackhawk in the lower and upper Mesa Verde, enhance the well performance. So we talked about one of the keys here in the Vermillion, and also in Uinta, is initial rate, and then ultimate recovery.

The initial rate helps the rate of return, the return on invested capital. And having these upper sands greatly impacts the initial rate. Because these sands tend to give up gas a lot faster, especially after fracture stimulation. So that's the thing that's quite intriguing and encouraging about the Uinta Basin.

We need more sampling. A dozen wells will certainly help. But just like the Vermillion Basin, as Keith mentioned in his remarks, it takes a long time with these shale wells to develop a high confidence in the type curve that you should use to book reserves. Today in the Vermillion Basin, we're booking reserves basically on a Pinedale-like type curve, with a fairly steep final decline.

And that flies in the face of conventional wisdom on these shales, especially shales like the Devonian, which are very similar to the Baxter shales, where we know that wells have been on production for over 100 years. And they're producing more or less at constant rates. We're still assuming a 6% terminal decline on the shale wells that we've got booked as PDP. So we need more history, as well as the spatial sampling.

But the interesting thing in Uinta, to contrast it with Vermillion, and the thing that's got us very intrigued, is this higher initial rate that boosts the economics, and then the long-life, low-decline shale gas reserves that help enhance the median (inaudible) rate, and finding costs for these wells.

Carl Krist – Credit Suisse

Okay, so, clearly your optimism here, it sounds like...I mean, I don't want to put words in your mouth, but by the end of the year, possibly '08, you know 12 well points and production on some of the earlier wells, that we should have kind-of a good idea what, at that point, could migrate potentially into kind-of a possible category. Is that...?

Charles B. Stanley

Remember that these non-proved categories still have standards that you have to meet, when we reported our 3P reserves and the resource potential in the Uinta basin. We had I think one data point at the time, and our friends at Rider Scott want to see more than one data point in order to classify reserves even in the possible category.

Now we’ve got four producing wells, another one waiting on completion, and more drilling. If we can convert these wells and show that this play has the spatial distribution and then show performance that supports our assumptions, I feel like we will be able to migrate a chunk of the potential from the resource category, and over into the possible category, and some of it into the probable category around those control points.

Carl Krist – Credit Suisse

Great. And then, this last question, I noticed a very big jump, $40-45 million of gross investment in Wexpro for the fourth quarter, obviously that’s great returns there. How do you see that going forward? That’s quite a large rate for a quarter. Was there something specific in there that popped that? Or is that something that can possibly be sustained?

Charles B. Stanley

Good observation, the pop is just by the nature of the drilling that we do. A big chunk of the investment that came in the fourth quarter in Wexpro is related to the completion of turning the sales of a bunch of wells at Pinedale.

You see that sort of growth in Wexpro’s investment basis, its wealthy, it’s dictated by the seasonal nature of the drilling and completion operations. And remember, we can’t put a well into Wexpro’s investment basin, until it’s completed in terms of sales and satisfied to paying well determination under the agreement.

What does it mean for the future? I think we’ve talked, maybe not in detail, but I’ll tell you that our plan for Wexpro is to increase the spend rate. As Keith mentioned, we identified over $1 billion of future investment potential in Wexpro at attractive finding and development costs that will continue to allow us to deliver gas to our utility customers at a very competitive cost of service.

As a result of this revelation, and a lot of its driven by the increased number of opportunities at Pinedale, but also in the other legacy assets, including Kinny Creek and Trail where we’ve already talked about sharing costs with (inaudible) in development of the shallow Mesa Verde section there. Places like Church Buttes along the Masa Arch.

We want to try to drive, and a lot of this is rig and timing and seasonal restriction dependant, we want to try to drive the capital investment in Wexpro to the $100 million level. Will we get there this year? We’ve spent over $80 million in Wexpro last year. I think it’s achievable, but again, it’s somewhat dependant on seasonal restrictions and when we can get into some of these areas to drill.

Carl Krist – Credit Suisse

Great thanks guys, appreciate the time.

Operator

Thank you, your next questions comes from Faisel Khan with Citigroup

Faisel Khan - Citigroup

Hi it’s Faisal.

Keith O. Rattie

Good morning Faisal.

Faisel Khan - Citigroup

Good morning. Keith, last quarter you talked about how the servicing costs in the Rockies were something you were concerned about, and that was somewhat effecting your drilling plans for ’07. Is that something you’re still concerned about? And where are you seeing those costs right now?

Keith O. Rattie

Thanks for the question. We commented in our last call that we thought service’s costs had escalated at a rate that was getting ahead of where commodity prices were, and where margins were, and margins of course drive returns and thus capital spending in the E&P sector. Chuck can give you more color on this, but we are seeing day-rates and other services costs beginning to adjust to a new market circumstance.

Charles B. Stanley

I think that’s about the level of color I’d like to give Faisel. Obviously constant negotiation and discussion with our service providers on the appropriateness of their costs and charges relative to the forward commodity price environment. And I’m just going to leave it at that.

Keith O. Rattie

I think theory suggests that there could be a pretty good adjustment.

Faisel Khan - Citigroup

Ok. And could you just go back to your ’07 CapEx guidance for market resources. What’s the breakdown between E&P, Wexpro, gas management and marketing? If you can give us a second so we can count slightly to $700 million total.

Charles B. Stanley

About $65 million planned in Wexpro growth and as I mentioned we hope we can do more then that, about $525 million in Questar E&P. A (inaudible) amount in Questar energy trading and about $110 million or so in our gathering and processing business. I hope that adds up to about $700 million.

Faisel Khan - Citigroup

OK. In the your drilling budget of $525 million, does that include kind of the, you said you may drill 12 wells in the Uinta, is that included in that budget?

Charles B. Stanley

When we set our capital forecast, last year, last fall, and rolling into the first quarter, we risk those outcomes, because we're not sure if we're going to get 12 wells drilled and I think if you listen carefully, Keith said we may drill 12 wells.

Faisel Khan - Citigroup

Right.

Charles B. Stanley

A lot of it again depends on where we move rigs and when we move rigs into the Uinta. We've got one rig down there right now that's capable of drilling these deeper wells, so it will depend on our decision on where we move rigs as to which area and how we allocate capital, which area receives that rig and how many wells we can accomplish there,

Stephen E. Parks

Capital allocation is going to be driven by a host of factors that we described this morning and our ongoing focus on returns of capital.

Faisel Khan - Citigroup

OK. So do you see flexibility in kind of moving that $525 million number up over the course of the year?

Charles B. Stanley

Yeah, you know, we'll have to wait and see, we’ll form projects that meet our investment criteria, the other wild card just to fill in the other blank is, it's very difficult, especially in the mid-continent for us to predict third party activity where we're not the operator. Where other companies operate the wells and we have anywhere from a single digit, low single digit working interests, to sometimes 50% or more of the working interest in a well.

Last year there was obviously a lot of third party drilling activity in the mid-continent, we're waiting, like everybody else on this call, is to see what people say about capital budgets for the remainder of this year and some of the key areas and obviously that is very difficult to predict right now.

Faisel Khan - Citigroup

OK. And what's the well count you’re expecting in Vermillion for ’07?

Charles B. Stanley

It will be somewhere between six and a dozen, depending on what we decide to do with the rigs out there.

Faisel Khan - Citigroup

OK. And then in terms of the amount of pipeline capacity that market resources holds to get gas out of your basin, I guess besides the basic swaps you have and the hedging you've done that to the well, you guys have pipeline capacity that can take gas out of the basin?

Charles B. Stanley

We don't hold a lot of firm capacity; we're sort of more the view that the holding firm capacity on the long hall is not a very profitable maneuver.

We sell our gas mostly to, well we sell all our gas to third parties at the interstate pipeline connection point with the midstream systems and most of those purchasers are the firm capacity holders.

Faisel Khan - Citigroup

OK.

Charles B. Stanley

And what we try to do, obviously, in areas where we're concerned about capacity, make arrangements for long term, longer term physical sales of the gas, in order to make sure that the gas will flow.

Faisel Khan - Citigroup

OK great, thanks for the time guys.

Operator

Your next question comes from Shaun Grant with Zimmer Lukas.

Alex Mayer – Zimmer Lukas

Hey good afternoon guys, hi, it's actually Alex Mayer.

Just in terms of your DD&A rate, I noticed you guys had kind of a big jump in the fourth quarter, and I'm just wondering what you're expecting for a full year ’07?

Charles B. Stanley

First of all the big jump in the fourth quarter, Alex, is driven by…we report DD&A on a volume weighted basis, so you’ll recall the fourth quarter we voluntarily curtailed about our VCF for production and we also suffered some involuntarily curtailed most related to some regional pipeline outages as well as some work that we had scheduled on our midstream assets but we decided to go on and do but it ended up taking longer than we originally anticipated.

So the bump up in DD&A in the fourth quarters in part impacted by the lower volumes that's impacting it.

The second comment would be that, this year as Keith mentioned, we're expecting a little bit higher DD&A rate than we were originally forecasting. I think for the full year, we're looking at somewhere in the $1.70-1.75 range.

Alex Mayer – Zimmer Lukas

Yeah? And I guess the next thing that you guys mentioned, you talked about, in terms of a differential for the crude you guys are getting. What's the differential you guys are kind-of baking in right now? And what has it historically been for crude versus WTI?

Charles B. Stanley

Most of the crude oil...Well, we have basically two types of crude oil that we sell. You know, we're not a big crude oil producer. The biggest volume that we sell is black wax in the Uinta Basin. And the black wax is basically a captive to the refining complex in Salt Lake Valley.

And over time, we've seen crude coming in from Canada. It has backed-off or reduced the netbacks for black wax in the Uinta Basin. Today, we're looking at a total deduct against Nymex of around $10. And we have a long-term pipeline contract that allows us to receive better netbacks on our black wax than a lot of other producers.

But we're limited on the amount of capacity that we have on that black wax. Overall, when we look at the average for the Rockies, condensate black wax and other crudes, we're seeing a differential of about $8 averaged across condensate black wax and other crude that we produce in the Rockies. And then a lower netback adjustment in the Mid-Continent region because of the (inaudible) area, about $1.50-2.00.

Alex Mayer – Zimmer Lukas

Great. Thanks guys.

Operator

Your next question comes from Ray Deacon with BMO Capital Markets.

Raymond Deacon - BMO Capital Markets

Hey, Chuck. I just had a quick question for you on the supplemental environmental- impact statement. What portion of your activity would be affected by that? And where could your activity level go in the Pinedale, if that's approved?

Charles B. Stanley

Ray, it affects our entire acreage position because, as you remember, our entire acreage block is subject to winter restrictions, primarily designed to protect wintering mule deer, that spend the winters at Pinedale.

The ultimate result from the supplemental EIS is a couple of things. One, it involves all three operators. Each of the operators would be given an area called a CDA, or concentrated development areas, in which they could place a number of rigs, and drill and complete wells year-round. And the “complete” part is the key difference.

Right now, as you know, we could have six...we have six rigs working through the winter at Pinedale, but we're only allowed to drill and case the wells, and not crack them and turn them into sales until May. And then from May through November, we're allowed to have full access to the area of our leasehold.

With the supplemental EIS, we would be able to drill, complete wells, move rigs within the CDA, basically do all the things that we can do in the summertime in the winter and as a result, we feel like we should be able to drill substantially greater number of wells than we're drilling right now.

It's a guess right now, but I think a reasonable assumption would be that we should be able to double the number of wells. Under the current rules, we can drill about 50 wells, plus or minus a year, some years a few more, some years a few less, depending on our ability to move the rigs and when we finish up on the winter drilling.

So, moving to the concentrated development areas under the FCIS, you know, doubling is reasonable. But we'll just have to wait and see how the records decision comes out and what it says, finally before I can give you a more accurate prediction.

Raymond Deacon - BMO Capital Markets

Got it, got it.

I’ve read parts of the document but it's fairly long. The issue with ozone has to do with the diesel compressors versus say another kind of compressors. Is that the right way to look at it?

Charles B. Stanley

Well basically ozone is a component of the air quality section of the FCIS. There's a number of things that are considered. “Sox & Nox” the combustion products that impact visibility in particular, haze is another term that people use, is one of the primary areas of concern along with those. And any combustion whether it be from a natural gas fired reciprocating engine, a gas turban, diesel engine on rigs…each of those contributes to the total emissions and therefore it would be targeted for reduction pursuant to the FCIS.

And the basic precept contained in that voluminous document is a reduction in total emissions based on a 2005 baseline of 80% over five years. So that sounds like a huge number but we believe there are technologies to allow us to meet that reduction requirement and introduce some additional rigs into the area.

Raymond Deacon - BMO Capital Markets

Okay, great. Thanks a lot Chuck.

Operator

Your next question comes from Mike Helm with A.G. Edwards.

Michael Heim - A. G. Edwards & Sons

I think my questions have been pretty much answered. I'll just throw out one. Can you tell me on the gain on the assets sale what those assets were and did that all fall into the fourth quarter?

Charles B. Stanley

The predominant asset, the one that drove the gain, was sales of non-core properties we had in western Colorado; E&P properties in western Colorado. And it was a third quarter event. We also had some small midstream asset that we sold as well. But the lions share of it Mike, was some lease hold and a few wells in western Colorado.

Michael Heim - A. G. Edwards & Sons

Okay, thank you.

Operator

Your next question from Marshall Carver with Pickering Energy.

Marshall Carver – Pickering Energy Partners

Just wanted to ask a quick question on the mid-continent region. What's driving the incremental growth and increasing your numbers? And then some thoughts on 20 acre spacing in the Elmgrove area. Are you guys moving forward with that and booking any of those reserves in 2006 and then going into '07?

Charles B. Stanley

Obviously, I think David, you hit on the driver. Elmgrove last year was the major driver in production volume growth in our mid-continent regions.

As to 2007, we today have two rigs working out there. We're seeing a decrease in the number of days it takes us to drill a well. We're getting more and more efficient at moving rigs out and getting wells completed. So we hope to continue to improve there.

As for 20 acre spacing, if you look at the…and I don't have the slide presentation in front of you, we have a little slide on Elmgrove, you'll see that our acreage is in two areas. The area to the north which is very close to the major growth fault that expands the section, we are already developed on less than 40 acre density over most of our acreage there. And we have probably an average of about a third working interest in those locations.

There are a few more (inaudible) wells to drill in that area. We are seeing some signs of interference in those wells but predominantly new reserves being added. And I would guess, I haven't calculated it lately, but the average well density in there is probably like 30 acres or 32 acres.

That's a different animal David than the area to the south where we have a large continuous acreage block. In that area we tend to see more stratographic complexity and less vamoginous and predictable section.

We haven't drilled any 20 acre pilot wells yet. We understand some other operators have. We'll obviously be watching those. We don't have any 20 acre reserves booked. In fact, we have very very few undeveloped locations booked in Elmgrove right now. Mainly because we consume the PUDs so fast that the administrative hassle of continuing to roll the PUDs to new locations. And the cost associate would be keeping track of that with our independent engineers just isn't frankly worth it because as you know we're successful effort shop.

Booking PUDs doesn’t do us any good, and the lease hopeful is only when the reserves are in the producing pool, that it has an impact on DD&A rate.

Outside of Elmgrove, the other area that we’re active in…a lot of activity planners in the western mid-continent and the granite play over in the Texas panhandle, we’ve got a rig working full time there, and we’re thinking of picking up a second rig.

Marshall Carver – Pickering Energy Partners

Thanks a lot for that. And just to probe a little more on the cost side, and completion costs in pressure pumping and rigs. Our observation seems like the Rockies have held in a little firmer than some of the other regions. Is that a fair comparison between what you have seen in the North Louisiana mid-continent and the Rockies’ as far as costs changing?

Charles B. Stanley

David…I don’t want to jaundice my discussions I’m having with my service contractors. I think there’s been movement in both places. But obviously in the mid-continent, there are a number of players, smaller players who are drillers only with free-cash-flow. And their activities may slow down before the large, independent operators.

If you look at the Rockies, the resource plays are dominated by large independent operators, so they’re not slowing down as quickly to the price signals as some of the other areas.

Marshall Carver – Pickering Energy Partners

That’s helpful, thanks guys.

Operator

Your next question comes from (inaudible) with (inaudible).

Analyst

Hi, good morning guys. Just a very quick question.

The process of booking 2P and 3P resources is not as standardized I guess…what’s the economic threshold that qualifies a piece of reserve from moving from 3P to 2P? Does it necessarily have to be economic at a certain price, or is it something else?

Thank you.

Charles B. Stanley

A probable reserve seal is one that is more likely than not to be recovered at current costs at current technology. Possible reserves do not have that economic criteria embedded in them. On a probabilistic basis, a probable reserve carries with it sort of an inherent 50/50 probabilistic assignment, whereas a possible reserve carries about a 10% probabilistic assignment.

Keith O. Rattie

I would add to that, that the 50/50 is a rule of thumb, but in a circumstance like Pinedale, which is where a significant chunk of our probables are, the probability that we’re going to recover those reserves is well above 50%.

They’re not booked as improved because of SEC rules that prohibit booking of skip offset.

Charles B. Stanley

That’s a good point Keith, you hit the nail on the head. There is, I think amongst the independent reservoir engineering firms, a growing stance on the basic criteria that need to be applied to the reporting of a probable reserve or possible reserve in the categorization.

We’ve used a very uniform and consistent approach in our exercise, along with our independent engineer Rider Scott. It’s one that follows the general conventions that’s been agreed upon by the society of controlling evaluation engineers.

Analyst

That’s why I asked the question, because it’s not a standardized only 2P & 3P level. And the reason I asked the question is just to try and understand…for not as much as the Pinedale, but for things like Vermillion and (inaudible). Would they have to cross a certain threshold in economics, at say $6 or $7 for the well head, before they move from 3P, and graduate into 2P.

I think you answered my questions.

Charles B. Stanley

Generally they do, I think that once things move to the point where you’re drilling wells on them, and you’re booking proved reserves on them, it’s very easy then to argue that the non-SEC compliant locations, in other words, those locations that are within a known gas column that are outside of the direct offset from a producing well, would be strong candidates to be categorized as probable reserves locations removed from the producing wells that are on the edge of the play, either because of, you know, structural accumulations, or closer to water, further-down dip…fall into the lesser category of possible reserves. And then, outside of that is the resource potential, which, in our mind, still requires you to have a well test, or some evidence that there is hydrocarbon presence.

And a pretty good story that the reservoirs and the (inaudible) configuration, in other words, the whole petroleum system that is present, that would augur for the possibility of those resources moving into the probable or possible category.

Operator

Your next question comes from Richard Sulles with Capital One South.

Richard Sulles – Capital One South

Good morning, gentlemen, how are you?

Charles B. Stanley

Good. How are you, Richard?

Richard Sulles – Capital One South

Good. Just a couple of quick questions to follow up on the Vermillion well's performance. If you've gone over this already, I apologize. I had to step away for a moment.

For the most recent wells, what kind of IP rates are you seeing, say, over 30 days?

Charles B. Stanley

These wells average probably 1-2 million a day, over the first 30 days. They come down quite rapidly. And it in part depends on what zones are they completed in: Are they completed in Baxter alone, Baxter-frontier, Baxter-frontier-Dakota?

Richard Sulles – Capital One South

Right. Most of the recent ones have just been completed in the one zone, I suppose.

Charles B. Stanley

Baxter or Baxter and frontier. I don't think we've had any recent Dakota completions.

Richard Sulles – Capital One South

Okay, so what kind of decline are you seeing on these wells over their young life so far?

Charles B. Stanley

Well, right now we're booking them with a hyperbolic exponent of two, a B-factor of two, and a terminal decline rate of roughly 6%, and they have very high initial decline rates, on the order of 85-90%.

Keith O. Rattie

And they start flattening out about a half-million cubic feet a day.

Richard Sulles – Capital One South

Okay. And you said the cost of holding is about $5 million per well, for these recent wells?

Charles B. Stanley

Correct.

Richard Sulles – Capital One South

Okay, okay. I think that does me. I appreciate it, thanks a bunch.

Charles B. Stanley

You're welcome.

Operator

Your next question is a follow-up from Shneur Gershuni with UBS.

Shneur Gershuni – UBS

Hi. Just one quick question about the booking of reserves at the Pinedale. The methodology has not changed at this point right now, in terms of, kind-of what you've said in the past. Is that correct?

Charles B. Stanley

The only fundamental change, Shneur, is we're using a 65%, instead of a 60% reduction relative to the apparent well EUR for the booking of the ten-acre locations.

Shneur Gershuni – UBS

And was that based on some of the data that you'd collected, just, in general over the past two years, or is it more related to drilling the five-acre test over the past summer, and sort-of the result?

Charles B. Stanley

I mean, it's the observation of the performance of the ten-acre wells, because, keep in mind, we're drilling ten-acre development wells now from the winter pads. And looking at the well performance from those wells initial performance, the lack of interference in the early life, and what it means...what the implications of that performance means with respect to gas inflation.

We're feeling more comfortable on the reserve assignments to these ten-acre locations, at least in the areas where we booked them. The jury's still out, and we're still waiting to see more well performance from the crestal wells before we book ten-acre PUDs there.

Shneur Gershuni – UBS

Okay. Thank you, Chuck.

Charles B. Stanley

Yep, you bet.

Operator

At this time, you have no further questions.

Stephen E. Parks

Well, we want to thank everyone for listening in this morning. You know how to get a hold of us. We're going to be updating our IR presentation to incorporate our fourth-quarter results, and we'll see all of you at some point on the road pretty soon. Thanks.

Operator

Thank you for participating in today's Questar Corporation conference call. This call will be available for replay beginning at 12:30p.m. Eastern Time today through 11:59p.m. Eastern Time on Wednesday, February 21, 2007.

The conference ID number for the replay is 6006346. Again, the ID number for the replay is 6006346. The number to dial for the replay is 1-800-642-1687, or 706-645-9291. Thank you. This concludes today's conference. You may now disconnect.

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