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Questar Corporation (STR)

Q3 2006 Earnings Call

October 27, 2006 9:30 am ET

Executives

Charles Stanley - President and CEO of Questar Market Resources

Allan Bradley - President and CEO of Questar Pipeline

Alan Allred - President and CEO of Questar Gas

Stephen Parks – CFO

Analysts

Shneur Gershuni - UBS

Carl Kirst - Credit Suisse

Faisel Khan - Citigroup

Sam Brothwell - Wachovia

Sam Delfazzo - John S Herod

Rick Gross - Lehman Brothers

Joe Magner - Petrie Parkman

Rebecca Followill - Howard Weil

Sara Nainzadeh - Millennium Partners

Richard Tallus - Capital One South

John Lawrence - Morgan Keegan & Co., Inc.

Presentation

Operator

At this time, I would like to welcome everyone to the Questar Third Quarter 2006 Conference Call. (Operator Instructions) I would now like to turn the call over to Mr. Stephen Parks, Senior Vice President and Chief Financial Officer. Sir, your may begin your conference.

Stephen Parks

Thank you, Nicole. Good morning. I'm happy to welcome you to our call this morning. Yesterday, we reported that Questar's third quarter 2006 net income rose 45%. It was driven by a 16% increase in natural gas and oil-equivalent production and higher realized gases for natural gas, oil, and natural gas liquids. Questar's third quarter 2006 net income was $95.1 million or $1.08 per diluted share. These results included a $15.8 million or $0.18 per diluted share after-tax gain from the sale of assets, and $8.7 million or $0.10 per share diluted after-tax charge for unsuccessful exploratory wells in Wyoming and Utah; and a $3.2 million or $0.04 per diluted share after-tax charge for unrealized mark-to-market losses on natural gas basis only swaps.

You can access our earnings release on our website at www.questar.com. Following my remarks this morning, Keith Rattie, our Chairman and CEO, will comment on operations, update our earnings and production guidance for 2006 and provide initial guidance for 2007. After Keith's comments we'll take your questions.

We have with us today other members of Questar's senior management, 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 the future operations and expectations of Questar Corporation. These statements are made in good faith and we believe they are reasonable representations of the company's expected performance at this time. Actual results may vary from our stated expectations and projections, due to a variety of factors that are described in our Form 10-K and 10-Q filings with the Securities and Exchange Commission.

Now let me briefly recap our financial results for the first nine months of 2006. Questar nine-month net income was up 46% to $322.6 million or $3.68 per diluted share. There were 87.6 million weighted average diluted common shares outstanding during the 2006 period, compared to 87 million a year ago.

Our Questar Market Resources subsidiary led the way for the first nine months of 2006 with net income of $256 million, up 51% compared to a year ago. Market Resources' nine-month results included the gains from the sale of assets, and charges for unsuccessful exploratory wells and unrealized mark-to-market losses described earlier. Market Resources engages in gas and oil exploration, development and production, gas gathering and processing, also in gas and oil marketing and gas storage.

All four Market Resources' subsidiaries, including Questar E&P, Wexpro, Gas Management and Energy Trading had double-digit increases in earnings in the first nine months of 2006. Questar E&P net income was up 67%, driven by an 18% increase in natural gas and oil equivalent production, and higher realized prices for natural gas, oil and NGL. Wexpro net income was up 13% driven by 14% increase in the investment base over the past 12 months. Gas Management net income was up 23% due to higher processing volumes and margins. Energy Trading net income was up 49% due to higher marketing fees and interest income.

Questar Pipeline, our interstate pipeline and storage business, earned $31.5 million in the first nine months of 2006, up 25% over 2005. This increase was driven by new transportation contracts and higher NGL revenues. The new contracts included the November 2005 completion of an expansion of our Southern System and the December 2005 completion of a new interconnect between Overthrust Pipeline and Kern River Pipeline.

Questar Gas, our retail gas distribution utility, reported nine months 2006 earnings of $19.5 million, 27% higher than a year ago. The improved results were from higher margins from customer growth, and the recovery of $3.6 million of gas processing costs in 2006 that were not recovered in 2005 until the fourth quarter, pursuant to a regulatory order. An additional regulatory order effective June 2006 had the effect of shifting $1 million of net income from the fourth quarter 2006 into the current quarter.

Now, I will turn the microphone over to Keith Rattie, Questar's Chairman and CEO.

Keith Rattie

Good morning, everyone. I am going to comment on '06 third quarter and year-to-date results. I will update you on Pinedale and the Vermillion Basin and some other key operating activities. Then, I am going to turn to our outlook for '07 and beyond. Earlier this week we reviewed our five-year plan with the Questar Board. I am going to give you a glimpse of what management told the Board.

Bottom line on our third quarter, all Questar operating units posted double-digit net income growth in the first nine months of '06, and all are on track to deliver record net income this year. Once again, as Steve noted, the highlight Questar E&P grew production 18% in the first nine months, 17% excluding a previously reported one-time adjustment. Questar E&P grew production 16% in the third quarter compared to a year ago and that makes five consecutive quarters in which Questar E&P has delivered 15% or higher production growth.

Note that we have raised our full year '06 EPS and production guidance for the third time this year. As noted in our October 2nd release, we now expect Questar E&P '06 production to range from 127 to 129 Bcfe, that compares to our previous guidance of 126 to 128 Bcfe and actual '05 production of 114.2 Bcfe. Note that we raised our '06 production guidance despite our curtailment of 1 Bcfe net production in the Rockies in October.

We now estimate that '06 EPS could range from $4.65 to $4.75 per diluted share. That's compared to our earlier guidance of $4.50 to $4.70. We put a table in our release to reconcile the new guidance with our previous estimates and as always, we exclude one-time items such as gains and losses on asset sales. Note that we have now hedged about 76% of our fourth quarter '06 gas and oil equivalent production, so we have taken commodity price volatility mostly out of the equation for Questar for the remainder of this year. But we estimate that a dollar change in the average NYMEX price of natural gas for the remainder of year will impact EPS by only about $0.02 per diluted share.

Note that Questar E&P's cost structure is rising, but remains in the top quintile of the US independents. We remain intensely focused on where we rank relative to the industry. You will hear that theme more later. We intend to keep our cost structure in the lowest quartile of the industry.

Now, let me comment briefly on our decision to shut-in about 2.3 Bcfe gross, or about 1 Bcfe of net, unhedged production in the Rockies for the month of October. As you know, most of our Rockies production is profitable, even at low prices but that wasn't the point. We, in effect, decided to store gas in the reservoir to wait for higher prices. We expect less production when we bring these wells back on next week and we should get much of the shut-in production back this winter at higher prices.

Let me briefly touch on third quarter highlights from operations. As you note, Questar E&P produced 33.8 Bcfe in the third quarter, that's up 16% from a year ago. Note, Pinedale production was up 25% compared to a year ago and now it comprises about a third of Questar E&P third quarter production. Please note that with expanded winter drilling, our Pinedale production profile has changed. In the past, our Pinedale production has declined over the first half of the year, bottomed in June, turned up and peaked in the fourth quarter. This year, because we came out of the winter with 33 wells to complete in the second and the third quarter, we expect the Pinedale peak in the third quarter.

Our production guidance for the remainder of the year assumes that Pinedale fourth quarter production could be about flat to third quarter production. As in previous years, Pinedale production will decline all winter and into the early summer and won't turn up until we move the rigs off the three winter pads and begin to complete the wells we drilled during the winter.

Now turning to Rockies legacy, production growth slowed just a bit up 5% in the third quarter, after two quarters of double-digit growth. Growth in the Vermillion Basin and Wamsutter offset decline in mature areas. The Uinta Basin production fell 2% compared to the year-ago period. As we said for several quarters, our core 40-acre Wasatch upper Mesa Verde play has matured. Note that we are now evaluating 20-acre density for the Wasatch Mesa Verde formations and will need increased density in the shallow section and success in the Mancos deep play to overcome decline and turn production backup.

Note also that our Mid-Continent team did it again. They delivered 24% production growth in the third quarter compared to a year ago, again driven by our Elm Grove play in Northwest Louisiana.

Let me give you more color on our major play starting with Pinedale. So far this year, we have completed and turned 45 Lance Pool wells for sale at Pinedale, including the 33 wells we drilled during the restricted winter drilling season. At peak, we ran a nine-rig program this past summer. We are now moving on to the winter pads of Pinedale. Recall that under the BLM imposed restriction, we will drop down to a six-rig program this winter.

So we have sent two of our better performing Pinedale summer rigs down to the Vermillion Basin for the winter. We remain on track to complete 45 to 48 wells at Pinedale this year. So, we expect to exit '06 with about 192 to 195 wells flowing to sale. Our results-focused Pinedale team -- and those of you who have been on the Pinedale you have seen this in action -- continues to deliver. We averaged about 42 days from spud to TD on our summer drilling program. We are not aware of any other Pinedale operator with these results.

Recall that we have over 932 well locations on 10-acre density on our acreage, so we will start next year with over 738 wells yet to drill on 10 acres. Our Pinedale play is still in the second inning.

Please note we have also drilled and completed four pilot wells to evaluate five-acre density drilling on our Pinedale acreage. We drilled these wells as five-acre offsets to some of the oldest producing wells in State Section 16 on the Eastern flank of the Anticline.

Now before we ran casing, we ran a tool to measure the pressure in about a dozen sand bodies in each of the new wells. Our technical team chose the sand bodies that appear to be continuous between the new wells and the older offset wells, some of which have been producing for at least six years or more, and one that has been on production for over 20 years.

In other words, what we did is we deliberately chose to measure pressures in the sand bodies that would most likely show depletion. We also chose sands that appeared to have the best rock quality, again, we are looking for interference. The early results are intriguing. While some sands did show less convergent pressure, the level of depletion was less than we expected. We have now completed and turned all four wells and of course we are going to closely watch the well performance for signs of interference.

We are also updating our reservoir stimulation based on the new results. The bottom line, at least in the pilot areas, these early results suggest that there's a technical argument to support five-acre density on at least part of our acreage.

Let me comment briefly, and perhaps for the final time, on the Pinedale deep test. The jury has come back with its verdict in September. We plugged and abandoned the deep section, and took an after-tax charge of $6.3 million for our share of the costs of the Rock Springs and Hilliard test.

From here on out, we are going to focus on our core Lance Pool Pinedale play. Recall, we told you in the July call that our decision on the deep play would depend on our test of the upper Rock Springs, i.e. if the incremental returns to drill and complete the Rock Springs don't work, then the deeper Hilliard doesn't work. In August we pumped three stages in the upper Rock Springs. We produced gas, but at rates less than what we would need to earn acceptable returns on capital.

To be sure, there's a lost of gas in both the Rock Springs and the Hilliard but its rate recovery and margin that drive returns, not gas in play. Therefore, after putting the cement to it, we moved up hole in the deep well, completed the Lance Pool and turned it to sales in late September. The Stewart Point 15-29 well is in the highest EUR area of our acreage block and it flowed at an initial rate of about 15 million cubic feet per day.

Let me turn briefly to the Vermillion basin. Recall that we have been focusing investor attention on two key delineation wells, the Sparks Ridge Unit Number One well and the Alkali Gulch Unit Number Three, you can refer to slides 15 and 16 of our IR presentations, which you can find on our website.

These wells, as we have said, will test our thesis that the aerial extent of the Baxter shale component of this play is defined more by overpressure than structure. The Sparks Ridge well, in particular, is a big step out from the other deep wells we have drilled to date. Both wells have now been drilled and completions are underway. We stimulated the Sparks Ridge well and started flow back and we are now fraccing the Alkali Gulch well.

Very early results from Sparks Ridge are different from earlier wells. It's made over 200-barrels of either oil or liquid hydrocarbons per day but the natural gas rate has been lower than our other wells. On an Mcf equivalent basis, the wells initial performance is about in line with the other Vermillion basin wells but significant amounts of oil or condensate in the flow stream may require different production methods than previous wells. We are not sure at this point how it's going to behave long-term. Sparks Ridge is the shallowest well we have drilled to date, and as I said, it is a long way from our other wells. It appears that we have found the edge of the over-pressured cell.

Overall, we now have 13 Vermillion Basin wells flowing to sales and well performance remains consistent with our estimates that the Baxter Frontier and Dakota reserves could range from 2 to 4 Bcfe per well.

As we have stressed, our technical team remains focused on optimizing completion design to maximize frac extension and rate while driving down cost. And to that end, as I mentioned, we have released two of our least efficient rigs and moved two of our better performing rigs from our Pinedale summer program down into the Vermillion basin for the winter. In short, we are hoping to see better drilling performance.

Briefly in the Uinta Basin, we drilled and completed and turned our third Mancos test to shale September. Recall that Mancos shale is the age equivalent of the Baxter shale in the Vermillion basin and as in the Vermillion, our technical team is focused on driving down drilling and completion costs to improve economics in this play.

This is the point in the call where I would normally comment on third quarter results from our other businesses, Wexpro, Gas Management, Questar Pipeline and Questar Gas. I just note that third quarter results in each of these businesses were in line with our expectations, and all four remain on track to post record earnings in '06.

When we get to Q&A, you may want to ask Alan Allred about the positive regulatory development in our utility business in Utah. We have agreed to implement a Conservation Enabling Tariff. We call it the CET. On a trial basis with a one-year review, the CET decouples Questar Gas revenues from customer usage. Questar Gas will implement the demand side management programs approved by the PSE.

Let me turn now to our outlook for '07. Earlier this week, as I said we reviewed our 2007 plan and our five-year plan with the Questar Board of Directors. Here's a quick glimpse of what we told the Board. First, we estimated that '07 net income per share could range from $5.20 to $5.50 per diluted share. This, of course, excludes one-time items and assumes the hedges on gas and oil production currently in place and summarized on the table at the end of our release.

I note that with 86 Bcfe hedged in '07, we have cut our exposure to commodity price volatility significantly. We now estimate that a dollar change in the average NYMEX price of natural gas will move 2007 EPS by about $0.22 per diluted share. Note that we estimate that Questar E&P 2007 production could range from 132 to 135 Bcfe, up 2% to 5% compared to 2006.

Yes, we are sending a message with our '07 production guidance. That message is not that we don't have the organic growth, we do. The message is that we think day rates and related services costs are out of sync with lower natural gas prices. We can grow faster, but if cost inflation continues, we are prepared to slow Questar's E&P growth to protect our cost structure and thus future margins.

We plan to complete 45 to 48 wells at Pinedale next year, compared to 48 to 51 wells this year. Why the difference? Well, we ran a seven-rig program this past winter. We are back to a six-rig program this winter.

A quick update on the Pinedale SEIS. This is one of the important drivers of the growth beyond 2007. We expect the BLM to issue the draft SEIS for public comment sometime in November, but we are not expecting a record of decision until the summer of '07.

If approved by the BLM, the SEIS will have a big impact on our growth over the next five years, but please note that that impact won't kick in until 2008 and beyond. Next year, we plan to drill again about a dozen new Baxter, Frontier, and Dakota wells in the Vermillion Basin, including our first horizontal well and we are going to drill about five Mancos, Blackhawk, Mesa Verde wells in the Uinta Basin.

Our Mid-Continent growth will probably slow significantly from the 25% we have seen in the first nine months of 2006. Our veteran Mid-Continent E&P has been defying gravity for years. They have a great track record of generating new growth opportunities and what we believed to be a mature leasehold. We do have one good growth play, we still have over a 140 high working interest operated locations and over a 100 non-operated locations to drill in the Elm Grove field in Louisiana. But well defines are steep, the treadmill is accelerating, we haven't made a significant acquisition in Mid-Continent for nearly a decade and there are only so many rabbits in the hat for these guys.

We intend to invest at least $80 million in new drilling in Wexpro in 2007. Wexpro's future has never looked brighter and I am going to comment on that in a bit when I get to our five-year outlook. Gas management next year, net income, gas management could grow 10% with some sensitivity to the frac spread in our processing business.

Pipeline net income could be flat to down slightly in '07. Pipeline's jump in earnings this year has been in part the result of higher NGL recoveries. We expect NGL recoveries to decline as shippers process upstream of Questar pipeline to meet lower hydrocarbon dew point specifications on downstream pipes.

Questar Gas, our utility, net income could grow about 3% next year, i.e., about the rate of growth in its customer base, we do expect the utility to earn its 11.2% allowed return on equity.

Let me close by giving you a look at the five-year plan we showed our Board earlier this year. The Board is going to hold us accountable for doing this. We believe, first, that we can continue to grow net income at high-single digit or low-double digit rates over the next five years if commodity prices remain at or near the current forward strip. We have very good visibility on this growth, it's all organic based on projects that we have already defined.

Now notwithstanding the near-term slowdown reflected in our '07 guidance, we believe we can continue to grow Questar E&P production at a compound annual growth rate of 5% to 10% over the next five years, again, without an acquisition. We are going to remain keenly focused on where our cost structure ranks relative to other US independents. We are running the business to be one of the last ones standing. If there is a fallback, we are going to manage our growth to keep the cost structure among the lowest in the industry.

Pinedale production will grow significantly over the next five years, if the BLM approves the SEIS, we could be drilling 80 to 100 wells per year at Pinedale by the end of the planned period. We hope to turn the Vermillion Basin and Uinta Basin deep plays into new growth plays for this company, but as we stress, we have got work to do to get our completed well cost down, so that these plays work at a $6 NYMEX gas price. Hence, we are remaining cautious next year with capital allocations. Now we need to put more assets into the hands of our Mid-Continent team. We are going to look for the right opportunity to do so, but our forecasts do not assume an acquisition.

Wexpro. Wexpro is the most under-appreciated business unit in the Questar portfolio. This month marks the 25th anniversary of the Wexpro agreement. Over the last 25 years. Wexpro has produced almost 1 trillion cubic feet of natural gas on behalf of the utility gas customers, and yet Wexpro's future appears brighter today than at any time in its 25-year history. We told the Board earlier this week, Wexpro now estimates that it has over $1 billion of identified risk, future investment opportunities, and additional development drilling locations that we think we can develop at a cost of service well below the current forward strip.

Therefore, we are going to ramp up Wexpro investment to over $90 million per year over the next five years and beyond to develop this inventory. If we do, production should grow significantly. That's good news for Questar Gas customers and it's good news for shareholders because Wexpro earnings could grow at a compound rate of 12% to 14% over the five-year period. Recall that under the Wexpro agreement, Wexpro earns a 19% to 20% after-tax un-levered return on its net investment base.

At our field services company, Gas Management, net income could grow at about 10% per year over the next five years. Unlike other midstream companies, Gas Management can piggyback on the investment we are making in Questar E&P and Wexpro in the Rockies. By end of the planned period, over 90% of Gas Management's revenues will be fee-based.

Turning briefly to the regulated businesses. Questar Pipeline net income as I said will be flat-to-down slightly next year but could grow at 6% to 8% per year over the remainder of the planned period, driven by projects that are underwritten by contracts. Specifically, the most significant is the build out of Overthrust Pipeline and the expansion of our pipeline from the Uinta Basin less the Kern River Pipeline.

Questar Pipeline's mandate over the next five years remains as it is today and we want them to identify and eliminate interstate pipeline bottlenecks in our core Green River in Uinta Basin producing regions. Also note that we told the Board, we are deferring a decision on the possible formation of an MLP until after the Overthrust build out is complete. Barring regulatory problems, Questar Gas net income should grow at 3% to 4% over the next five years. That's about the rate of customer growth, and that means that at the end of the planned period, Questar gas will be contributing less than 8% of corporate net income.

Our balance sheet will remain strong. Cash flow will remain strong. In fact our current plan shows we will generate significant free cash flow over the five-year period by the end of the period. If we find attractive projects we will reinvest. If we don't, we will return cash to the shareholders. We don't have a buyback plan in place today but we can put one in place very quickly if we decide to.

Bottom line, if we execute the plan we showed our Board, barring a significant decline on commodity prices, investors who hold our shares over the next five years should be pleased. We are going to hold ourselves accountable, as will the Board. We will have more details when we hold our semi-annual investor meeting in Boston and New York on November 14 and 15. And now we will be glad to take your questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Shneur Gershuni with UBS.

Shneur Gershuni - UBS

Good morning, guys. Great quarter. A lot of information on the E&P side. I just had a couple of follow-up questions. You had mentioned that you drilled four five-acre pilot wells and so forth. Would you be able to talk about relative theories? Does it sort of create an interesting opportunity with respect to how the type curve might change with respect to the 10-acre bookings and so forth? Just looking for some more color on that, if you have that.

Charles Stanley

As Keith mentioned in his prepared remarks, we drilled four wells. We deliberately sited these wells offsetting the oldest producing wells, including the oldest producing well on our property, which has been in production since the 1980s. The other wells as old as six years.

What we did, as Keith mentioned, we measured pressures, about a dozen pressures in each well in the most obvious, continuous sand bodies and what we saw was some of them exhibited less inversion pressure and some of them at 50% to 60% inversion pressure. But many of them, even though they looked continuous for log correlation did not appear to be significantly drained.

What that means is that not only is there architectural reason that this continuity between the individual sand bodies that affects drainage, but also even in sands that appear to be continuous, the Rock properties are so forward that five-acre spaced wells don't appear to be adequately draining the reserves.

What does it mean for booking methodology on 20-acre wells? You recall, we booked our 20-acre proved undeveloped locations at 75% of the reserves and assigned to a 40-acre parent well within that 40-acre unit. That methodology was based on our reservoir model and was deliberately conservative in order to make sure that we didn't overbook reserves.

This drainage information will be put back into our reservoir simulator and we haven't finished that work yet, but just looking at it, it would appear to bode fairly well for an increase in reserves to the 20-acre locations, and probably an increase to the 10-acre locations as well. You will recall in the case of 10-acre wells, we are booking those at 60% of the recovery or estimated recovery from a 40-acre parent well.

The reservoir simulation work will take a few months. Obviously the pressure data is important but just as important to me and to our reservoir engineers is the performance of these wells over the next six to 12 months to see if they perform similarly to the original wells drilled on a looser spacing, on a less dense spacing. If they do, then it bodes well for increasing recoveries on 10-acre and 20-acre locations. We just have to wait and watch and see.

I would also point out, this is a sample of an area that the area we drilled these wells in is on the flank of the structure, in an area where we would expect the rock properties to be poor quality. So we would expect smaller drainage radiuses in this area than we would, say, on the crest of the structure, just because of the deterioration of the rock quality.

As Keith mentioned, we think the five-acre data that we have today is encouraging for five-acre development, at least on part of our acreage. We need to collect more data on the crest portion of the acreage and obviously get more time series on these wells before we get more confident.

Shneur Gershuni - UBS

Chuck, does this present an opportunity to explore 2.5-acre spacing?

Charles Stanley

Never satisfied. We will see interference on this wells. There's no doubt about it. Interestingly, if you think about it, if we drilled all of the locations on five-acre density right out of the box, it's not likely that we would see instantaneous interference between these wells. It will take sometime.

That has an important ramification for the net present value of the production stream coming from a well, even if it does exhibit interference later in its life because, as you recall, typical Pinedale well recovers half of its reserves in its first five-and-a-half or six years of its life. So if we could get near virgin reservoir out of the well for the first four or five years without seeing any degradation from interference, then a lot of the present value of that production stream is locked in and the remaining 40 years of the well life, even if there's interference which results in a steeper turnover decline.

We currently have these wells booked on an 8% turnover decline, even if it went to 12% to 15%, the flush production from the front end of production curve has an important ramification for net present value and could argue for drilling these wells on five-acre density even if they do interfere in their lateral wells.

2.5-acre wells, it is way too soon. I intuitively think that based on the drainage, the calculated drainage radiuses that we have seen and these are elliptical draining radiuses that parallel and link to Anticline. Five-acre wells should drain over time the gas in place. Not instantaneously, but over time. 2.5-acre wells, I think you will see almost immediate interference and probably would not be wise to drill at that dense of a spacing.

Shneur Gershuni - UBS

Okay. That's great. And just one last question. Just you had mentioned in the prepared remarks about the Vermillion well and you were seeing oil and so forth. I was wondering if you can elaborate on that?

Charles Stanley

Sure. We have seen small amounts of condensate. Condensate is a straw-colored liquid hydrocarbon, about the same density and specific gravity as gasoline. Condensate is a different animal than oil, because in the reservoir, at reservoir temperatures and pressures, the condensate is in a gaseous phase and it only condenses into a liquid as the well is produced and the gas flows to the surface, the condensate drops out of solution and forms a liquid phase.

What that means is that at reservoir temperatures and pressures the condensate doesn't affect the permeability of the rocks. Low permeability rocks like shales and tight gas sands don't like free liquids, because the free liquids effectively block up the pores and restrict the flow of gas in the reservoir. So we were concerned when we see liquids that they are either condensate or we get dry gas production.

Interestingly, the first 12 wells that we drilled out here, we saw traces of liquids and they appear to be condensates. We have taken samples of them, we have taken them back to reservoir conditions and they go back into solution into the gas. This last well, the Sparks Ridge that Keith mentioned, is drilled basically on the edge of what we have identified as the over-pressured cell. It's a shallower well that the top of the Baxter and the top of the Frontier are shallower than any of the other wells we have drilled.

In this instance, it appears that we don't have a condensate liquid. We have a true oil. Now this is based on sort of the rules of the thumb of looking at the oil, smelling it, looking at its color, the behavior of the well as we produce it, and that black oil, it first scared us, because we were concerned that it would block up the pores and restrict the permeability of the rock, but the well seems to be behaving normally. It's just it has a very high oil-to-gas ratio.

We haven't done the laboratory work to confirm that it is a true black oil. That means it would live in the reservoir as a liquid, rather than as a gas. If it is, then clearly the rock properties are such that it is allowing that oil to move to the well bore. We want to make sure that it will continue to flow to the well bore and as Keith mentioned, it presents some additional headaches for producing.

One would be that over time, the oil would have to be artificially lifted, either with gas lift or with a pump in order to keep the rate up. The other is obviously just dealing with oil production in addition to gas production in the area. Right now, we don't even know where this oil is coming from; we haven't run our production log yet to determine whether it was coming from the Baxter or from the Frontier or Dakota. So there are lot of unanswered questions here.

Keith mentioned that we think we have found the edge of the pressure cell. We think we can map the over-pressured interval with the 3D seismic data. It has a very unique seismic response. So we predicted that we would be basically on the edge of the cell. The pressures that we encounter when we drill the well were lower than the typical Baxter wells that we drill today, still over-pressured, but only slightly so.

What does this oil mean? As you move out of the cooking pot, out of the center of the Vermillion Basin towards the periphery, the temperatures and the generation conditions are such that oil can still survive and be in a liquid phase on the edges of this play. So, we don't know what it means yet as far as future prospectively. We know that there's oil in the Sparks Ridge well likely to be free oil and not condensate. We can map the edge of the over pressured intervals, so we know that we are right on the edge of it. It may be that we have an oil play around the rim of this basin; we just don't have enough data yet to give you any more color on it, unfortunately.

Shneur Gershuni - UBS

That's great. I just wanted to confirm one last thing. You had mentioned the central creation of an MLP that is basically just delayed until Overthrust is completed. Did I understand that correctly from your report?

Keith Rattie

That's right. We deferred a decision on that. We had a discussion with our Board, but don't expect any action until we complete the build out of Overthrust. We have to focus on execution in the next couple of years.

Shneur Gershuni - UBS

I definitely agree. Thanks very much.

Operator

Your next question comes from Carl Kirst with Credit Suisse.

Carl Kirst - Credit Suisse

Good morning, everybody. Also congratulations on a great quarter here. Chuck, just a quick clarification here on a response to Shneur's question on the 5-acre pilot. The understanding that you need to get some time to see the performance, the six to 12 months that you referenced, was that to gain comfort on what the level of interference was? Or did that include, we won't revisit the booking methodology until then too? Or can we revisit the booking methodology on the 20-acre and 10-acre, say, for instance in the next couple of months?

Charles Stanley

Good question, Carl. I think it's the former. We will want to see longer-term performance on these wells to make sure that the initial pressure readings that we took in the 12 or so sands in each of the four well bores are indicative of the overall pressure regime of the rest of the untested sands, because remember, in every one of these well bores there's literally hundreds of individual sands and when we multi stage frac these wells we commingle all of that production. So it will take a while to see the effects of partial depletion in the well performance.

Clearly, after a year or so, we'd have a much higher confidence in what that data is telling us about specifically the 5-acre performance, and more importantly the ramifications for booking methodology on the less densely spaced wells.

The other thing I didn't say in response to Shneur's question just to remind you of why we are doing this now. As part of the supplemental EIS, we have committed, if the BLM approves this proposal, to move into a concentrated area of development, and basically drill Pinedale development wells on whatever we determine to be the ultimate optimal spacing and then basically progress. We would, in our concentrated development area, we will progress from south to north and fully develop the Anticline on whatever spacing is deemed appropriate and not come back to these areas to drill additional infill wells.

Which we means that we need to know the answer on 5-acre density sooner rather than later because we will be drilling 5-acre developments wells in a full development phase within the next several years after we receive approval.

So, it's an important question that needs to be answered right now. We will be drilling some more 5-acre wells in 2007 to gather additional information outside of the current area, and that information along with the performance of these wells over the winter will be very important.

Carl Kirst - Credit Suisse

Chuck, you just hit on my second question and do you actually have a number? I mean is this four going to expand to 20 or is it smaller samples than that?

Charles Stanley

The only place where we get meaningful short-term data is by offsetting the older wells that have been on production long enough to have depleted reservoirs in their immediate vicinity. So, we will drill a handful and right now, I don't know exactly how many we'll drill. It depends on what we see from these wells. We'll make that determination on the fly as we go through our 2007 development program.

Carl Kirst - Credit Suisse

Great. If I could just ask one other question here. As we look into 2007, obviously, being very cost conscious of oil field inflation, is it possible you can tell us if there's been an E&P budget set for 2007? And in the earnings guidance that was given what your embedded unit cost expectations are on that?

Stephen Parks

We talked to the Board about our budget. We're a bit cautious at this point about talking about absolute capital commitments until we get a better sense for our commodity prices. Frankly, in the commodity price environment, how quickly we see winter draws on stores, how dramatic those draws are, and we'll allocate capital to these various programs based on what we see for commodity prices.

Frankly, regional pipeline capacity is tight. We saw it in the fall here. We are concerned about it. Obviously, during the shoulder season in the spring, we are frankly shocked at the narrow basis during the summer and early fall this year. We were saved by record burns for power generation in the Southwest.

So, as producers continue to develop these Rocky Mountain plays and drive production volumes, we think base is going to widen back out and could widen out dramatically. So, we want to be cautious not to overdrive production growth into what could be a dramatically declining commodity price environment.

Keith Rattie

Carl, just a couple of other comments on that. The Board has indicated its support for a capital program up to $1.1 billion, but I stress the “up to” part. We look at the current situation, we are about 65% hedged next year, but we obviously cannot hedge our cost structure. It's my opinion that services sector costs have outpaced commodity prices right now and we need to see some moderation in services sector costs and we're going to look for that. If we get it, we'll have opportunities to reinvest up to that level. If it's not there, we will do something else with our cash flow.

Carl Kirst - Credit Suisse

Great. Thanks, guys.

Operator

Your next questions from Faisel Khan with Citigroup.

Faisel Khan - Citigroup

Good morning.

Stephen Parks

Good morning, Faisel.

Faisel Khan - Citigroup

You talked about, I guess following up on Carl's question, that you are prepared to wait until services costs come down. What kind of percentage decrease would we have to see in current services costs for you to grow production at the clip we saw last year?

Stephen Parks

We look at it in different ways, Faisel, one-year forward strip, five-year forward strip. I prefer to look at the five-year forward strip versus day rates to get a sense, and if you make a plot of rig rates versus five-year forward expectations, you can see rig rates have risen in lock step with the five-year forward curve up through the summer, but rig rates have not come down at all, with the dramatic decrease in the forward strip that we have seen over the past three months or so. They are now in the neighborhood of 20% above where they should be based on the historical relationship.

We are talking to our contractors and service providers about that. Obviously, fuel has come down. We contract for rigs, dries, and we're buying the fuel. So that input is coming down. Steel costs are still high. There is a lot of inventory of tubulars out there that have to kind of work their way through the system before we will see any meaningful pullback in tubulars, especially the highest rated tubulars we use in wells like Pinedale and the Vermillion basin.

So typically, in this business, the rig rates are sticky, and service costs in general are sticky on the way up, i.e., they lag, the expectation of future prices up and they lag the expectation of future price is down by anywhere from four to six months. So what we're concerned about is driving growth into this sticky service cost environment.

We think rates are going to come down. Some of the plays that have been driving the inflation of service costs are looking more marginal in today's forward strip.

Keith Rattie

From a market perspective, Faisel, over the past year, you have to assume that every land-based rig that could work has been working. Next year, it looks like there are at least 200; quite a few, maybe over the next couple of years over 300 new build rigs entering the market. Many of those will come into the market in the first half, at least in theory that ought to put the brakes on this cost inflation.

Faisel Khan - Citigroup

Okay. And then assuming that the costs remain where they are, and your CapEx budget depending up on where prices end up for the next year or two, assuming that your CapEx budget allows you to generate little bit more free cash flow instead of investing in the E&P business, how would you think about investing that free cash flow? If you are not going to invest it in the E&P business, what would you do with it?

Stephen Parks

We won't put it in the other businesses. We have a couple of areas; I mentioned the big inventory of future growth opportunities in Wexpro. We are going to step on our investments in Wexpro. That's one area it can go. We remain ready to give the cash back to the shareholders if that turns out to be the best thing to do. We don't have any plans right now for a share buyback, but we can move quickly if the circumstances were different.

Faisel Khan - Citigroup

Okay. And you talked about that you wanted to put more money into the Mid-Continent team’s portfolio. You said you didn't think about an acquisition in the model but I wonder does that mean that that could be something you would think about?

Stephen Parks

Absolutely. We continue to evaluate acquisition opportunities. We just haven't seen anything that meets our criteria. Softening commodity prices and opportunities, I think, will come with them.

Faisel Khan - Citigroup

Looking at the basis swaps that you guys have put on in your hedging, your hedging tables that you have in your press release. You've got your fixed price swaps, which I see, roughly 59 bcf of gas in '08. And then you have 27 bcf of gas on the basis swap. So do the basis swaps go along with the fixed price swaps or are they completely separate?

Stephen Parks

They are basically what I would call, a naked basis swap. They are just a swap on Rockies basis only.

Faisel Khan - Citigroup

Okay. So on top of the 59 bcf that you have hedged fixed price swaps, you have an additional 27 bcf where you basically hedged out your basis risk with that incremental 27 bcf?

Stephen Parks

That's correct. Yes, unfortunately those basis swaps were under water and resulted in the mark-to-market reduction in net income for the quarter. As I said, we are very surprised at where our current basis, cash basis and forward basis is today based on the macro fundamentals of the Rockies regional transportation capacity.

Faisel Khan - Citigroup

Got you. Thank you for your time.

Keith Rattie

You bet.

Operator

Your next question comes from Sam Brothwell with Wachovia.

Sam Brothwell - Wachovia

Hi, good morning, guys.

Keith Rattie

Good morning, Sam.

Sam Brothwell - Wachovia

Hi, Keith, just a quick question. The two rigs that you sent down to Vermillion from Pinedale, are you contemplating leaving them down there if things go well or will you just go ahead call them back up to Pinedale when the winter restrictions come on?

Keith Rattie

We are working on picking some additional rigs that would be more suitable for the Vermillion basin. These Pinedale rigs that we are using are not made for quick moves, but when they are set up and drilling, they drill very quickly; they have got one of the rigs, one of the record-setting rigs from our Pinedale drilling program.

Right now, what we are looking at is well design, bid selection and taking the human element out of the drilling operation in order to see if we can achieve the kind of cost savings and efficiency savings that we have been able to demonstrate at Pinedale. We think we can, but the first thing you need is good rig and good crews that have demonstrated a track record for being able to accomplish that.

We see the results and it boosts our confidence then to take the next step which is to contract to construct purpose-built rigs for the Vermillion play. That means rigs that can move a smaller number of loads very quickly, don't need cranes to assist and rig up and rig down. In short, a commitment to those rigs signals a big step in our confidence in the Vermillion play.

The first question is, can we drill these wells faster? We think we can. We need to demonstrate that to ourselves, and then we will move on to step two. So, the long answer is we will move these rigs probably this summer back up to Pinedale and by then, we'll have at least one new rig in the area that would be able to move quicker than the rigs that we are moving right now.

Sam Brothwell - Wachovia

But based upon what you are seeing right now, you do anticipate committing to more rigs in Vermillion?

Keith Rattie

That is absolutely part of the equation. We want to watch these two rigs and see how they drill for a few months, and we'll start making that decision in time to get rigs out to replace them.

Sam Brothwell - Wachovia

Okay. Thanks a lot, guys.

Operator

Your next question comes from Sam Delfazzo - John S Herod.

Sam Delfazzo - John S Herod

Good morning.

Keith Rattie

Good morning, Sam.

Sam Delfazzo - John S Herod

Regarding next year's production guidance, I was just interested in knowing if you could narrow down a little bit what the Mid-Continent portion of that production is?

Stephen Parks

Well, Sam, the Mid-Continent we project, we basically flat with the 2006 production as Keith mentioned in his remarks. We have been able to drive Mid-Continent production, basically with the drill bit at Elm Grove. And this year's production benefited from two things: one, we picked up a second rig; and two, earlier in this year, in the first and the second quarter, we did a lot of well workovers and recompletions, because we upgraded our understanding of the reservoirs, especially the shallower reservoirs in Elm Grove, realized we were leaving behind quite a number of pays in the wells based on detailed petro physical analysis.

So, we went back into the wells perforated and frac'd additional zones, which brought on flush production without any significant timing delay as we would see with the normal drilling program.

So that flush production was like a slingshot. It drove the production growth, the down growth. We don't have another rabbit like that to pull out of the hat to keep that growth going, and in fact, that new production that we introduced will decline. It's already declining and create an even bigger snowball that we have to push uphill next year.

That is why we are pretty cautious on our overall production growth forecast in 2007. It will take a while to overcome that and drive production upward again, in these mature assets.

Sam Delfazzo - John S Herod

Okay. And which of your operating regions in the E&P segment are most sensitive to essential cutbacks in drilling?

Charles Stanley

Well, our highest cost regions and the regions that we are concerned about bottleneck and take away capacity is the Uinta Basin in Eastern Utah. Now, the Vermillion Basin as to cost sensitivity is certainly one of our most sensitive, as Keith mentioned, we are working hard to get these well costs down to the point where we feel comfortable that these plays will work, and generate acceptable returns at $6 NYMEX. We think we can get there. We are not there today.

We are going to have to put some money at risk in order to demonstrate to ourselves that we can achieve the kinds of cost savings that make these plays economic, but we are not going to overdrive production volumes in these areas until we are confident we can do so.

Sam Delfazzo - John S Herod

And lastly, regarding the asset management, I'm wondering about the spread with the decline in Rockies gas prices in the third quarter. I was wondering, I didn't see net income from the petro gas management go up, so I was just wondering if you could help me understand that relatively stable performance from the gathering and processing?

Keith Rattie

In part, it reflects the fact that a lot of our business is not keyholed, it is fee based and the other thing is that we managed our midstream business like we managed our E&P business. We have sold forward and locked in what we deem to be very acceptable margins on ethane and NGLs ahead of the pullback in natural gas prices in the Rockies. And as a result, it sort of smoothed our performance. We don't hit the peaks, but we don't enjoy the valleys as much either.

So, we continue to do that in '07, as well to reach out into the future and sell our NGL production and buy gas in the futures market to lock in the known spread, to dampen the volatility and sensitivity to price derivatives.

Sam Delfazzo - John S Herod

Okay. Thank you very much Keith.

Keith Rattie

You bet.

Operator

Your next question comes from Rick Gross with Lehman Brothers.

Rick Gross - Lehman Brothers

Good morning.

Keith Rattie

Good morning, Rick.

Rick Gross - Lehman Brothers

I have a quick question on going to 5-acre spacing. And that is, if we go from 64 wells per section to 128, does that have any implication as to the complexity that you deal with down hole, kind of like needing a traffic cop to feed all these things through the formations? Does it have anything to say about costs or time to bottom of the hole or anything of that sort?

Keith Rattie

Great question. As you can imagine, in three dimensions, it begins to look like a spaghetti bowl. We have basically, for the past several years, been developing a drill out plan for Pinedale, and we have been doing it in three dimensions using software that we basically adapted from geophysical world to plan our well trajectories for collision avoidance.

As you stated, its nightmare, especially in the shallow part of the holes and we have to be extremely careful that we don't collide with an existing well bore that's producing, because obviously high-pressure gas and shallow depth you could create a serious well control situation.

That being said, with careful planning, you can drill these wells from the surface pads at 10-acre or 5-acre density with no additional cost other than the upfront cost of planning the development. What we have been doing is basically planning for a drill out that would imagine 5-acre density over the whole area and in the areas where we don't need it, we will just take those 5-acre trajectories out of our drill out plan.

We're there. It's certainly, obviously, in the overall development of the field, it has more well bores, and to the extent that those well bores are drilled in the more marginal areas, it changes the overall weighted average EUR, when you start to add more 5-acre well bores on the flanks of the structure. But there's a lot of incremental gas to recover from those well bores and I think they are well worth drilling.

Rick Gross - Lehman Brothers

Okay. And that goes back to when you showed, as you move off the crest, you kind of given schematics that you stepped out under the flanks, that the reserves you would book would be less than average?

Keith Rattie

Absolutely.

Rick Gross - Lehman Brothers

And from a standpoint of then trying to think about the impact of 5-acre spacing, we have two impacts, one is even if we don't drill 5-acre spacing we have an impact on the recovery rates of lets say the 10s and the 20s?

Keith Rattie

Correct.

Rick Gross - Lehman Brothers

And then you would also have the impact on the flanks where we would have lower EURs per 40 impacting higher recovery rates in that area as well?

Keith Rattie

I'm not sure I followed your second point. The --

Rick Gross - Lehman Brothers

Well, the second part would be you actually would go to 5-acre spacing and you would be recovering more for the section because you would have those 5-acre wells there.

Keith Rattie

That's correct; although, the average EUR, obviously, would be less than in the crystal area, that's correct.

Rick Gross - Lehman Brothers

Now as we look at that, once again, I assume the well costs are still going to be very similar, and if we would drop down and we would go from, like an average field finding cost of $0.60 to $0.70 plus inflation over time. Are we getting to the point where we have got finding costs on the flanks in these 5 acres that are $1.50.

Keith Rattie

They could be more than that. It depends on the EUR and where we decided to draw the line on drilling 5-acre wells. We carry the 5-acre wells on average in our 2P, 3P, at 2.5 Bcf.

Rick Gross - Lehman Brothers

Okay. Thank you.

Operator

Your next question comes from Joe Magner with Petrie Parkman.

Joe Magner - Petrie Parkman

Good morning. Thank you. Just follow back to the Vermillion Basin. You had originally planned to drill 12 wells this year. You have results from one of these step out wells and you are expecting results from the Alkali Gulch soon. What is the plan from here and where do you go from here in terms of your approach?

Is it to continue to test outlying areas? I know part of that was designed to unitize a lot of the acreage and lock it up and remove the leasing or the time constraint. Do you continue to test the outlying areas or do you retrench and focus on costs and what's worked in the successful areas of play?

Charles Stanley

Joe, we have a couple of key wells we need to drill to do just what you said, to continue to lock up units. But what we really need to do and want to do is go into an area and concentrate on basically drilling it up on a program basis, just like you would under a full steel development to optimize efficiency and see where we can get the cost to.

There are areas of field that there's shallow production that potentially the well cost can be allocated not only to the deep section, but to the shallow horizons as well in both Wexpro and plus our E&P can adjust in a single well bore, so we can drive production volumes for E&P, but also for Wexpro and also Wexpro's investment base.

The other key thing for us is trying a horizontal well. We don't know if a horizontal well is the answer. Obviously, if you drill a horizontal well, you give up the reserves and rate from the underlying plastic section, the frontier section in particular, which we think may still be contributing up to half of the reserves in these wells.

That being said, horizontal wells seem to have been the catalyst in unlocking the plays in the Barnett and Fayetteville and other shale plays around the US. So, we need to try. And the initial focus has been on picking the interval in which to drill the horizontal leg in the Baxter in an over 3,000-foot thick section.

It's pretty easy in Barnett, where you are dealing with a couple of 100 feet. But here we have got 3,000 feet of section and identifying the single interval that we want to drill through with this horizontal well bore is critical, because if we pick the wrong interval and we inadvertently condemn the horizontal technique because we just happened to drill in a poor quality part of the Baxter, that would be bad.

We think we are starting to see a consistent interval that's giving up a greater percentage, not the lion's share but a greater percentage of the gas in the other intervals. That's likely going to be basically almost in the middle of the section. That's likely to be the target of the horizontal well. We would like to see a little more performance from the wells we are drilling right now, but hopefully that will firm up our target and we'll go after this horizontal interval, basically in the middle of the Baxter in 2007.

Joe Magner - Petrie Parkman

As you have more time to gather production information from the existing wells, has that had any impact on your understanding of the play and changed your pre-well expectations or resource potential at this point?

Keith Rattie

Every quarter we see the reserves booked to the PDP wells go up, slightly. We started out using and 8% terminal decline. We moved to the 6% terminal decline. The material balance calculations that we have done in the reservoirs suggest that even a 4% decline is probably not shallow enough. So basically the more production history we get, the more confident we get that the reserves are there.

On average, this is probably going to be a 2.5 bcf play, maybe 3 bcf play. There are going to be outliers on both sides, there are going to be some wells who will recover 4 plus bcf. Those wells incidentally are wells that I think you are seeing a significant contribution from the underlying sands. The Baxter itself is probably in that 2 bcf range.

And again that's why we are focused on the decision between horizontal and vertical drilling. One of the keys in horizontal drilling in the Barnett and other shales is to get longer KH or permeability height by turning the well, and going a long distance in the section up to 3,000 feet horizontally.

In this case, we drilled through 3,000 feet of shale in a vertical well. So we have to see some fundamental difference in the horizontal well. That would be the possibility of intersecting natural fractures, the ability to propagate fracs vertically in the horizontal well to add more effective drainage, those types of things in order to justify giving up that incremental reserves that we know is coming from the frontier under the Baxter.

Joe Magner - Petrie Parkman

Okay. Great. And you have been working on some gas in play and core analysis over the past 12 to 18 months. Do you have any update or information from that work?

Charles Stanley

Nothing new, Joe. These cores take, because of the ultra-low permeability, it takes a long time to get the final measurements. We have seen some preliminary work. It looks very similar to the initial work that we did, 400 BCFE per section kind of numbers. We are still analyzing the more recent cores that obtained. It takes almost a year to get good perm data out of it.

Operator

Your next question comes from Rebecca Followill with Howard Weil.

Rebecca Followill - Howard Weil

Good morning. Chuck, realizing that you are hesitant to commit on talking about your cap-ex budget for 2007, can you tell us what numbers are built in there to get the production that you have outlined for 2007?

Charles B. Stanley

Just on a Questar E&P side?

Rebecca Followill - Howard Weil

Yes.

Charles Stanley

Let me give you that number. It is about flat with -- about $500 million, about flat with last year.

Rebecca Followill - Howard Weil

So you have modest escalation since you are drilling just three less wells, there is just a little bit of modest escalation in costs?

Charles Stanley

We have assumed escalation across all of our drilling programs. As we said, we do not think that cost should escalate. In fact, they should decline, but at this point, we do not have good reason to reduce our capital costs.

Keep in mind, when we forecast, we forecast 100% capital and risk production volumes, knowing full well that this is a risk business and that we can never fully anticipate results. We allocate capital based on risk economics and we forecast production based on risk results, and those results are not only a risk production stream for an individual well but also a risk in timing of execution that drives our overall forecasting.

Rebecca Followill - Howard Weil

Thank you.

Operator

Your next question comes from John Mansfield with SAC. John, your line is open. Since there was no response from his line, your next question comes from Sara Nainzadeh with Millennium Partners.

Sara Nainzadeh - Millennium Partners

Hi, this is actually Mark for Sara. Chuck, the key question I have for you is circling back to Sam’s question, the two rigs will go back to Pinedale, and you mentioned there would be one new rig. Will that be a special purpose rig or just another rig that you had ordered a while back?

Charles Stanley

It will be a not-ideal rig for Vermillion but a rig that moves in less loads than it took older style Pinedale rig. It will be a rig that we can use universally in our drilling program, whether it be for Wexpro or for QEP, and it will be capable of drilling Vermillion wells and Pinedale wells as well.

Sara Nainzadeh - Millennium Partners

On the 5% production increase that we have seen over the last year, could you give a little more detail, I know you did a little bit earlier, on how much of the Vermillion ramp-up that incorporates, or does it at all?

Charles Stanley

I do not have the detailed production volumes. I think Vermillion production is about flat year over year, in forecast. Keep in mind that in our Rockies Legacy Division, we have a number of older producing properties that are in decline. We were basically, with the Vermillion program replacing the decline from these older properties that we basically run out of development locations, and so we were again struggling to keep up with the fuel decline, production decline, and these individual older fields, and the new programs replace that decline and modestly grow production.

Sara Nainzadeh - Millennium Partners

If rates start to come down to what you deem acceptable, will you begin to underwrite new rigs or special purpose rigs?

Charles B. Stanley

In order to make plays like the Vermillion work, we need build-for-purpose rigs. We need rigs that move in a day or so, not rigs that take a week to move, because obviously this is going to be an intensely repetitive development program, so yes, we will, but we want to make sure when we make that commitment, because we will build rigs specifically for Vermillion, and it would be sub-optimal for a lot of our other operations.

One of the things we are going to be experimenting with is well design, including using oil-based mud, things like that, that we have used successfully at Pinedale. We need to know exactly what kind of mud systems we are going to use, what size tubulars we are going to run in the wells, whether we are going to drill horizontal wells, for instance, because drilling a horizontal well at a depth, a measured vertical depth of greater than 9,000 feet requires a substantially bigger rig than just drilling straight vertical wells, because of the hook-loads and the tension that you have, especially right casing. A lot of unknowns yet that are obviously important to know before we step out and contract to build specific rigs for Vermillion.

Operator

(Operator Instructions)

Your next question comes from [Richard Tallus] with Capital One South.

Richard Tallus - Capital One South

Good morning. Just a couple of follow-up questions on the Vermillion wells. For the recent drills, what has been the average cap-ex on those wells?

Charles Stanley

They are about $5 million, drilled and completed. That is gross cost.

Richard Tallus - Capital One South

I guess that is an increase over the first few wells you drilled out there.

Charles Stanley

It has been about flat, actually. We have seen drill times coming down on the wells, and it is also the day rate inflation that we have seen.

Richard Tallus - Capital One South

Okay. What has been the flow rate on the last couple of wells? What are they flowing at about right now?

Charles Stanley

Let’s see, sequentially, all these wells start out in the 1.5 million to 2.5 million cubic feet a day range. The initial rigs are constrained by our ability to handle the flow-back of the frac water that comes back after we multi-stage fracture simulate these wells. They quickly decline and then start to level out at rates of about a half-a-million a day, and if I look across the 13 wells that are currently producing, with the exception of the last one, the Sparks Ridge well, which is basically an oil well with associated gas, they have all kind of leveled out in that 550 to 650 million cubic feet a day range. We have one well that is only partially completed that is making 300 MCF a day, but that is sort of what we expect from them. Then they go into a very flat decline.

Richard Tallus - Capital One South

I think that is it for me. I just needed to get a little background on that. Thank you.

Operator

Your next question comes from John Lawrence with Morgan Keegan.

John Lawrence - Morgan Keegan & Co., Inc.

You were talking a lot about your increases in costs and so on, and I was wondering if you could comment a little bit about what is going on, also with your labor pool and the labor bargaining, both cost as well as turnover, that kind of thing.

Charles Stanley

We were talking about contractor outside labor?

John Lawrence - Morgan Keegan & Co., Inc.

Yes, a contractor labor, I do not know how much you have of your own, because you keep hearing about labor rates going up in a huge way and labor shortages developing, and that could cause issues for how reliable your crews are, that kind of thing.

Charles Stanley

We have clearly seen strong inflationary pressure in the skilled labor market in-house. Obviously the oil and gas industry is aging, and we have basically a generation gap where we did not hire people, did not train people, and the entire industry is facing it in the technical and skilled market, and that is obviously driving G&A and our E&P businesses, and also our gathering and processing pipeline, all those businesses. All these businesses face the same shortage of critical skilled folks.

At the field level, we see contractors with relatively stable workforces in many of the plays that we are in, and the reason for it is that we have a -- let’s take Pinedale as a great example. We have a very visible, very long-term drilling program. Our contractors like to work on these programs. They put their best equipment on these programs and their best people, and those people tend to be longer-term employees. They tend to like to work, because they know they are going to be in one place and not following a rig that is moving 100 miles in any given direction every 30 to 90 days. It is ideal work for our contractors and for their employees. So we are seeing, in that instance, a very stable workforce.

In the mid-continent, it is a lot different, because in the western mid-continent, we basically have one-off wells. We have one-off rig contracts, and we see a lot of turnover in that area. Elm Grove in northwest Louisiana, we see a barely stable workforce and a stable contracting environment.

It really depends on the company’s programs and the attractiveness of those programs for the contractors. In areas like Pinedale, it is very easy to attract and retain high-quality contractor, high quality workforce. In areas where we do not have a program of drilling opportunities, it is more difficult.

The biggest issue for us is now focusing on high-grading our rig fleet in the plays that we think we can drive cost down and improve economics on, like Vermilion.

John Lawrence - Morgan Keegan & Co., Inc.

As far as your decision-making goes, it sounds like you are not seeing a huge impact.

Charles Stanley

No, I think one of the reasons we have seen a dramatic decrease in the number of days to drill a typical Pinedale well from mid-60s a year-and-a-half ago down to 41, 42, 43 days today is a direct result of the stability of the workforce that we had out there because, as I said, we have taken the human element out of the drilling operation and we are able to focus on the mechanical side of it.

Operator

You have a follow-up question from Rick Gross with Lehman Brothers.

Rick Gross - Lehman Brothers

I just have a few odds and ends. First one is, if you are going to be a little bit cautious on the E&P spending and ramp up spending at Wexpro, my assumption would be that if you just focus on E&P production guidance, you are kind of missing the picture on the financials that would be generated by the swap of dollars that Wexpro generates pretty high returns on investment.

Charles Stanley

Very good observation, Rick. Well put.

Rick Gross - Lehman Brothers

From a standpoint of looking at all of this and slowing down the program temporarily to get a grip on costs, is it possible that financially, there will not be any deduct if you do not grow by X in E&P if you devote all the incremental money to Wexpro?

Keith Rattie

I will give Chuck a break, just for a moment. The guidance we have given reflects caution in pushing capital and driving our cost structure in the E&P sector. As you know, we are almost neurotic about giving guidance. We want to be confident that we are going to hit the guidance that we give you, so we have taken some caution. Obviously if the costs in the service sector adjust to what we think the current market realities are, softer natural gas prices, which are going to squeeze margins, and it looks like our margins are going to be at a level where we can get the kinds of returns on capital with existing performance, we can turn it up a little bit.

But there is an important point as well. Pinedale has been the key driver of our growth. Next year, we are going to have a bit of a pause. We have one less rig operating this winter, so in our models, we assumed drilling performance about what we have seen lately. Hopefully we will get resolution with the SCIS, which will allow us to ramp up drilling in Pinedale, and then we will continue to drive our volume growth over the next several years.

Charles Stanley

I would add to Keith’s comments that this year’s growth has been higher than we predicted, and in part, it has been driven by an incredible job that our mid-continent folks have done. We had good luck in our execution at Pinedale. We got the wells on a little earlier than we thought we would. We got off of the winter patch quicker than we thought we would -- a lot of things went right.

We also had a great well in the eastern mid-continent that basically was 100% well that was producing about 6 million a day net, which drove increased volumes in that area. We do not have those built in to our 2007 plan. We do not forecast on basically the 100% probability of good luck. We tend to be fairly conservative.

That being said, we do not expect linear growth. We do not think we can sustain 25%, 26% growth out of the mid-continent next year. It is just not possible with the assets we have to keep doing that.

Rick Gross - Lehman Brothers

A couple of quick questions on Pinedale. You lost a winter rig, but you also had a rig sitting on a deep well that was a lot longer to drill than the average well. I was also curious about whether you are making progress on productivity in the bottom-half of the hole, with bits, et cetera, that you think you might be able to cut the drill time?

Charles Stanley

Keep in mind that we reached total depth on that Pinedale well in August of last year, so the testing was initiated in September, October last year, 2005, on the Pinedale depot. We have not had a rig on Pinedale for a year, year-and-a-half now. That rig was not in the rig count this past year, either, and it was not in the winter rig count.

The answer to your second question, yes, it is interesting. The bottom couple thousand feet of the hole is critical to increase drill times. We spend 40% or so of our time at the bottom couple thousand feet of a Pinedale well right now, from 12,000 to 14,000 feet. The rock is harder. It drills slower. It dulls bits quicker. We have to trip out of the hole and replace the bits.

Interestingly, we have seen a deterioration of drilling performance year over year in that deep section, and as a result, we have gone back and started looking at the bits, and found that there are some changes in the way the bits are being manufactured. We are focused on trying to get back to where we were, and just getting back to where we were in 2005, in the bottom part of the hole, is two or three days of additional savings on drill time, and at a $50,000 a day average spread, that is $150,000 of net savings, assuming costs stay basically flat with where they are today. That is meaningful, especially when you multiply that over 1300 or so gross wells that we have identified in our remaining inventory, on a combination of 10-acre, 5-acre locations.

Do we think we can do even better? I hope so. We have seen glimpses of performance in the low 30s. Is it something that we can do consistently? Only time will tell. There are certain things that we are working on with respect to bit design, motor design, the way we drive the bits, that we think will continue to yield some reduction in days to drill.

But I do not think you are going to see the drill time as we have seen in the past couple of years.

Rick Gross - Lehman Brothers

Last odds and ends -- you showed a lot of development locations; as far as the legacy properties, and I was curious as to whether or not, with today’s economics, a lot of that stuff may be marginal.

Charles B. Stanley

The well costs are high. You know, we used to think the [WAMPs] order was always $1.50 or $2 higher than whatever the current forward strip was. Interestingly, the well results, the reserves and recoveries that we are seeing from the [WAMPs] order wells are better than we had predicted. We think that they remain economic at a $6 NYMEX, or slightly under that, at today’s cost. Again, we are drilling wells today at almost double what they were a couple of years ago, so we are hoping that the softening of the forward curve allows us to claw back some of that margin that is currently in the hands of our drilling contractors, and allow us to drill these wells with better margins, better economics.

Operator

Your next question is a follow-up from Joseph Magner with Petrie Parkman.

Joseph Magner - Petrie Parkman

Just one quick question on the Mancos play. It was not touched on. Where do you stand there? What sort of results have you seen since last call?

Charles Stanley

We have completed in terms of sales our third Mancos well, Joe, which is down in the close vicinity of the first two Mancos well that we drilled and completed. Performance run under, for the first month or two we have had it online, looks very similar to the first two, indicates 1.5 to 2 BCF recovery from the Mancos itself. When you co-mingle the overlying Mancos silt and the Blackhawk and various sands in the Mesa Verde, we think we are seeing 4 to 5 BCF type wells here. The range is going to be anywhere -- keep in mind that the classic section is highly variable, and one of the reasons we have focused on the Mancos is to put a sort of a predictable, solid, 1.5 to 2 BCF base on each of these wells, with low decline, long reserve life, not as splashy in initial production rates, but really an anchor for lowering the DD&A rate, defining development costs for this play. Then, coupled with that, this more variable sandstone section in the Blackhawk and shallow Mesa Verde sands in the Wasatch as well, and we expect to see a range of 2.5 to 5 BCFs for wells in that combined Manco-Blackhawk- Mesa Verde -Wasatch section.

As Keith mentioned in his remarks, we have also drilled some 20-acre pilot wells in several areas in our shallow Wasatch play to look at the possibility of in-filling. What we would do is basically in-fill the shallow 40-acre space Wasatch wells with deeper wells that would not only in-fill the Wasatch up 20 acres, basically, it would go deeper and capture reserves in the Mesa Verde and also in the Blackhawk and Mancos.

Early results from the pilot study, we do not see a lot of dramatic interference in the shallower sands. We were expecting some. There is some, but it is not as significant a depletion as we were expecting on 20 acres. There is incremental recovery available to us in the Wasatch and almost all of the western part of our acreage was developed before we started drilling for the Mesa Verde, so we have basically virgin Mesa Verde section on 40 acres to develop in the area.

Joseph Magner - Petrie Parkman

What is your oil-gas production split out of the Uinta? We have heard recently about some, about marketing opportunities and differentials. What are your thoughts there and does that affect your ability to ramp up much of that production?

Charles Stanley

We product about 3,000 barrels a day gross of black wax out of the Uinta. You will recall that those are from two oil fields that were originally discovered by Gulf and Chevron, and later Chevron operated them together and then formed Shenandoah Energy, which we acquired in 2001.

Those fields are connected to a pipeline that takes the black wax from the eastern part of Utah into the refining complex here in the Salt Lake valley. We have been lucky in that those volumes have been dedicated to that line. We have not see the curtailment that some other operators in the basin have reported.

There is pressure on differential between NYMEX and Utah black wax, as more and more syn crude has made its way down out of Canada into the Salt Lake valley. It is pushing a lot of the indigenous liquids, not only the black wax but also the sweet crudes from western Wyoming down in differentials between NYMEX and realized prices.

It has tightened the market considerably, because we are seeing evidence in not only the black wax markets, from what other producers are saying, but also in the southwest Wyoming markets, of a tightness that did not exist a year or so ago.

Joseph Magner - Petrie Parkman

Thank you. Just one last question, you have a well or a location spotted on the Vermillion basin map that is north of your trail 31. Is that a well that is designed to test the northern edge of the over pressure zone, or what is the --

Charles Stanley

It actually gets deeper up there on the northern end. That would be a well that would basically push the limits of the play further down deep on the north end rather than shallower.

Joseph Magner - Petrie Parkman

Interesting. Thank you.

Operator

There are no further questions at this time. Are there any closing remarks?

Charles Stanley

We have kept you a long time. We appreciate your interest. We hope to see many of you in Boston and New York on the 14th and 15th of November. We are signing off for now. Thank you.

Operator

Thank you for participating in today’s Questar third quarter 2006 conference call. This call will be available for replay beginning at 10:30 a.m. Eastern standard time today, through 11:59 p.m. Eastern standard time on Friday, November 11, 2006. The conference ID number for the replay is 4211338. Again, the conference ID number for the replay is 4211338. The number to dial for the replay is 1-800-642-1687, or 706-645-9291.

Thank you for participating. You may now disconnect.

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Source: Questar Q3 2006 Earnings Call Transcript
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