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Questar Corp. (NYSE:STR)

Q2 2006 Earnings Conference Call

July 27, 2006 9:30 am ET

Executives

Keith Rattie – Chairman and Chief Executive Officer

Steve Parks – Senior Vice President and Chief Financial Officer

Chuck Stanley – President Questar Marketing Resources

Allan Bradley – Chief Executive Officer Questar Pipeline

Alan Allred - President, Questar Gas

Analysts

Carl Brown – Cramer Rosenthal

Faisel Kahn – Citigroup

Shneur Gershuni – UBS

Sam Brothwell – Wachovia Securities

Carl Kirst – Credit Suisse

David Thickens – Deephaven

John Mansfield - SAC Capital

Rick Gross - Lehman Brothers

Monroe Helm - CM Energy Partners

Joe Magner - Petrie Parkman

Brian Singer - Goldman Sachs

Marshall Carver - Pickering Energy

Presentation

Operator

Good morning and welcome to the Questar Corporation Second Quarter 2006 Earnings conference Call. After the speakers remarks there will be a question and answer session. (Operator Instructions) It is now my pleasure to turn the call over to Mr. Steve Parks, Senior Vice President and Chief Financial Officer. Mr. Parks, you may begin sir.

Steve Parks

Thank you operator. Good morning and welcome to Questar Corporation's Second Quarter 2006 Conference Call. Yesterday we reported that Questar's Second Quarter 2006 net income rose 49% driven by a 16% increase in natural gas and oil equivalent production and higher realized prices for natural gas and natural gas liquids. You can access our earnings release at our Website at www.questar.com. Following my remarks this morning Keith Rattie, our Chairman and CEO, will comment on operations and update our guidance for 2006 earnings and production. 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 Allen Alrech President and CEO of Questar Gas.

All remarks this morning will contain forward-looking statements about the future operations and expectations of Questar. These statements are made in good faith and we believe they're 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 SEC.

Now let me briefly recap our financial results of the first half of 2006. Questar first half 2006 net income was up 46% to $227.5 million dollars or $2.60 per diluted share. There were 87.5 million diluted average common shares outstanding on June 30 this year compared to 86.9 million a year ago.

Our market resources subsidiary led the way for the first half of 2006 with net income of $172.9 million up 56% compared to a year ago. Market resources engages in gas and oil and exploration, development and production, gas gathering and processing, wholesale gas marketing and gas storage. All four Gas Market subsidiaries, Questar E&P, Wexpro, Gas Management and Energy Trading had double-digit increases in earnings. Questar E&P net income was up 79% driven by a 19% increase in natural gas and oil equivalent production and higher realized prices for natural gas, oil, and NGL. Wexpro net income was up15% driven by a 17% increase in its investment base over the past 12 months. Gas Management net income was up 12% due to higher processing volumes and margins. Energy Trading income was up 59% due to higher marketing fees and interest income.

Questar Pipeline, our interstate pipline and storage business earned $21.3 million in the first half of 2006 up 34% over 2005; this increase was driven by new transportation contracts and higher NGL volumes and prices. The new contracts included the 2005 completion of an expansion of our Southern system and the December 2005 completion of a new inter connection between Overthrust Pipeline and Kern River Pipeline. Questar Gas, our retail distribution utility reported first half 2006 earnings of $28.7 million, 13% higher than a year ago. The improved results were from higher margins from customer growth, and the recovery of gas processing costs in 2006 that were not recognized in 2005 recognized until the fourth quarter pursuant to a regulatory order. Now I'll turn the microphone over to Keith Rattie, Questar Chairman and CEO

Keith Rattie

The bottom line on our second quarter and first half is the bottom line. Questar operating units posted double-digit growth in the first half of '06 but it's the operational results from Questar E&P that stand out. We grew natural gas and oil equivalent production 19% in the first half and 17% excluding one time adjustments. Questar EPP has now delivered 15% or higher production growth for four straight quarters. Our veteran E&P team is getting the job done with its drill bit and that's allow us to raise E&P production guidance for the second time this year. We now expect '06 range from 120 to 128 billion cubic feet equivalent. That's compared to our previous guidance of 124 to 126 and '05 actual production of 14.2 Bcfe equivalent. Note in our release that we also trimmed a dime off the top end of our EPS guidance. That's entirely due to forward price curve for natural gas for the remainder of the year. We put a table in our release to reconcile current and previous guidance. We now estimate that '06 EPS could range from $4.50 to $4.70 per diluted share and that's compared to our previous guidance of $4.50 to $4.80.

Our revised guidance, as we noted, assumes a NIMEX natural gas price range of $7.00 to $8.00 per million Btu's for the second half of the year and I should note at the close of the market yesterday the market was actually at the top end of that range. That's $1.00 per million Btu's less than the $8.00 to $9.00 Btu's that we assumed in our earlier guidance. Note that we haven't changed assumptions.

Our revised guidance assumes that Rockies and Mid Continent differential will average $2.25 per million Btu and $1.50 per million Btu respectively for the remainder of the year. As you'll note, that's well above the current Rockies' basis of $130 per million Btu and current Mid Continent basis of $0.90 per million Btu. Now as always our guidance excludes one-time items.

Note that we've not hedged 70% of forecast second half of '06 gas production; We've taken commodity risk mostly out of the equation for Questar and its shareholders in '06. $1.00 in the average Nimex gas price for the rest of the year moves EPS by just $0.07.

Also note that we've added fixed price swaps to '07, '08, and '09 gas equity production and note the upward slope of our new hedges. The average net to the well price of hedged volumes in each of the next three years is higher than in the preceding year. So, as you'll note, we've begun using only swaps to heads Rockies basis.

Now at the end of '08 we think the probability that Rockies basis will widen is greater than the probability that it will narrow from current levels. So far we've been wrong. Unrealized mark-to-market losses on natural gas basis hedged reduced second quarter EPS by $0.04 per share. The 2006 Rockies basis this far has been tighter than we expected and I think anyone predicted. The reality here is that it's been scorching hot here in the West so far so the gas burn for electricity is way up.

Let me focus your attention on our update on probable and possible reserves. We think this is the key part of our release yesterday. These estimates were reviewed by the Company's independent reservoir engineers that prepare Questar's E&P approved reserves. Not that our last updates were in our March 8, 2005 and August 9, 2005 press releases and we put a link in our earnings release yesterday (www.questar.com/news/news 2005.html). We encourage you to refer to these releases. The three numbers that are a good symmetry here and they're pretty too easy to remember. 1.5 trillion cubic feet equivalent proved 2.5 trillion cubit probable and 3.5 trillion cubic feet possible. At the year end 2005 we reported proved reserves of nearly 1.5 trillion cubic feet equivalent. The revised estimate of probably is 2.5 trillion cubic feet equivalent is up 83% from March /05 report and possible reserves of 3.5 tcf equivalent are up 103%. I'm going to comment on what's in and what's not in these estimates as I go through our major plays here in a moment but let me make four points about our reserves estimate.

First we don't report nonproved estimates in our filings. Second in accord with SEC rules we don't book proved reserves on undrilled locations that are more than one direct offset from a developed well. Now at Pinedale because we have good control on the distribution reserve structure the quality of our probable reserves approaches that of the reserves we've booked has proved undeveloped. Third, and possibly most important, these estimates are a snapshot in time. They're going to change as we develop, produce and evaluate well performance and incorporate new data. Fourth we want to remind investors not to sum the proved, probable and possible estimates first considering the differences in the risk of recovery with each classification.

Now reserves are important information but you ring the cash register with production so let me just comment on our production results as Steve hit some of this. Questar E&P produced 31.3 bcfe in the second quarter. That's up 16% from a year ago quarter. Note that Pinedale production was up 26% from the year ago quarter. Pinedale in the second quarter comprised one-fourth of Questar E&P's production but as we discussed that share will grow. We're still in the very early stages of our Pinedale development plan. Note that Rockies Legacy produced was up 20% or 12% excluding the one time adjustment in the second quarter. Increased volumes from the Vermillion, Clay, Wedge and Wamsutter areas offset finds from mature property.

Our Mid Continent team shot the lights out. Production was up 28% driven by our Elm Grove play in northwest Louisiana and a high volume well in the Arcoma Basin in eastern Oklahoma.

Let me talk about Uinta Basin production, which was down 10% from a year ago. That's a bit misleading because volumes in the year ago quarter included production from a back log of wells drilled in the first quarter of '05 and wasn't complete until the second quarter for reasons related to weather that we talked about at the time.

A compressor failure and gathering related relays also hurt our volumes in the second quarter but the primary issue here is that our core Wahsatch/Upper Mesaverde play is maturing and the average working interest in our remaining inventory is declining. What that means is we're going to need a new play in the Uinta basin to overcome decline and current production back up. Our potential Mancos play may be the key and I'm going to talk about that in a moment.

Let me walk through the major plays now to give you a little more color starting with Pinedale. We came out, as you know, of the winter drilling season with 33 new Pinedale wells drilled and cased ready to complete. We couldn't frat most of these wells until we got the drilling wells out of the way so only 5 of the 33 were flowing to sales at the end of the quarter. We should have them all on by mid September and that should help drive Pine Dale volumes in the second half.

Now if you're a Questar shareholder tip your hat to our Pine Dale Team. Over the past couple of years they have found ways to offset the soaring costs, completion services, wellheads, and other related costs. Today a typical Pine Dale well costs about $5.5 million to drill and complete and that's about the same as it was years ago before the big inflation in those costs. With pad drilling once we drill and case a well we skid the rig a few feet and spot the next well. That's cut some cost. Skid water frat has cut a lot of completion costs out without any apparent adverse impact on well performance.

There's other items on the list. Chuck can elaborate in q and a but the key point is that this focus on costs continues because it matters. We had a lot more wells to drill at Pinedale. You'll note that we reported – you'll recall that we reported 780 bcfe proved reserves at Pinedale at the year-end 2005. Questar E&P now estimates that's it's lance full probable reserves are 890 bcfe and possible reserves are 715 bcfe. The big jump in the third category, the possible reserves category, compared to our August 2005 estimate is tied to potential development on part of our Pinedale acreage. As you'll remember our reservoir models suggest that with 10-acre density, our current development plan, we'll recover less than half of the gas in place at Pinedale. We're going to start evaluating 5-acre density later this year.

Also please note, that the deep potential in the Rock Springs formation is included in our Pinedale probable and estimates and this is a good time to bring you up to date on the Pinedale deep test. As we've said in the past, we know there's a lot of gas in the Rock Springs and Hillyard formations that depth down to about 19,500 feet. What we don't know is whether we can produce that gas at rates necessary to justify the high costs to drill and complete wells at these depths and on that count the news so far is not encouraging. Let me catch you up on what's happened since our April call. We got back on the Stewart Point 1529 location. We clearly cleared the obstruction that we've talked about, the obstruction at 6800 feet and cleaned the well bore down to about 19,050 feet. That's the middle of the Hillyard and we found another obstruction. We're not sure what that obstruction is. It might be another frat plug that's moved up hole and lodged in the collapsed casing. We tried but we couldn't drill it out.

Given the risk and the cost we decided to resume the test on just the upper part of the Hillyard only. This time we babied the Hillyard back on it to avoid pulling shale and prop it into the well bore. The upper Hillyard flowed at fairly stable rates of about 1.5 cubic feet a day for about six days. Then we set a plug over the Hillyard and moved back up hole to test our primary target, the Rock Springs and that's where we are today. We're still testing the Rock Springs. We are producing gas but the rates are disappointing. Though frankly not surprising given the poor rock quality at these depths. We still have several have several more domes to test in the upper Rock Springs and once we do that we'll decide what to do next. Chuck can give you a little more color in q and a.

Let me turn to the Vermillion Basin. Confidence in this play is growing and that is reflected in our updated estimates of probable and possible reserves, which now include 341 bcfe probable and 806bcfe of possible reserves for the Baxter, Frontier, and Dakota play. The Vermillion probable reserves estimate is based on, please note, 210 80 acre locations above the lowest known gas accumulations defined by drilling to date, mostly covering the Canyon Creek and Trail structures and if you look at Slide Number 17 in our presentation this will probably make a little more sense.

The probable estimate for Vermillion adds to the 40-acre infill location next to the probable location; plus the acreage within the greater structure limits of the play defined from regional 3-D seismic. Note also, that both our probable and possible estimates assume an average EUR, estimated ultimate recovery, of .5 bcfe per well. I'll also add that our technical team believes that this play could extend beyond the areas in our 3P estimates. We're going to drill several wells this year to test that thesis.

Let me move to the Uinta basis where our estimates now include 450 bcfe of probable and 950 bcfe of possible reserves. As we've been saying, Wahsatch/Upper Mesaverde tight sand gas play is maturing. We're down to about a one-year inventory of undrilled 40-acre locations. We're going to do some pilot work on 20-acre density in the field and we should have some data by the end of the year. But as I said earlier, we're going to need success on our new plays in the basin to arrest decline and to turn production up and towards that end we're continuing to evaluate Uinta basis deep potential. The targets, you'll recall, are unconventional reservoirs in the lower Mesaverde and Mancos and Dakota formations.

We've now drilled and tested our second Mancos well and the Dakota well down to about 16,000 ft. The Mancos, you'll recall, is a thick over pressured shale the age equivalent of the Baxter shale in the Vermillion basin and the Hillyard shale at Pinedale. The Mancos and Dakota are present and more important over pressured across most of our Uinta basin. Well performance in these first two wells has thus far been similar to what we've seen in the Vermillion basin and we still have the shallower Mancos, Beatty, Black Hawk and Mesaverde formation behind five to test later. We're also close to planned total depth, which we're going to test shortly.

At Mesaverde formation we have five to test later.

We're also close to planned total depth on our third well, which we're going to test shortly.

Now unlike the Vermillion Baxter play the economics of a possible Uinta Basin deep play might be boosted by developing the shallower Wahsatch/Upper Mesaverde formation tight sand on 20-acre density. Uinta reserve estimates include 290 bcfe of probable and 364 bcfe of possible reserves for the deep Mancos play.

Le me turn quickly to the Mid Continent. As I noted, our Tulsa and Oklahoma City teams are doing a great job replacing, define, and growing volumes. At Elk Grove in northwest Louisiana our inventory of undrilled locations is now up to about 250. Two-thirds of those are Questar operated. We recently added a second rig at Elk Grove. We now expect to drill about 50 wells a year with two rigs.

Our Oklahoma City team also continues to stave off decline. Chuck and I were down there just recently reviewing their activities and I came away very impressed with the great job our folks are doing generating attractive drilling opportunities in the Texas Panhandle and Western Oklahoma with a variety of targets that include the Granite Wash, Atoka, and Moral Formation.

Briefly a comment on Wexpro; the Wexpro investment base, as Steve noted, has grown 17% over the past 12 months and Wexpro still has about $700 million of identified undrilled investment opportunities. Good news for our customers, the customers of Questar Gas and good news for our shareholders. That should drive further growth in the investment base and therefore net income, while helping to keep rates for Questar Gas customers among the lowest in the country. Wexpro produced about 10 bcfe in the second quarter on behalf of the utility.

Gas Management, our gathering and processing services business had another good quarter as gathering and processing margins remained strong. They're going to be very busy this summer. We're building a 20-inch pipeline from our Blackfork Plant to Kern River Pipeline near O'Powell, Wyoming. We're also expanding the Blackfork Processing Plant. We're building new facilities to handle growing volumes grossed from Pinedale.

Also note, we're expanding our Uinta Basin gathering and processing hub. With the Northern Ute Tribe and another industry player as partners we're building 64 miles of 12-inch pipeline from a tab on Questar Pipeline in Northeaster Utah down to the southern part of the Uinta basin to pick up gas in new plays that would otherwise be stranded, including Questar E&P's Star Mesa Flatrock Play plus some third party gas.

Please note that we're also planning another Rockies hub in the Vermillion Basin. We attempt once more to piggyback on Questar E&P's investment in the area.

Let me move on to our regulated businesses starting with Questar Pipeline. I hope you all saw that the pipeline net income was up 34% in the first half, 30% in the second quarter. As we said in the past, we've given Questar Pipeline a simple mandate and that's to identify and eliminate pipline bottlenecks in Questar E&P's core Rockies producing basin and they're getting after it. We're going to invest $50 million to extend Over Thrust Pipeline west to Kern River Pipeline at O'Powell. This expansion should be in service early next year. Also next year we're going to extend Over Thrust's 77 miles east to the Wamsutter hub in Central Wyoming to an interconnect with the Rockies Express pipeline. Questar Pipeline also recently announced a binding open season for a notional 540-mcfe expansion east from the Uinta Basin to the Meeker Greasewood Hub and Allan Bradley can give you more details on that in q and a.

Finally our utility, Questar Gas earned its allowed return in the first half of 2006 for three reasons. First new customers added about $4.7 million in non-gas margin compared to the first half of '05. Second, we're now recovering part of our gas processing cost, which of course we were not recovering in the first half of '05; and third temperature adjusted usage per customer declined less than we expected and that's despite high natural gas prices.

To summarize, all major Questar operating units boasted double-digit earnings growth in the first half but it's our E&P business that's driving value for Questar shareholders today. Questar E&P updated reserves estimates, we hope, tell a pretty compelling story. This company has significant organic growth potential. Our E&P Team is turning that potential into reality. For the second time this year we've raised our production guidance for '06. With hedging we've taking commodity price volatility mostly out of the equation for the rest of this year. We're gaining confidence in our Vermillion Basis shale play with the initial results from our first two Mancos Wells in the Uinta Basin we think we might be onto something good there. And with that, we'll now be glad to take your questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Your first question comes from Carl Brown of Cramer Rosenthal.

Carl Brown – Cramer Rosenthal

Hi guys. Congratulations on a great quarter once again.

Keith Rattie

Good morning Carl.

Carl Brown – Cramer Rosenthal

A quick question on the reserve update; when you look at the Pinedale Reserve of about 1.5 t's between probable and possible and divide by the locations that you've laid out for that I'm coming up with about 1.2 bcf per location, which even after you gross up for something like a 45% net revenue interest that works out to about 2.7 bcf per location. That seems a little low relative to previous Pinedale wells. Can you just comment on that or whether or not I'm making a mistake in how I'm thinking about that?

Keith Rattie

I'll let Chuck field that one.

Chuck Stanley

Good morning Carl. Without checking your math here, the average of the 10 and 20-acre probables is 5.6 bcf and the average work interest is about 57% and the NRI is about 77% and then all of those are in the probable category so basically the unbooked 10 and 20-acre locations that aren't currently booked as proved are averaging about 5.6 bcfe and then there's 575 of those. Then the remaining 5-acre locations are average of a 3.77bcfe. The same working interest and NRI and there should be about 660 some, 665 or so 5-acre locations. So when you go through that math I think you'll come up with the probable and possible reserves in the report.

Carl Brown – Cramer Rosenthal

Okay I'll double-check that and then I'll tuck it back.

Chuck Stanley

If you have any more questions give us a holler and we'll help you work through the numbers.

Keith Rattie

And Carl I don't know if it was part of your question or not but please keep in mind on the proved side we've got about 585 of the locations that we talked about on 10-acre density that have not yet been booked.

Carl Brown – Cramer Rosenthal

Okay, great; and then on the Vermillion location it seems like between probable and possible it's about a little over 600 locations. It seems kind of right in line with the locations that you had listed on your slide for the May Analyst Meeting. I was just wondering for the other 3,000 potential locations that you laid out and resource potential for Vermillion in the May Analyst Meeting can you just talk about conceptually what needs to happen to move those from resource potential to a 2-P, 3-P number? Is part of that the delineation wells that we're going to be drilling in the back half of the year or are there other factors involved?

Carl Brown – Cramer Rosenthal

Sure Carl. You basically answered the question for yourself. We need more spatial sampling, obviously, and if you think about it as Keith described it the reported probable reserves are simply the Crestle area above the low stone gas based on today's drilling and based on 80-acre density. As we collect more well data we'll get more confident as to the drainage area and then as we moved down dip on the structures we'll push out the known limits of gas, which is necessary in order for our reserve auditors to get comfortable with the classification of those areas as probable and possible. So that requires these additional delineation wells that you mentioned to push the limits of gas down dip. In addition to that, we just need more time and well performance. So we wanted to get this update out because of, obviously some changes in our thinking on Pinedale and other places; but we also wanted to remind investors that this is a continuum and as we collect more data we'll modify the estimates and, obviously, the important wells haven't been drilled yet in Vermillion and those are those delineation wells. They'll come later this year; but, frankly, by the time we get those wells down and produce them long enough to get a meaningful production data set it'll probably be early next year at the earliest before we have a meaningful data set to update our estimates on Vermillion.

Keith Rattie

I would just add and I'll refer the others on the call to Slide Number 17 in our IR presentation, which you can get on our Website. The three key delineation wells that are yet to be drilled that we plan to drill later this year are shown there as the Spark Ridge Unit Number One, The Apppalac Gulch Unit Number Three Well shown at Turquoise and another well at West Hiawatha Structure.

Chuck Stanley

Wowser!

Carl Brown – Cramer Rosenthal

So after those wells get drilled we can expect an update? We don't need to bring [unintelligible] back in to have them kind of redo the whole process?

Chuck Stanley

Well Ryder Scott does reserves in the Rockies Carl. They will review this because they'll – we rely on them to sort of vet our reasoning and our assumption so we will obviously review it with them again but it's incremental work just like it was this time. Okay, here's the latest information that we've developed. This is how we think it fits in to our analysis. Do you agree or disagree?

Carl Brown – Cramer Rosenthal

Great, and lastly Chuck could you just give me an update on sort of your thinking or progress on rigs in the Vermillion Basin, where we stand today and where we expect to be towards the end of the year?

Chuck Stanley

It's obviously -- it goes hand and glove with this work that we're doing on delineating the field Carl. Currently we're using older rigs, which are sub optimal for moving. They move in a lot of truckloads and so as we become more confident with the scope and scale with this play we'll be talking to joint contractors about specific custom built rigs for this program. That will be happening, hopefully, by the end of this year.

Carl Brown – Cramer Rosenthal

Okay, thanks a lot and again great quarter.

Chuck Stanley

Thanks Carl.

Operator

Your next question comes from Faisel Khan from Citigroup.

Faisel Kahn – Cramer Rosenthal

Good morning. I just wanted to see Chuck if you elaborate a little bit more on your last comment in terms of being able to drill up all these probable and possible reserves at a faster rate? So you say the data point of Vermillion is by the end of this year before you decide whether to take contracts for additional drilling rigs. How about for the other plays? How is that going to work?

Chuck Stanley

Faisel if you'll look at our previous IR presentation, our current IR presentation, in addition to the slides on the Vermillion, we have, what I would call, an EP life cycle curve. These projects all set somewhere on the curve as to our level of certainty and sort of the key point where a project moves from the testing and validation phase into a sanctioned commercial development project. Obviously, Pinedale is well into it. The Vermillion is on the cusp and as we gather more data our confidence goes up there and our ability and comfort with committing to large scale development in the form of long-term rig contracts because we're still talking about having to sign a significant term contracts in order to have new built rigs available for these projects. It varies with every well we drill and with more of a spatial sampling. Uinta Basin a little earlier in the process, obviously we have two wells down. As Keith mentioned, they're both very similar and characteristic to our results from the Baxter in the Vermillion Basis. As we see more performance from those wells and get additional wells down that project will move along the curve into the realm of commercial sanctioning. We'll have to work with joint contractors to pick up additional rigs. So it's a -- we try to give you that slide to help you see sort of graphically how we visualize these various projects and where they are in the continuum of certainty and maturity for commercial development.

Faisel Kahn – Cramer Rosenthal

How about the pilot wells on five-acre spacing in Pinedale and what do those look like now? How much data…

Chuck Stanley

Well, first of all we haven't drilled them yet. We'll drill them this summer with one of the rigs that's moving around to do some delineation work. After we get the data there's two things that we look at from these five-acre pilot wells. The first will be real time information where we will collect pressure data in individual sands to determine whether or not they've been drained or partially drained by the nearby well. Basically what we'll do is we'll offset some of the oldest wells that have been producing the longest on our property and theoretically those wells would have drained a larger area because they've been on longer so by offsetting them by five acres if there's going to be drainage or interference hopefully we'll see it in these five-acre pilots in the form of pressures that are below virgin discovery pressure. So that data will be real time and important. Then after we collect the pressure data we'll go on and complete the wells normally like we would any development well at Pinedale and then monitor the production performance to see whether or not the offset wells perform as the parent well is performing or if there's a lesser performance. From that production data we can then validate our assumption on reserves, degradation in reserves or interference between the five-acre well and the parent wells.

Faisel Kahn – Cramer Rosenthal

Okay, got you. Could you just talk about these 500, I think, expansion you're looking at on the pipeline system? What exactly is it? You said there was a binding open season they're holding on that pipeline system?

Keith Rattie

I'll let Allan Bradley handle that.

Allan Bradley

That's correct Faisel. What we're looking at is an expansion of our system from Fiddler, which is sort of in the core of the Uinta Basin over to the Greasewood/Meeker Hubs, which are the receipt points into the WIC and Rockies Express peonce laterals. We're also looking at an expansion of our Rifle line east to west coming up from northwest Colorado. Obviously we have, as Keith said, looked at a notional $540 million a day, which will be a combination of flows moving west to east from the Uinta Basin over the Greasewood/Meeker Hub and then basically Colorado east and north up to the Greasewood/Meeker hub. So we're looking at basically a pretty flexible service. We're looking for binding bids. We're asking customers would they like that service done incrementally or would they like to have Questar Pipeline integrated with this existing system, which gives them access to Clay Basin. We're a couple weeks week away from the open season closing. There's a lot of competition in these corridors but we're hopeful we'll get a sufficient interest that would allow us to go ahead and build in that corridor.

Also in the background we're talking with Northwest Pipeline about a joint venture expansion for some of their volumes, which would move basically Williams E&P production from the Greasewood area over to Sand Springs and interconnect with the Northwest Pipeline System. So there's a lot of activity in that corridor right now sort of driven by the big Rockies and WIC expansion project moving east and we see a potential to help debottleneck that corridor.

Faisel Kahn – Cramer Rosenthal

What's the cost of 540 mcf a day?

Keith Rattie

On the upside it's between $150 and $200 million.

Faisel Kahn – Cramer Rosenthal

Okay, thank you for your time.

Operator

Your next question comes from Shanure Garshunik of UBS

Sharnure Garshunik – UBS

Hi guys. Congratulations on a blow out quarter. Just had a couple quick questions. Some of the previous callers actually asked most of my questions. That said, I was wondering if it was possible to break out the fees that are associated with the deep play in the Mancos and so forth that were booked in reserves?

Chuck Stanley

For the Uinta Basin – This is Chuck Stanley Shanure. Are you talking about individual wells or the total?

Sharnure Garshunik – UBS

Basically bcf per well if that was possible.

Chuck Stanley

We assumed about 3 bcf per well.

Sharnure Garshunik – UBS

3 bcf?

Chuck Stanley

That's on a gross basis.

Keith Rattie

Chuck, just to be sure that's for the entire section?

Chuck Stanley

That would be for the Baxter to Dakota section so that would include the Mancos Section and Dakota Section only, the deeper section only.

Sharnure Garshunik – UBS

The deeper section, okay. My next question is I'm wondering if we could switch gears to the deep test at Pinedale and so far I understand it's completely a science project at this point right now. Just I guess the comments were it wasn't currently viewed as economically viable or there wasn't enough data and so forth. What is the next step that you guys would do? Is there any interest in drilling another one and you have flow data that you would be able to release at this point right now?

Chuck Stanley

Well Shanure, Keith gave you a little bit of flow data. We started testing this well last fall by testing the Hillyard shale. We have a very short duration test, as you recall, blocked off. We went back in. We cleaned it up. What we found during the clean out was really not as bad as we had feared. We had some concerns that perhaps the Hillyard had flowed into the well bore and completely plugged it but the upper obstruction was only about 30 feet and it mostly frag plug and prop up with a little bit of shale debris. We didn't encounter anymore obstruction in the well bore until we got down to about 19,050 feet where we hit a second obstruction and we're not sure if it was a frag plug. We had two frag plugs in the well when we fragged the Hillyard in three stages. One of them was the one that was up at 6,000 feet. The second obstruction, the deeper obstruction, down at 19,000 feet may have been a frag plug that moved a few hundred feet up the hole, which was set above the first stage of the Hillyard. We couldn't get through it. Now the other alternative interpretation is that the casing collapsed in the bottom half of the Hillyard. That's certainly a possibility given the bottom hole pressures or the mechanical calculations for casing strength will argue against that. It could have the damaged joint, a casing damage threads on one of the joints that collapsed. We just don't know. Given the pressures, we have determined it was uneconomic and very risky to continue the with the stumming unit to try to clean the well out. So we tested the lower interval. As Keith mentioned, during last fall's test we opened the well up to see what it would do and we'd never experienced any mechanical failure in the rock so we reported initial rates of 10.5 million a day or so last fall. This time we decided to basically hold back pressure on the well and not let the forming pressure drop too much and we saw with back pressure on the well that we could stabilize the well and flow it at a million or a million and a half a day from the Hillyard. Yeah, sure it might be more than that but you risk the mechanical integrity of the well bore and we just didn't want to do that. After seeing the Hillyard rates, which were about what we were expecting from the half interval or so that we tested we thought we gathered all the information we needed there. As you'll recall the primary objective was the Rock Springs so we moved pumped a total of six stages in the Rock Springs formation. From the bottom one the depth was a little over 18,000 feet, 18,200 feet; and the top of the top stage was about 16,330 feet. Six separate stages, all fracted and fracted at the same time, a multi stage frag stimulation, and the we drilled out of those frag plugs and commingled those six stages. Hillyard, remember is behind the plug. We flowed the well and what we saw was the initial rate of 2 and 3 mcf a day sort of stabilizing into one and one a half mcf. But interestingly in this interval, is a very coaly interval, especially on of the frag stages. We also were seeing a lot of water and this water is coming from the coal. So that's not surprising because typically coal has water in them. We don't know if there will water or not but it presents all kinds of interesting problems for dealing with water at this depth both for just the volume of water for a water gathering system and the challenges for disposal; but it also created some additional problems because the fluid combustibility issues creates a mineral scale inside the casing, which we had not seen in any of the other Pinedale wells and it's clearly related to the chemistry of the water is associated with the coal. So we're still producing that coaly interval. In fact, we think most of the gas in this Rock Springs is coming from the coal, very little is coming from the sands. That's due to the low permeability of the sands. We want to produce it a while longer to see if see any meaningful change in the water to gas ratio that would indicate that these coals are dewatering. We think they probably would dewater over time. The question is at the rates is it really economic to spend a lot of time trying to dewater them because it is, as you said, a science project and not an economic project. There's some additional sands up hole in the upper Rock Springs that we need to frag and flow back to determine whether or not they will produce at commercial rates. The logs are notoriously difficult to interpret in these type gas sands. We'll just to have to wait and see whether those sands are any better than what we've seen far. They're not markedly different that the sands that we've already tested. So it would surprise me if the result was much different.

Sharnure Garshunik – UBS

I guess would it be fair to say it's too early to try to figure out whether you want to do another science project?

Chuck Stanley

Well science projects are interesting for scientist and I'm a scientist so I would tell you that I'm interested in the science but as a businessman it's pretty difficult to justify drilling another well based on what we've seen in our area today. I mean it's clearly – there's a lot of gas in the rock. You know, when our technical team sits around and discusses this thing we can't come up with anything different to do in another well as far as completion technology and frac design that we think would yield any different result. It's just tied rock that we said at the outset is not giving up gas as commercial rates. We were actually frankly surprised at how easy to frag because we had mustered a lot of horsepower, especially for the Hillyard to pump these large fracs and the fracs went away very easily. In fact, they didn't look that different from a lands pool frac as far as the ease of pumping the frac jobs. So we think we got the well properly stimulated and it's just not giving up gas at rates that would be commercial at this depth and for these well costs.

Sharnure Garshunik – UBS

Okay. I'm sure there's lots of people with many more questions after me but I must say that we're definitely glad to see that both the Mancos and the Vermillion in reserves. I guess that's it for now.

Keith Rattie

Thanks, Shanure.

Operator

Your next question comes from Pam Rothwell of Wachovia Securities.

Sam Brothwell – Wachovia Securities

Hi good morning.

Keith Rattie

Good morning Sam.

Sam Brothwell – Wachovia Securities

Hey, Keith just – and I don't want to beat this deep test to death but from your vantage point let's say that that looks like it's not going to work out as originally possibly thought; but as you look at whole scene how does a loss of that deep potential if that's what happens. How does that effect your view of the overall potential for what your doing? It seems to me that maybe it's gotten a little bit overblown in the market.

Keith Rattie

Well Sam, we think it probably has. From my vantage point I'm much more interested in execution with respect to the lands pool development. We are early in the second inning of what may be the most profitable natural gas play in the U.S. lower 48 today. We've got over 932 locations total with over 750 those yet to drill on 10-acre density. If I had to rate the things that I think about today in terms of possible future growth potential I'm very focused on the results we're going to get from the five-acre density evaluation that Chuck talked about that we mentioned in our earlier remarks. I'm very focused on these next few delineation wells in the Vermillion Basin because they have the potential to extend the play significantly and very focused on the Mancos development as well.

A final concern as we focus on returns on invested capital, as we focus on costs and keeping our cost structure very competitive so remain one of the last ones standing if there is a significant pull back someday. I'm concerned about the impact that the dedication of rigs, people, time and capital to execute on the rest of the stuff. I hope that kind of helps you calibrate where…

Sam Brothwell – Wachovia Securities

Yeah, and I think it also important to think about that there were maybe 200 deep locations out of thousands of potential drilling locations.

The other thing I wanted to ask you Keith as, obviously the E&P story is continuing to clock along well. Is there any update to your thinking on how to ultimately properly structure the Company?

Keith Rattie

There's a lot of thought being given to that question as there has in the past and there continues to be a lot of thought given to it. When you're talking about structuring what you're talking about are any number of ways to unlock value and close, what we see, as a value gap in the Company today. The industry, obviously, is talking about the potential for putting pipeline midstream assets into an MLP. It's a pretty crowded array of offerings coming to the market right now. That gives us some concern. Our other issue there is that we've got several projects in the pipeline business that are going to require some capital. That if we execute the cash flows from that business will be significantly higher and that will give us more flexibility and probably enhance the consideration of an MLP. What we see trend emerging today is that MLP are launched on a much smaller scale. EBITDAs in the $40 to $50 million range typically with visibility to future growth mostly organic and much of that resulting from the drop down of assets of the parent and that's the model that we're looking at very closely.

We get a lot of questions about the utility and whether or not in the current industry environment remaining in integrated natural gas play is still the best strategy for the long-term. The answer to that question depends a lot on what you mean by the long-term and your view of commodity prices going forward. Our piece has been, and continues to be, that we can offer investors a lower risk play on the fundamentals of gas with this mix of businesses; but, as you know, the reality is that the utility this year will generate only about 8% of our corporate net income. It's significantly marginalized as far as shareholder value is concerned. This is a topic that we talk with our board about and every board meeting. We're going to have another conversation in August. We are a team that is going to do the right things for the shareholders over the long-term.

Sam Brothwell – Wachovia Securities

Okay, thank you very much.

Operator

Your next question comes from Carl Kirst of Credit Suisse

Carl Kirst – Credit Suisse

Just very quickly for you Chuck. Was there from an economic standpoint on the 3P reserve report was there any specific price that was assumed and also Chuck you have a rough estimate of what the development capital associated with the nonproved reserves are or should we basically be just using the development cost of the PUD, which I think we're just about 030 when we kind of run our asset values?

Chuck Stanley

Carl, I'll answer the last question first. Obviously, the development costs on the stuff the way the logic is you use now current cost and basically we looked at that and we see on average that these are $1.75 finding and development cost numbers across all categories on average. Some are higher and some are lower but it's in that ballpark.

The first question you asked, by nature of probable and possible reserves you don't look at a particular price deck when looking at these things. They're looked at on technical certainty basis and of course you go back and look at our earlier, our first probable and possible release last year you will see some definitions and we've adhered to those definitions, which are generally accepted I think by those who are engineering firms, reserve auditing firms, as the definitions for probable and possible reserves and they do not include a price deck assumption.

Carl Kirst – Credit Suisse

That was my understanding. I just wanted to make sure of that.

Chuck Stanley

So in other words Carl, in plain English, they're unrisk and by categorizing them as probable or as possible there's an implicit risk embedded in the categorization rather than reducing the absolute number for risk or price sensitivity.

Carl Kirst – Credit Suisse

Two other quick questions if I could, just delineation wells that are going to be drilled at the Vermillion late this year, so gain, just to confirm from a timing standpoint. We hopefully will be in a position that by the end of the year not only we have completed but we'll also have comfort with sort of the test data out of those three wells?

Chuck Stanley

Probably not; we're drilling these wells not necessarily in the order that you, as an investor or we as management, would like to drill them but we're being driven by when the permits are popping out of the BLM and secondly we're forming federal units and we're drilling these wells strategically to preserve as much lease hold as we can out here by unitizing and in a certain extent lease hold and expiring leases are driving our strategy of which wells we drill first and it's not necessarily the ones that you're the most interested in and that I'm the most interested in that are getting drilled first. Probably it will be late year before we get the key delineation wells down and maybe even into the first quarter and then we'll need enough production history from them to get comfortable. So it's a first quarter, second quarter '07 event before we really have a full comfort level on these off structure wells.

Carl Kirst – Credit Suisse

That's great color. I really appreciate that. Then last question. You know as we look at sort of the total production guidance for the full year '06 it would sort of seem to imply a relative growth rate that's a little bit lower here for the second half. I don't believe you guys have given official guidance for 2007 but I guess it's safe to say with everything that's going you guys are still encouraged hopeful of certainly seeing the same double-digit production growth in '07?

Chuck Stanley

I hope so Carl. I mean there's lots of moving parts here. As Keith mentioned, we've been pleased and frankly a little surprised at the delivery from our Mid Continent Team not only from the Western Mid Continent folks of Oklahoma City who continue to amaze us with the ability to harvest this rather mature set of assets to replace decline and then the Eastern Mid Continent Team who's charged with developing the Arcoma properties and also northwest Louisiana has been able to deliver outstanding growth in the Elk Grove area. They've recently picked up a second rig; but as that production volume grows it's a bigger and bigger snowball that you have to push uphill and it's unrealistic for us to expect them to continue to deliver the production growth rate that they have. They've certainly bolstered this year's early period first and second quarter growth. That's going to slow down some as we go into the third and fourth quarter into next year. We're fighting a fairly mature set of assets in the Uinta Basin that we hope this Mancos play that's evolving will help breathe new life into. So those are the variables and of course the big delta comes from Pinedale and this year we'll complete somewhere between 45 and 48 total wells. We think we can do a few more next year.

Again that snowball gets bigger and bigger. The big step change Carl in our ability to grow production organically is a process that's underway right now to submit to the BLM a supplemental EIS at Pinedale, which will allow us to go to varies of concentrated development, one for each of the three operators on the innacline (ph) that would allow for year round drilling, which we already have but we have on a limited basis. You'll recall we can drill with six rigs from three pads through the winter and we can't complete any wells until after May of each year and then we have to be done with our completions by the 15th of November. With this supplemental EIS, which we anticipate will hopefully be approved in the middle of next year, or by the middle of next year, we'll be able to go to a, more or less, conventional level of activity where we can drill, complete and move rigs around. We'll still be concentrating our activity on pads to reduce surface disturbance but we won't be constrained as we are not by only being able to complete half of the year. That could result in a step change in our ability to drive production out of Pinedale, potentially doubling the number of wells we can drill and complete in a given year. So that's a big catalyst out there but it won't happen until 2007 and even if it's approved it won't have an immediate impact because we'll have to move additional rigs into the area in order to achieve the full level of activity.

Carl Kirst – Credit Suisse

Great, that's excellent Kudos and good luck.

Chuck Stanley

Thank you.

Operator

Our next question comes from David Thickens of Deephaven

David Thickens – Deephaven

Good morning gentlemen. Most of my questions have been answered but going back to the revisions that you made today in your probables and possibles; in the May Analyst Meeting you had 680 3P wells and then another 3100 in resource potential. How many of those 3000 wells in resource potential, 3100 in resource potential were moved into the 3P category with today's update?

Chuck Stanley

Give me a second. The number of probable and possible wells included in today's number. I think Keith you have that number in your description.

Keith Rattie

202 was included in the probable estimate and 478 in the possible and if you add those two they add up to the 680. I believe the answer is zero.

Chuck Stanley

That's what I was thinking. I wanted to make sure that was correct. That's the number that I have as well.

David Thickens – Deephaven

Okay so we've still got over 3000 potential Vermillion wells that are not included in the 3P numbers, the revised?

Keith Rattie

As you go to Slide Number 21 the numbers we gave you today are consistent with the Vermillion numbers in that slide.

Chuck Stanley

Okay and the reason for that of course is we haven't drilled any new wells outside that limit of lowest known gas that we talked about in our analyst presentation in May.

David Thickens – Deephaven

Okay, so kind of the negative focus we're seeing on maybe the disappointment we're seeing about the relative lack of success so far in the deep test really seems to be missing the forest for the trees.

Chuck Stanley

That's certainly an interesting way to interpret it.

David Thickens - Deephaven

Okay. Fair enough. The other thing I'd love you to touch on a little bit is can you talk about the supplemental EIS and the Pinedale a little bit more. Kind of where we are in terms of timing? And if that comes through as hoped, what is that going to do for your ability to accelerate development in that play?

Chuck Stanley

Okay. Well, I just talked about it with Carl Kirst's question.

David Thickens - Deephaven

I'm sorry, I missed that then.

Chuck Stanley

Just very quickly, we believe that timing on that is likely second half of '07 for certainty. And as I mentioned in detailing my answer to Carl, the key is that it's not a switch. When we get approval, the next day we can immediately go to the rate change or step change in the pace of development to double the number of wells we can drill. It will take time to build a good quality inventory of rigs out there to affect the step change.

So it won't be an instantaneous event, but it's an event that is very meaningful for Questar shareholders. As to the process, it's the same process that any environmental impact statement goes through except because it's a supplement to the existing EIS, it's narrower in scope, but it still goes through a process of consultative meetings with various stakeholders, formal public input sessions, and then ultimately a full study of all of the various scenarios by the BLM and ultimately a decision by the BLM.

David Thickens - Deephaven

Am I correct, though, in that you really kind of have to -- if it's passed, you would have to be kind of at the minimum spacing or have the minimum spacing figured out, because once you're in an area and move out of that area, you can't go back in. If you develop it on 10s, for example, and then later decide that 5s are going to work -- ?

Chuck Stanley

You're absolutely correct, David. One of the tradeoffs in this supplemental EIS will be that we will concentrate our development activity in an area, drill it up and then move north or south through the field. And as we move out of an area, we will reclaim the surface disturbance that is larger of necessity for drilling, because you have to accommodate the drilling rigs and the associated equipment.

Once the drilling is complete, we can reclaim those surface disturbances down to probably about a half or less than half of the disturbance during the drilling phase. Once we do that, we're done. We will commit not to come back, which is why we are going to do 5-acre pilot studies this summer to determine what portions of the field are amenable to 5-acre development and answer that question so that we know the answer before we start into this concentrated development plan.

Keith Rattie

David, this is Keith Rattie, I'm going to cycle back to your earlier question on the Vermillion Basin and add a couple of key points that maybe we've overlooked and will help with the understanding of what we've done on reserves. We've mentioned in the Vermillion Basin that there are 680 grossed unrisked locations in the 3P estimates. 210 of those are in the probable and the rest are in the possible.

The probables are based on 80-acre development. The possibles pick up 40-acre development. The point I wanted to add is that well performance to date suggests, it's early, but it suggests that these wells are draining a lot less than 40 acres. And if you look at the resource in the Rock, I think you can see the potential for increased density down the road as well.

David Thickens - Deephaven

The resource potential wells are based on, is that a -- in the core area you've got it broken down 1400 in the core and 1800 in the expanded area. I'm assuming that the difference between the 680 and the 1400 or the incremental 1400 in the core is down spacing, of course at a greater extent than the core areas as well.

Chuck Stanley

It's down spacing to densities below 40, in the 20-acre density, and then the expanded area pushes the limits of the play off of the structures and into the synclines.

David Thickens - Deephaven

Thank you very much.

Chuck Stanley

You're welcome. Thanks, David.

Operator

Your next question comes from John Mansfield of SAC Capital.

John Mansfield - SAC Capital

Good morning. Great quarter, guys.

Keith Rattie

Thanks.

John Mansfield - SAC Capital

Just wanted to kind of ask a question about -- with the number of undeveloped locations you guys have now in the thousands, do you see any value in bringing in a partner doing some drill to earns or doing anything to accelerate the drilling in some of these fields to not only increase the actual proved but also just to increase the production?

Chuck Stanley

That's a good question. I'll take it, Keith, and you can bat it back and forth. The first thing that we want to do is delineate these plays. For instance, the Vermillion, we'd like to know what we have and have a good handle on its ultimate value before we consider taking a partner. I'm not going to foreclose the possibility of taking a partner, but frankly the limitation right now is not capital. It's the natural caution and sort of progression that you go through as you pilot, validate, and then start a commercial development project.

Even if we had a partner, our conversion rate from probable, possible to proved and from proved to production wouldn't be materially different. I think we have plenty of access to capital to, in essence, develop these assets at whatever pace we deem prudent. The other obvious constraint is the ability to obtain good drilling rigs and use those drilling rigs efficiently to develop these fields. As you know, places like Pinedale, we have further constraints on the pace of development like seasonal access restrictions.

John Mansfield - SAC Capital

Also, as you kind of alluded to the possible MLPing of the midstream assets, what would be the reason for not doing that? I mean, doesn't it just make so much sense to do that?

Keith Rattie

Right now our thinking on it is more of a timing issue. Clearly an MLP structure has the big advantage from a cost of capital standpoint, and we're very focused on that. MLP valuations today are better on a per unit of EBITDA and other metric basis than what we think is implicit in the ownership of assets in a C corp type structure.

It's a crowded field of current and potential new entrants. First law of stampedes is someone always gets trampled. But beyond that, we're looking down the road to the completion of these projects that we've talked about and then more flexibility in how you execute an MLP, a transfer of pipeline and potentially midstream assets to an MLP type structure.

John Mansfield - SAC Capital

And then I guess the last piece would just be on the deep Uinta. What is the spacing on the two wells that you have down in there now?

Chuck Stanley

They're 160 acres apart from each other in the same section, John. The third well is in the same section as well. Well, actually it is a section away but it is in the same area.

John Mansfield - SAC Capital

You haven't actually flowed from the third well?

Chuck Stanley

No. It's still drilling. It's nearing total depth. It's below 14,000 feet. We've had frankly some tough drilling problems at the well because of high pressures in the shale. It's a learning curve that we're on in drilling these wells as well. Our plan is to drill some more and obviously get some spatial sampling away from this area. This again happened to be the permits that we had in hand at the time.

Operator

Your next question comes from Rick Gross of Lehman Brothers.

Rick Gross - Lehman Brothers

I finally made the queue. I've got, I guess, just scraps left.

Keith Rattie

Rick, we were not trying to exclude you.

Rick Gross - Lehman Brothers

I took it personally. My assumption is on the supplemental EIS with the deep test coming in the way that it has. And you've got 5-acres pilots at the end of the year, that you'll probably go about a program that emphasizes the lance pool and that you won't spend a whole lot of time and attention to figuring out how you would want to optimally develop the deeper horizons at this juncture.

Chuck Stanley

That's a reasonable assumption, Rick. I mean, frankly, developing the deep and the lance pool simultaneously presented a whole host of challenges that involved different-sized rigs, potentially two separate gathering systems because of pressures, et cetera, et cetera. This profoundly simplifies it.

Rick Gross - Lehman Brothers

Right. From a standpoint you alluded to it any number of times. One of the things that I've wondered is that you've done a very, very good job of monitoring your costs, riding the rig operators, working all the various types science experiments into improved techniques to complete wells, et cetera. As you move from Pinedale, accelerate Pinedale a little bit, move to Vermillion, if you have success in the Mancos, do you have enough internal capacity? I mean, is all the people, your drilling engineers, et cetera, et cetera, scalable to handle attacks across multiple fronts? Or is that also an issue aside from just getting good rigs, et cetera?

Chuck Stanley

Well, obviously manpower is always an issue. And in this environment its a huge challenge for us, Rick. I think the interesting thing is a lot of the techniques and basically efficiency gains that we have been able to accomplish at Pinedale are transferable technology, not the specific well design but the techniques, the focus on certain things that really matter in driving down cost. And what we have now is a cadre of people on the rigs who are doing this stuff themselves and are looking for ways themselves to make improvements.

Pinedale, while I'm never satisfied with the results and we'll always drive for a lower number of days to drill and complete wells and lower cost. It's pretty much on autopilot. We've got a great group of people who are doing good things and making improvements every day out there. We can now take the core team of people who have driven that efficiency and turn their attention to another manufacturing process like Uinta or like Vermillion, use the same techniques, the same basic tools that we used at Pinedale, and I think that's something we're really good at and we've got a great group of people that do it. Trust me, it's not me that does it.

It's these folks that are focused on this 24 hours a day, seven days a week. And I have no doubt that, given time, that they will come up with ways to do the same thing that they did at Pinedale and Uinta in the Vermillion Basin. I think we have the people to do it. Most of the people that we have are obviously working very hard. But given their capability, we feel pretty comfortable that they can expand to take on additional work.

Keith Rattie

Rick, from where I sit, one of the most important things that Chuck and his team have done in the last couple of years is we've recruited a lot of new talent to the Company and some bench strength and some youth in the organization. It's pretty impressive to watch the younger folks learn from the old pros. And not too much emphasis on the "old" part of that. This industry, though, is -- I mean, this is a critical issue. I think it could be the Achilles heel for the industry if we don't continue to attract young talented technical professionals to the industry. We are doing our best to build this part of the organization. I am pretty pleased with what we have done to date, but we have got some more to do

Rick Gross - Lehman Brothers

Going to ask a question on the Mid-continent. It seem like over in Oklahoma you mentioned the Granite Wash, you mentioned the Atoka, I assume you've got a considerable amount of HBP that a lot of these things are developing plays that whether it is completion technology or its interpretation technology, would seem to set up a reasonably long duration inventory given, and you haven't talked so much about kind of we'll call it the inventory that you may have built there as far as well locations, the way you have described it in other areas. Can you actual do that, given the nature of how some of these plays are developing?

Chuck Stanley

They have developed kind of like amoebas. A lot of these plays started on structures and they have migrated off the structures and into the sort of the holes between the known structures. The Granite Wash play is a great example. You look at a Granite Wash well log, it looks like a Pinedale log. It has got just a huge pile of sand. And it use to be, back when I started out as a geologist and looked at the Mid-continent, you only completed the things that really met a specific pay criteria on your log analysis. And today you frac the entire section and it gives up gas. And people go wow, that is all reservoir.

Our western Mid-continent position, unlike Pinedale, the Uinta Basin, Elm Grove even, is a typical fragmented lease hole position where we have in many instances less than 50% working interest in sections. And those sections are by and large not contiguous. So, what we see is activity over a broad area and not a lot of concentration with just a handful of exceptions.

One being the Granite Wash play where we have identified 30 or 40 development locations to chase, so we are able to secure a rig and drill a program there. But that is the exception rather than the rule in the Mid-continent. And the technical team there and the land team, more importantly, start the year with no proved undeveloped locations and continue to drive production and reserve replacement with basically no inventory.

And it is an amazing accomplishment and one that they have continued to be able to do and it is a strong testament to their capability. And it is also a testament to the resilience of that basin as plays have evolved in these different intervals as tight gas sand technology has taken off, not only in the Rockies but also in the Mid-continent region.

Rick Gross - Lehman Brothers

Okay. One last question and this is - I am surprised that I haven't heard a revival of the storage project out at the Rockies, given the build out of your network, given the flexibility that you articulated earlier, that you are trying to provide people to access the multiple pricing points and given what I look at as huge seasonality. If you look at the forward curve and you kind of look at how gas is being priced in summer versus winter, is there a particular reason why we have not seen a revival in the storage projects you have talked about?

Keith Rattie

It isn't exactly dead, Rick, and I'll let Allan Bradley add to my comments. I assume you are talking about the Salt Cavern storage development --

Rick Gross - Lehman Brothers

Well, Salt Cavern or just any project at all.

Keith Rattie

One of the big hurdles today, and I'll let Allan -- we are active on a parallel path with the Salt Cavern project. But the big challenge today is the high cost, the big investment associated with cushion gas for storage. There is a lot of capital that is tied up just in filling up the Cavern to the level where you can add working gas and operate it. So, cost and therefore the economic value of storage is an issue. The other problem from a developers point of view is regulatory policy. You are absolutely on the mark, we need a lot more storage in this country and I think we are going to see evidence of that over the next couple of quarters. The U.S. market today would benefit a lot if we had over 4 Tcf of gas in storage at the end of the injection season, but that is not going to happen due to capacity limitations.

The regulated returns that are allowed for storage are not keeping up with the market value of storage and the costs and risks associated with storage development. It is a problem that we think needs some attention.

Rick Gross - Lehman Brothers

Thank you.

Operator

Your next question comes from Monroe Helm of CM Energy Partners.

Monroe Helm - CM Energy Partners

This is really for Rick Gross. I just figured out that they are going through the queue by age, since I just came in behind him. Actually my questions have been answered but while it is disappointing, I'm sure, that deep test didn't work out, it is probably good from a stock market standpoint that the focus will go off Ed and back onto trying to improve the present value of -- moving the present value of the 3P reserves forward and I think you are doing a great job going back to the Wyoming Commission to try to accelerate the Pinedale. So, great results and just keep it up.

Chuck Stanley

Thank you.

Operator

Your next question comes from Joe Magner of Petrie Parkman

Joe Magner - Petrie Parkman

I think I might have a couple more scraps to follow-up on. Any update on the Hiawatha EIS and where that stands?

Chuck Stanley

Joe, Hiawatha EIS, as everyone, maybe not everyone realizes, is the environmental impact statement associated with the Vermillion Basin development activity. Joe, it is moving along through the process. As we have stated these things take 18 to 24 months to go from inception to final approval. No surprises so far as far as anything that we didn't anticipate.

Joe Magner - Petrie Parkman

Okay. And there were, I believe, a couple more wells in Vermillion completed in the second quarter. Any update on those wells or just general comments on how, now that you have got three more months of production data on the Vermillion, how wells have been tracking to your model?

Chuck Stanley

You are correct there, couple more wells added. These wells were basically sort of inside the known limits of gas so they didn't add anything materially as to the areal extent of the gas. The well performance on the two new wells falls right onto the type curve that we've developed. And we continue to see from the older wells that these wells are tracking along pretty good on our type curve. We still see 2 to 4 Bcf range per well and everything seems to be holding together pretty good. So we're, as Keith said in his comments, gaining confidence in the repeatability of the play. Obviously we're anxiously anticipating drilling some of these off-structure wells to see if we see a fundamental change in the ROP properties or well performance relative to structural position.

Joe Magner - Petrie Parkman

Okay, great. And then just one other follow-up question on one of the first questions. Specifically the 2P and 3P potential based on the number of locations you lined out and then the per well reserves that you talked about and the net revenue interest, was there any sort of risk factor taken into consideration on the probable and possible on the Pinedale? It seems like if you walk through the math, locations per well reserves and then your 49% roughly net revenue interest, you come up with something much higher than what you put in the table. Just curious about risk and how that was taken into account.

Chuck Stanley

No, there is no risk other than the implicit risk in the categorization of the reserves. Probable reserves carry a higher probability than possibles. But the numbers that are included -- the way we build this is we start with gross un-risk per well reserves and then adjust. Obviously count the locations and then adjust for average working interest and average NRI. Keep in mind that we do in our 10-acre and 5-acre wells, and in the 20-acre locations, reduce the average EUR to take into account potential interference between wells drilled on denser spacings. So, as we stated in the past, we impact the reserve assignment for an individual 10-acre well at roughly 60% of the EUR of a 40-acre parent well within that 40-acre spacing unit. So, if that is what you mean by risking, yes, there is a reduction, but we believe, based on reservoir modeling, that there will be some sands that will cover greater than 20-acres and greater than 10-acres and therefore be drained by more than one well. And that we need to account for that in our reserve assignments.

Joe Magner - Petrie Parkman

Okay. Maybe we can follow-up off-line and just go through the math.

Chuck Stanley

Sure, be happy to.

Joe Magner - Petrie Parkman

Okay, great. And then just shifting gears on the regulated side. There were some hearings planned for June to discuss the issue of decoupling revenues from usage. Is there any update on that front?

Keith Rattie

I'll let Alan Allred handle that.

Alan Allred

Joe, those hearings that were scheduled for June have now been moved to the first week of September. Testimony is coming in, we still have support for the decoupling from the Division of Public Utilities, from Utah Clean Energy, and from a southwest energy efficiency group along with National Defense Resource Counsel. It is being opposed by our Consumer Advocate in the state and we will just have to wait and go through the hearings and see where we end up.

Keith Rattie

As you know, Joe, other states have embraced decoupling. It eliminates the disincentive that a utility has to work aggressively to promote conservation. For Questar Gas about 70% of our revenues are tied to volumes. We do promote conservation, mindful of the fact that when we are successful it hurts us. Decoupling would basically result if customer usage decline through conservation efforts, the utility wouldn't be hurt by it, We think that is a win/win for our customers, for Questar Gas and for the state. But as Alan mentioned, the state funded agency is opposing it. Others are opposing it unless we offer some kind of a rate reduction. So the outcome on this is uncertain.

Joe Magner - Petrie Parkman

Okay, thanks. That is all I've got.

Operator

Your next question comes from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs

Thanks. This may have already been asked, but just wanted to check what current finding and development cost assumptions are in the Uinta Basin, especially as it relates to the incremental probable and possible reserves that you added. What gas price do you feel like that works out? And what would be the finding and development costs associated with that resource?

Chuck Stanley

Brian, give me a second here while I find the numbers for you on the Uinta. As I mentioned in one of the questions, answered one of the questions, earlier, did not screen these reserves or [inaudible] reserves based on price. We did it strictly on a technical assessment, So these are price independent reserves. The question on finding and development costs, for the Uinta the average probable finding cost is $2.05 and the possible finding cost is $1.90.

Brian Singer - Goldman Sachs

Great, that is helpful. And is it safe to say that that is, I guess, between that and relative to Pinedale or relative to Vermillion that Uinta's on the high end?

Chuck Stanley

Yes, that's right. And let me point out, Brian, that these are un-risked reserves and un-risked costs and their cost based on current experience, not on any assumptions of future well cost savings through economies of scale like we are enjoying at Pinedale.

Brian Singer - Goldman Sachs

Based on your current price outlook and the drilling results that you have seen so far in the Uinta, is that something that you would think about accelerating drilling or what would be necessary for that to happen?

Chuck Stanley

We see more than just the Mancos as potential in the Uinta, we see the Lower Mesaverde, the Black Hawk. A silt in the upper part of the Mancos, which used to be as deep as we drilled, called the Mancos B, always adding incremental reserves to add to the economics of the Mancos play. We are also intrigued by the possibility of infilling our existing Wasatch well development program on 20-acre density. We were concerned about that on the standalone basis because of potential interference, probably wouldn't work.

With addition of Upper and Lower Mesaverde, Black Hawk, Mancos B and Mancos Shale reserves, we got up into the 4 or 5 Bcf per well range, that makes an economic play. And if we can get a repeatable result out of this deeper section as we drill some more delineation wells in the play across our acreage, certainly we will look at accelerating it. The limitation will be a, collecting the data to get comfortable and in b, getting the deeper rigs out there to drill it. Because remember, we are drilling down to almost 16,000 feet in these Mancos wells and the current fleet that we have out there, except for this one rig that we are doing the deep drilling with, is incapable of drilling wells to that depth.

Keith Rattie

Brian, just an added comment from my vantage point. Where we see the U.S. today, at least the lower 48, on shore scene is that threshold economics imply that producers are going to need Henry-hub prices north of $6.00, possible in the $6.50 range, to earn acceptable returns on capital. So we are going to run this business so that we earn acceptable returns at prices below those levels, hopefully well below those levels. We are going to try to take advantage of opportunities to hedge when the market is above those levels to protect our investment against possible downturns. But that is our current thinking. We think the marginal cost producer in a resource play today ultimately sets the long run price for natural gas in the U.S. market. Our intent and hopefully our execution will keep us well below that,

Chuck Stanley

And, Brian, let me add something that maybe wasn't clear to you when I spit out those numbers to you. Those numbers don't include this sort of incremental reserve adds above the deep section in the Uinta. So if we go in and we are successful and we think that we should get decent incremental reserves out of the Wasatch, that's not in the numbers yet. It is only reserves and well cost to drill the deeper section. So the finding and development costs could come down, obviously, two ways. One by getting additional incremental reserves in the shallow section and two, by reducing well costs through economies of scale.

Brian Singer - Goldman Sachs

Great. Very, very helpful, thank you.

Operator

Your next question is from Marshall Carver of Pickering Energy.

Marshall Carver - Pickering Energy

Quick question, this may have been asked. Any plans for a follow-up well, follow-up deep test in the Pinedale?

Chuck Stanley

Marshall, Chuck Stanley. We don't have any plans at this point to drill another deep well. We understand that other operators are going to drill one further south. We will obviously watch with great interest the results from that well to see if they learn anything that changes our view. And if they do, of course, then we will incorporate that information into our decision making process. But, no, we haven't permitted another deep well and we have no plans at this point.

Marshall Carver - Pickering Energy

Okay, thank you.

Operator

And a follow-up question from Carl Brown, Cramer Rosenthal.

Carl Brown - Cramer Rosenthal

Hi, guys, just a couple of quick loose ends. I was wondering if you could tell me where in the Q for Vermillion wells would be Alkali Gulch number three and the planned horizontal well B?

Chuck Stanley

Carl, I think Alkali Gulch number three will be drilled after the currently drilling Alkali Gulch number two. And the horizontal well will probably be drilled late this year, early next year.

Carl Brown - Cramer Rosenthal

Great, thanks. And, Chuck, on the 2 to 4 Bcf range that you are using for Vermillion, I believe you said in the past that the biggest variable in where you are in that range is the terminal decline rate and whether or not that is something like 6% or 8%. I was just wondering if you could update us on your latest insights into where some of those older wells are tracking along the terminal decline rate?

Chuck Stanley

Well, they are showing less decline than we currently have them booked at, which I think is a 6%, because we are seeing reserve growth at every quarter. As we look out in time we hope that that sustains itself. But, we just have another 90 days worth of information. They are very flat declines and that is not surprising given the massive thickness of shale we have open in these well bores.

Carl Brown - Cramer Rosenthal

Okay, great. And last question. I'm sorry, I missed the comment on the second DP winter well. Did you guys say that it is basically performing right in line with what the first was doing?

Chuck Stanley

It is.

Carl Brown - Cramer Rosenthal

Okay, great. Thanks a lot.

Chuck Stanley

You bet.

Operator

We have no further questions at this time. Are there any closing remarks?

Keith Rattie

We kept you on the call a long time. Thanks for listening in, everybody. You know how to get a hold of us. Also, you have access to our website for copies of slides and other information. Again, thanks for listening in today.

Operator

Thank you for participating in today's Questar second quarter earnings conference call. This call will be available for replay beginning at 1:30 eastern time today. The ID number for the replay is 4211295. Again, the ID number 4211295. And you may access the replay by dialing 800-642-1687. Thank you for participating. You may now disconnect.

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Source: Questar Q2 2006 Earnings Conference Call Transcript (STR)
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