Questar Corp. Q2 2008 Earnings Call Transcript

Questar Corp. (STR)

Q2 2008 Earnings Call

July 29, 2008 9:30 am ET

Executives

Stephen Parks - Senior VP and CFO

Keith Rattie - Chairman and CEO

Chuck Stanley - President and CEO of Questar Market Resources

Allan Bradley - President and CEO of Questar Pipeline

Allan Allred - President and CEO of Questar Gas

Analysts

Robert Christianson - Buckingham Research Group

Sam Brothwell - Wachovia

Nick Pope - JPMorgan

Carl Kirst - BMO Capital

Becka Followill - Tudor Pickering

Faisel Khan - Citigroup

David Hemron - Wachovia

Rick Gross - Lehman Brothers

Schinder Christoni - UBS

Winfred Ruha - Ruha Consulting Limited.

Presentation

Operator

Good morning. My name is Tiara. I will be your conference operator today. At this time I would like to welcome everyone to the second quarter 2008 earnings release conference call. (Operator Instructions).

I would now like to turn the conference over to your host, Senior Vice President and CFO, Mr. Stephen Parks. Sir, you may begin your conference.

Stephen Parks

Thank you, Tiara. Good morning and welcome to Questar Corporation's second quarter 2008 conference call. I will briefly summarize our results for the second quarter 2008 and then turn the microphone over to Keith Rattie our Chairman and CEO for some additional color. Keith will also update earnings and production guidance for 2008. After Keith, we'll invite your questions.

Other members of Questar's management team are here to answer your questions including Chuck Stanley, President and CEO of Questar market resources; Allen Bradley, President and CEO of Questar Pipeline; and Allen 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. We make these statements in good faith. We believe they are a reasonable representation of the company's expected performance at this time. But actual results may vary even significantly from our current expectations and projections due to a variety of factors that are described in our form 10-K filing with the Securities & Exchange Commission. Now, here is a short summary of our second quarter 2008 results.

Questar grew net income 54% in the second quarter 2008 to $172.6 million or $0.98 per diluted share compared to $112.2 million or $0.64 per share a year ago. We now expect 2008 net income to range from $3.50 to $3.60 per diluted share compared to prior guidance of $3.25 to $3.40. Our market resources subsidiary continued to lead the way, growing net income 59% to $162.1 million in second quarter 2008.

Three of our market resources segments, Questar E&P, Wexpro and Gas Management delivered double-digit net income growth. Questar E&P grew net income 75% to $116.8 million with production increasing 14% to 40.6 Bcfe. Realized prices for natural gas, crude oil, and NGL increased 28% more than offsetting an increase in average production costs.

Wexpro grew net income 28% driven by a 30% increase in investment phase over the past 12 months and higher oil sales. Questar management grew net income 46% driven by higher gathering and processing margins. Net income from energy trading was $4.8 million; $1 million lower than a year earlier as a result of reduced trading margins.

Questar Pipeline, our interstate pipeline storage business, earned $12.7 million in second quarter 2008, up 27% from 2007. The increase was driven by higher transportation revenues from expansion projects completed in fourth quarter 2007. Three onetime events in second quarter 2008 combined to reduce pipeline net income by $2.1 million.

During the second quarter, pipeline recorded a $6.8 million after-tax impairment of its entire investment in a salt cavern gas storage project. They also recorded a $2.4 million after-tax gain from the sale of their processing plant and related gathering lines, and a $2.3 million after-tax gain for the collection of a note receivable that had been previously written-off.

Questar Gas, our retail gas distribution utility reported a seasonal second quarter 2008 net loss of $2 million compared to a loss of $1.1 million a year ago as higher operating and maintenance expenses more than offset gross margin increases from new customers. Questar Gas now serves 881,500 homes and businesses, up 2.3% from a year ago. For more details on our second quarter 2008 results, you can find our earnings release in the latest version of our Investor Relations presentation on the Questar website at questar.com.

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

Keith Rattie

Good morning everyone. Bottom-line, Questar Corporation made over $358 million net income in the first half of 2008 as Steve noted', that's up 36% from a year ago. And as Steve noted, all six Questar business units posted record net income in the first half.

With the first half now in the books, we now expect 2008 net income to range from $3.50 to $3.60 a share, that's up $0.20 to $0.25 per share from our prior guidance of $3.25 to $3.40 per share. We listed the key assumptions in our earnings release so I'm not going to take time to repeat those here. Other than to point out that with hedging, we've taken most of the commodity price risk out of the equation for Questar for the remainder of 2008. We estimate that a $1 change in the average NYMEX price of natural gas for the remainder of this year moves Questar 2008 EPS by only about $0.02 per share.

Please note that our guidance excludes onetime items and excludes unrealized gains and losses on basis swaps. You will note the hedge table at the end of our release; we now have basis only swaps on 183 billion cubic feet of natural gas production over the next three-and-a-half years.

We've added about a 140 Bcf of basis swaps since our last call. I'd remind you that the quarterly mark-to-market on the basis swaps could result in some volatility in our reported net income.

The highlight for the quarter is that Questar E&P grew natural gas and oil equivalent production 14% in the first half of 2008 compared to a year ago. Note that our Midcontinent team grew production 27% from a year ago, and that 42% of Questar E&P second quarter production was in the Midcontinent. We expect Questar E&P full year production to range from 166 billion cubic feet to 169 billion cubic feet equivalent. That's unchanged from our prior guidance and it's up 18%, to 21% from 2007.

We'll give initial production guidance for 2009 with our third quarter earnings release, but two developments over the past months should give investors better visibility on this company's future growth opportunities.

Item one: As we reported in our July 7th press release, we've updated Questar E&P probable and possible reserves and petroleum resources estimates and for the first time we've reported estimates of non-proved reserves in our second E&P business, Wexpro.

Let me give you just a quick recap. Questar E&P estimated proved reserves as of March 31st, 2008 were up 16% from year end '07 to 2.2 trillion cubic feet equivalent. That is a trillion cubic feet in natural gas equivalent. That increase was primarily the result of our first quarter '08 acquisition of development properties in Northwest Louisiana. Questar E&P estimated net probable reserves jumped 68% from two years ago to 4.2 trillion cubic feet equivalent and almost 50% of those I would note are at Pinedale.

Questar E&P estimated net possible reserves jumped 46% to 5.1 trillion cubic feet equivalent. Questar E&P estimated net petroleum resource potential jumped 836% to 18.4 trillion cubic feet equivalent and that's since our last update in March of 2005.

Please note that Wexpro estimated net probable reserves are 1.09 trillion cubic feet equivalent and that's on top of the 642 billion cubic feet equivalent proved reserves that Wexpro previously reported at year end '07.

Now, we put a lot of detail on these estimates in our July 7th release and in our updated IR presentation. Both of those are available on our website. Please note we have our estimates of non-proved reserves reviewed by our independent reserve engineers. Our 3P reserve estimates conform to the definitions used in the Petroleum Resource Management System classification framework.

I've mentioned that because the proposed new SEC reserves-reporting regulations will be based primarily on the PRMS definitions. Item number 2 in June, the BLM issued the final SEIS for development on the Pinedale Anticline. The BLMs preferred alternative D, would allow year-round drillings and completions, rig moves and other activities within the three concentrated development areas on the anticline.

This preferred alternative cuts emissions by 80% from a 2005 baseline and greatly reduces habitat disturbance and fragmentation compared to what's allowed under the current 2000 Pinedale ROD. We're expecting that the BLM will issue the recorded decision, the ROD, in early September and if they do, we may be able to ramp up from 73 wells to 78 wells at Pinedale this year, to a 105 wells to a 115 wells next year, and then ramp up further to a 140 wells to a 150 wells in 2010. We hope to give you more detail on our plans for 2009 at Pinedale, 2009 and beyond once the BLM issues the ROD.

Let me turn to operations. This quarter I am going to start with the Midcontinent and as I noted at the outset our Midcontinent chain grew production 27% in the first half that was driven by our Cotton Valley Hosston tight gas plan in Northwest Louisiana and our Granite Wash Atoka play and the Texas Panhandle. Now we expect our Midcontinent E&P margins to be stronger than margins in the Rockies over the next few years, margins of course drive returns on capital so you should expect us to allocate capital accordingly.

We currently have nine Questar operated rigs on our core acreage in Northwest Louisiana. Six are drilling vertical Cotton Valley/Hosston wells. Well results to-date from the properties that we acquired in the first quarter has been consistent with the performance we modeled in the acquisition economics.

Please note that we're drilling ahead with our first horizontal well in the Cotton Valley formation on the Thorn Lake property. You'll recall that we identified horizontal development in the Cotton Valley as an up side, but we didn't value it when we acquired these assets. We are going to need to evaluate horizontal potential before we drill vertical wells in these less developed areas.

As we noted in our latest IR presentation, Questar E&P now has Haynesville share rights to over 30,100 net acres in Northwest Louisiana. Our Haynesville journey, I would note, is now underway. We're drilling ahead on our first two Questar operated Haynesville shale wells, one each on the Thorn Lake and Woodardville properties. We're planning to core and log the entire Haynesville interval in both wells before we plug back, kick off, and drill the horizontal lateral, so it will take a while before we have results to report.

I would note also that we've also staked the next two Questar operated Haynesville wells in the Woodardville and we're waiting for results on the first non-operated Haynesville well drilled in the Elm Grove Field. We've also elected to participate in a second outside the operating Haynesville well at Elm Grove. The operator there plans to begin drilling this well by the end of the quarter.

Now, like other operators in this play, we're going to have to move quickly to evaluate Haynesville's potential on some of our acreage. About a third of our Haynesville rights are not HBP and are therefore still under the primary lease term. Where this is the case we have to drill a well to establish production from the Haynesville during the primary term of the lease or we lose our Haynesville rights. Most of the primary term leases don't expire until 2010 or 2011, but a few do expire this year and next so we're focused on those right now.

You'll find more detail on slides 19 and 20 in our latest IR presentation. Let me move to the Anadarko basin, another highlight in our first half. Our Oklahoma City team is delivering solid growth from our Granite Wash, Atoka, Morrow tight gas play in the Texas Panhandle. We now have eight rigs drilling ahead in this play, four operated and we now have over 270 identified gross locations in our drilling inventory in this play, and that's based on 40-acre density.

We expect now to participate in over 60 gross wells in this play in 2008. That's up from 48 at the time of our last call. Our Oklahoma City team is also reporting early success in the emerging Woodford shale play in Canadian County and Western Oklahoma.

Today we participated in five wells that have been drilled completed and turned to sales by outside operators. Initial results in these wells appear consistent with the data that we shown on slide 21 in the IR presentation. We're also participating in another well that's been drilled, cased and waiting completion. We're participating in another four outside operated wells that are drilling ahead and we've recently elected to participate in an additional 15 Woodford shale wells in Canadian County. Our average working interest in this play is about 17%, and we now estimate that we have 488 potential locations on 160-acre spacing.

Now let's come back to the Rockies and give you a little more color on Pinedale. Those of you who follow our story know because of BLM imposed winter drilling and completion restrictions, Questar E&P Pinedale production typically declines in the first half and declines in the second quarter compared to the first quarter. But that should change beginning of next year. Recall that we came out of the past restricted winter drilling season with 40 wells drilled, cased, and ready to complete. As of today we've turned 36 of those new wells to sales so far, and we have another dozen or so that are either being completed or waiting on completion.

This summer we have nine rigs operating at Pinedale. Please note that as I mentioned earlier, we now expect to drill and complete 73 to 78 wells at Pinedale this year', that's up slightly from 70 to 75 in our prior guidance.

Now, let me turn to the Uinta Basin. You'll note that the second quarter production was down from the first quarter and down from a year ago. This is not related to well performance. Our Uinta Basin deep play is working as we described in our IR presentations. But gathering system issues negatively affected our second quarter production and here is the problem.

The deep well has come on at high flowing pressures and we tied one of the deep wells into our existing gathering system. We knock-off production from the older lower pressure shallow wells, so you put a new well on at 4 million to 5 million cubic feet a day and nothing shows up at the other end of the system.

We've planned and we know we've got to build a segregated high pressure gathering system but that unfortunately is taking longer than we planned because the under staff BLM is taking up to nine months to issue rights of way for new gathering lines, even when the new line is in an existing corridor adjacent to an existing line.

In the interim, we have moved the five rigs we have in this play to areas of our Uinta leasehold that are less affected by these gathering system issues and the worst case is we may have to move some rigs to other plays outside the basin until we get our gathering system built out.

Let me turn briefly to North Dakota. Recall that we've acquired 62,000 net acres in the emerging Bakken shale oil play. We're still planning to spud our first well later this year. Game plan here is to have several well permits in hand before we move a drilling rig in. We remain optimistic that our acreage is well situated in the play and we continue to expect well results described on slide 18 in our IR presentation.

Turning to Wexpro. As we've said in the past, we're turning up the growth in our second E&P company. We grew Wexpro's investment base 30% in the first half of '08 compared to a year ago. We plan to invest roughly $700 million in Wexpro over the next five years and if we do that, Wexpro's net income could double. And with over 1 trillion cubic feet equivalent of probable reserves in Wexpro, five years from now, we'll still have a big inventory of undeveloped locations that should allow us to sustain Wexpro's growth well into the future.

I'll remind everyone that Wexpro develops and produces gas and oil on a defined set of properties in the Rockies on behalf of the utility. Under the 1981 Wexpro Agreement, Wexpro delivers gas to the utility from these properties at a cost of service that includes 19% to 20% after-tax unlevered return on its net investment base.

We hope that you've noticed that our Rockies gathering and processing business grew net income 47% in the first half of 2008. Gas management is on track for late fall completion and start up of a 107-mile 30 inch gathering trunk line, a very important project that will move Questar and third party production from Questar's Pinedale acreage to our processing complex at Blacks Fork. This summer we're also installing the first gas turbine driven compressor at our Gobblers Knob facility on the south end of our Pinedale acreage.

Our business development team in gas management continues to generate attractive investment opportunities. We think gas processing margins in the Rocky Mountain region could remain attractive for the next several years. So we're now evaluating a major expansion of our processing complex at Blacks Fork to handle growing Pinedale volumes.

We're also evaluating an expansion of our stage coach Red Wash processing complex in the Uinta Basin. We also hope that you notice Questar pipeline's first half results net income was up 35% from a year ago, that was driven of course by the expansion projects we completed last year, and that's despite the net loss from one-time items that Steve mentioned.

Our pipeline team's role as we said in the past their role in our corporate strategy, is to protect returns on invested capital in our Rockies E&P business and to do that by identifying and eliminating pipeline bottlenecks in our core Green River and Uinta Basins. Just some examples of this strategy at work, we're working with a sponsor of the proposed Ruby pipeline project to offer low cost expansion capacity on over thrust pipeline to allow Ruby shippers to move gas from Wamsutter Canada and Blacks Fork to Opal for delivery into Ruby.

Our pipeline team is on track to complete the Greasewood compression project and the white river hub project which of course is a joint venture with enterprise by the end of this year. Questar pipelines also are working with its partner Alliance Pipeline to redesign the proposed Rockies Alliance Pipeline project or RAP.

RAPs open season in June convinced us that that Rockies' producers in the Chicago area utilities prefer and therefore would be more likely to commit to capacity on a new pipeline that moves Rockies' gas directly to the Joliet Hub in Chicago. The current Rockies forward basis in our view is conveying a very simple message. We need another Bcf a day plus export pipeline by 2012. Rockies producers should get some relief from current wide basis differentials once the final phase of Rockies express or REX is completed and put into service. But even with REX and even with Ruby, growing volumes from Pinedale and other major Rockies plays may fill those pipes by the time they go into service.

So, let me summarize, 2008 shapes up to be another good year for Questar. We've raised our full year 2008 EPS guidance by $0.20 to $0.25 per share from our prior guidance. With the final SEIS at Pinedale we're one very important step closer to accelerated year-round drilling what is this company's most valuable asset.

Our second quarter results highlight our E&P growth in diversification strategy. We expect Questar E&P production to be up 18% to 21% this year from a year ago. Midcontinent production was up 27% in the first half and 42% of Questar E&P second quarter production came from our Midcontinent assets.

We're drilling the first of several Questar operated Haynesville shale wells. Our Oklahoma city teams delivering solid production growth in the Anadarko basin and Texas Panhandle and employees in all Questar business units continue to execute well. In short despite some challenges 2008 shapes up to be another pretty good year for Questar.

And with that, we'll be glad now to open it up for your questions.

Questions-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Schinder Christoni with UBS.

Schinder Christoni - UBS

Good morning, guys.

Keith Rattie

Good morning, Schinder.

Schinder Christoni - UBS

I guess, if you don't mind, I would like to start with the resource potential that you highlighted back at the beginning of the month. Specifically, with respect to both the Haynesville and you also booked some key Pinedale's potential in the resource potential group, what kind of milestone should we be looking for to see those potentials moved into the 2P and 3P category? I guess, how far away do you think, you would be from commercial development on either of those plays and so forth?

Chuck Stanley

This is Chuck Stanley. I will take in reverse order. On the Pinedale the potential obviously we drilled a well and tested it several years ago, and as we discussed when we talked about the well results, we tested gas from the Hillyard shale and from the Rock Springs section in the deep part of the well. We estimated at the time that the individual intervals would flow at rates of $1.5 million to $2 million a day in the shale and $1.5 million or $2 million a day in the overlying Rock Springs section.

Key issues for us were that those rates didn't justify the increased well cost of drilling to 19,000 plus feet. We had some fluid compatibility issues and some Co2 in the gas which presented some significant obstacles to commercial development commingling of the deeper section with the shallower normal Lance Pool plays at Pinedale.

If you go back and look carefully at our disclosure from our original problem possible reserve estimates, the resource potential in the deep Pinedale did not change. The same number appears in the earlier version, so we left it unchanged, still a resource. There is gas in the ground out there. With today's technology we think it is marginally economic to uneconomic, but that's the definition of resource potential. It is something that with either increased recoveries through a new hereto for unknown completion technique and/or reduced well costs and/or higher gas prices would suddenly move into the problem possible category.

The Haynesville is a bit different. The Haynesville is a play that frankly is further up the curve as far as commerciality. I am sure that you're familiar with some of the results from offset operators including a recent well that was reported in the media as IPing over 16 million a day, from a horizontal later in the Haynesville and interestingly it is offset directly by Questar acreage on three of the four sides. So, very interesting and encouraging early well results in the Haynesville which obviously spurred our interest in going ahead and putting two rigs to work evaluating the deep potential on some of our expiring leases that Keith mentioned.

These resource category plays are something that obviously we're focused on moving up the certainty category from resource potential into the problem and possible category, but obviously for shareholders what really matters is converting all of these non-proved categories to proved reserves and ultimately to proved developed producing wells and that requires more rigs, more capital, and a focus on allocating capital to the highest return plays in our portfolio as Keith mentioned in his comments. I hope, I answered your questions. They're long-winded answers.

Schinder Christoni - UBS

Okay. Let me start with deep Pinedale. There is basically nothing new to report at this point in time, but the Haynesville does look promising, and I guess we should just keep watching all the different results from the wells that you're drilling on the potentially expiring leases and should give us an indication of how we should be thinking about that?

Chuck Stanley

Much better and shorter answer than my long-winded one wants to know, thank you. There is a well drilling as most of you are aware to the south of our acreage by another operator at Pinedale. We'll be watching those well results. I would hope that you'd hear some early results from that well, maybe in the quarterly call coming up for that unnamed operator. And then at Haynesville it will be our own well results because frankly today the actual data, the hard data that has been released is very limited from wells drilled to the west of our acreage by other operators and to the south by another operator. So, we're acting or reacting to limited data.

As Keith mentioned, we're going to core our wells. We'll drill first vertical pilot holes to go straight through our vertically through the Haynesville section, collect core data because core data as you know in shales is very important to determine gas saturations, porosity, permeability, the percentage of absorbed gas versus free gas in the rock which has a direct impact on deliverability and ultimately on recoverable reserves, and the decision about how closely to space these wells. Then we'll obviously get a full set of logs, and then try to choose from that data in real-time more or less what part of the Haynesville we'll land the horizontal lateral in and how far we drill laterally into the section before attempting a completion.

Schinder Christoni - UBS

Okay. If I could just ask about the Uinta Basin for a minute here, obviously you're having challenges with the gathering system and you're waiting on the BLM and so forth, but from a drilling perspective were you seeing any improvements with respect to drilling times and costs prior to the challenges you saw with the gathering system and so forth?

Chuck Stanley

The answer is absolutely yes. We've seen a 25% or 30% reduction in drill times from the early wells we drilled in the basin, and it's across the several different well designs for the deep wells. Unfortunately, those drill times haven't resulted in a proportion of reduction in costs because on the input side of the drilling equation we're obviously the victim of higher commodity prices in our business which translates into higher diesel fuel for drilling rigs, and higher costs, particularly concerning element of costs is the higher costs for our oilfield, our oil country tubular goods which is a direct reflection of higher steel prices.

And just, in general, higher service costs as we go forward here, we're seeing most of the time savings and efficiency gains offsetting increased costs with not a substantial reduction in overall well costs unfortunately at this point.

Schinder Christoni - UBS

Okay. And one final question if I may. Keith, you highlighted a whole slew of investment opportunities including really pushing Wexpro and so forth. Do you feel that your cash flow generation, your capital structure is appropriate for all the opportunities that you have in front of you? Or are you looking to expand your capital at all? Or are you just going to sort of prioritize just top return projects and go from there?

Keith Rattie

I think it's a good question, Schinder. I think the message that you received is the right message. This company has abundant opportunities and attractive places to reinvest in our core businesses in a circumstance like this that gives us an opportunity to high-grade our capital spending plans, I think one of the things we tried to highlight in the prepared remarks is the fact that we're doing that. We have some problems in the Uinta Basin, Rockies basis as you know is wide and likely to remain wide for a few years. So you're going to see a movement of capital to lower cost plays in the Rockies and to the Midcontinent.

We did lever up in the first quarter to make the acquisition in Northwest Louisiana with the good results that we're seeing. We expect our E&P team to quickly turn those assets to production in cash flow and to deliver. Our view on our balance sheet has not changed. We intend to maintain a strong balance sheet and intend to maintain strong credit ratings.

So in summary, opportunity to allocate capital to the best quality projects and favoring those that generate high early cash flow that will help us de-lever and reload the balance sheet.

Schinder Christoni - UBS

Okay. One just question that just totally slipped my mind. Your production guidance was not increased when you released guidance last night. Yet your Pinedale well completions are increasing. Are they just coming on too late in the year to have a meaningful impact? And then secondly, is the challenges in the Uinta kind of the offset as to why the production guidance is not going up?

Chuck Stanley

It is Chuck again. You're exactly right on the Pinedale, the increase in well count there, two or three wells added to the end of our completion season. So they'll be coming on basically on the last day of November. And a lot of these wells, I probably need to point out that the wells that we're drilling this summer are largely in the north part of our acreage, and that is not an area that will be part of the initial concentrated development area with approval of the SEIS and issuance of the record decisions.

So, we have to complete those wells and be out of that area by the 15th of November, it will still be under the normal seasonal restrictions. So adding a couple or three wells at the end of the drilling and completion season, the normal November 15th deadline will have a few tenths of a Bcf impact on production in out of Pinedale, so not a big impact. The other thing to keep in mind at Pinedale is in certain areas in certain individual wells Wexpro has a higher working interest than Questar E&P, so even though we talk about adding incremental wells the net revenue interest and therefore the net production to Questar E&P varies depending on where those wells are.

As to the Uinta basin, it's very difficult to forecast timing on the installation of the additional gathering trunk lines to handle the high pressure wells. As Keith mentioned in the prepared remarks, every time we add a new well, we don't get the full gross production volume showing up at the plant. The impact is two fold. One, the high gathering pressures tend to suppress the performance of the new high pressure wells we put on because they're bucking higher line pressure and, two, all of the old low pressure wells that are on that particular branch or note of the gathering system experience an immediate suppression of production because they're generally very low pressure and the higher gathering pressure impacts the whole family of wells on that gathering system.

So, forecasting the impacts of adding new wells and what will actually show up at the sales point is a difficult hydraulic modeling exercise and so we're being pretty conservative on our assumption on, A, what that impact will be as we add new wells and, B, timing on installing the new gathering loops because of the fact that we have to rely on permits out of the Pinedale BLM office and the folks out there are terribly overloaded just processing normal drilling ABDs, so it could be early next year before the system is installed.

Keith Rattie

One more just simple piece of a very particular on that. The deep high pressure wells generally are working interest is quite a bit less than 100%, typically about 66%. The older production is coming from Wasatch wells where we have a 100% working interest.

Chuck Stanley

One final point I'll make, something that perhaps you haven't thought of and that is that we acquired a substantial producing property or several substantial producing properties in late February and in Northwest Louisiana. Those properties have gross production of a little over 50 Min cubic feet a day when we acquired them, but that production volume had been built by drilling with a large number of drilling rigs that had been active in the fourth quarter of last year. It took us quite a while to permit new locations, get rigs into the area and ramp up to where we are today which is nine drilling rigs working in Northwest Louisiana, so during that time period the existing wells that were on those properties have continued to decline.

We just now begun to arrest that decline and turn the production curve back up. That timing will be somewhat impacted now by allocating some of those rigs to drilling Haynesville wells which take a lot longer to drill and complete, over 60 days to drill based on what the offset folks have done on drilling the wells and then probably another 30 days or so to complete them and get them online. So, we hope that the result from one of those wells will more than offset the amount of time it has taken us to drill it. But in the meantime production continues to decline while we're drilling those wells.

Schinder Christoni - UBS

Great. Thank you very much. I have taken up too much time.

Operator

Your next question comes from the line of Robert Christianson with Buckingham Research Group.

Robert Christianson - Buckingham Research Group

Thank you. What do you think the odds of the SEIS not getting approved? To me that is a presidential election year, things can get lost to politics. What would you place the odds of that?

Keith Rattie

I am about as good as handicapping the government as I am at handicapping elections, but, Bob, our view is that a very significant step occurred 30 days ago when the BLM issued the final draft of the SEIS which as you know was delayed several times due to the consulted process that the BLM follows under these types of documents. The final draft was issued about a month ago. The 30-day waiting period co-incidentally or public protest expired on Monday, and so the next step is the drafting and issuance of the record decision and everything that we've seen to date suggests that that record decision is on track for issuance in 60 to 90 days or so.

Now, why do I have high confidence that it will be approved? Several reasons, the most important is that it is so much better. It is an unprecedented commitment on the part of industry to do things that aren't required under current regulations, environmental regulations, federal regulations, and therefore it is really a sort of a tight model for responsible development on public lands in the western US.

Commitments to significant reductions in air emissions as Keith mentioned the 80% reductions in air emissions from a 2005 baseline, a number of other important commitments including installation of liquids gathering system to reduce truck traffic, the commitment to move onto these areas of concentrated development, drill up all of the subsurface locations from pads without disturbing over 95% of the broader field area. And use of flair less completions, a large number of acres set aside and put into basically a moratorium outside of the core Pinedale Anticline producing area.

So, when you look at all of those things that the operators on the Pinedale Anticline have committed to do voluntarily, in conjunction with this supplemental EIS, which is supported by the major stakeholders including Wyoming Fish and Game, the Governor's office and other interested parties. It's hard to argue why this thing would be denied or not acted upon.

Robert Christianson - Buckingham Research Group

If I may, a second question. You've spudded your first Bakken well. How did you choose that particular location?

Chuck Stanley

Well, unless my folks are not telling me everything, and there are morning meetings. We haven't spudded yet, Bob. We staked the Bakken well and we chose that location based on the proximity to some old vertical wells that give us some reasonable subsurface control on the presence of the porous middle Bakken interval. As well as the maturity of the Bakken source rock, the upper and lower Bakken shales that in case that porous middle Bakken interval.

Robert Christianson - Buckingham Research Group

I am sorry; I read the article about being stakes. But how soon before drilling rig moves in?

Chuck Stanley

As Keith mentioned in his prepared remarks, we like to accumulate multiple drilling permits. When we mobilize a rig to North Dakota, we can amortize the mode cost over more than one well.

Robert Christianson - Buckingham Research Group

Very good. I'll get back in line. Thank you, Chuck.

Chuck Stanley

Thanks, Bob.

Operator

Your next question comes from the line of Sam Brothwell with Wachovia.

Sam Brothwell - Wachovia

Hi, good morning, just a couple of quick ones. I know you hit the Haynesville; can you give us an idea of timing when you may be able to delineate that? Number two, with respect to Uinta are you still seeing AURs inline with what you had originally expected? And finally, maybe you can talk a little bit about what your plans are during the Rockies express hydrostatic testing that's coming up?

Keith Rattie

I'll let Chuck take at least the first two and the third if he wants.

Chuck Stanley

Well, on the Haynesville, Sam. As far as delineating the presence of the Haynesville, it's a marine shale. It seems to be present based on a loose grid of vertical wells that were drilled. Some of them were drilled many years ago, some more recently and offset operator activity. We're pretty comfortable saying that the Haynesville exists under all of our core acreage that we show on our IR slide there that addresses the Haynesville. To me the key for delineation is probably a technology application here. What is the appropriate interval in the Haynesville to drill the horizontal lateral? How many frac stages should be pumped? How long should the lateral be? I think those are the kinds of questions that will take some time to answer.

Generally, I think longer laterals are better, more frac stages are better based on their early well results that we've heard and tidbits' about. As for our acreage, it will take us with a couple of rigs working, and with participation in outside operated wells, it will take us a few months, at least a year or so to get a grid of control over and around our acreage.

As for the EURs in the Uinta Basin, our well results to-date have been spot on with our 3 Bcfe to 5 Bcfe, 3 Bcfe to 6 Bcfe range. Obviously, we've had some enormously good wells like the 9D Dakota well that I think we got booked at close to 8 Bcfe just in the Dakota. But the fundamental impact here has been not on well results but on production volumes as a result of the gathering system problems that we've discussed earlier.

Sam Brothwell - Wachovia

All right.

Chuck Stanley

One other thing that I should point out about the Uinta, there is a lot of noise going on in the background as well that Keith didn't talk about in his prepared remarks, but is important. We have completed some very high rate wells like the Dakota well, the 9D well that we put on a little over a year ago; I think it went on in April of 2007. That well came on at over 8 million cubic feet a day, today it's declined down to a measly 4 million cubic feet a day. It's half of the gross production and that makes an impact when you amortize this over a quarter. That's not an insignificant volume.

The other thing that we have going on in the background that's important from a quarter-to-quarter analysis from the first quarter to the second quarter is, in the southern Uinta Basin we have a very high rate of well that IPed at over 14 million cubic feet a day. That reached payout and we cease to receive a 100% of the production volumes and reverted down to or went to the post payout working interest of about 33%, so a big apparent decline but one that's related to payout on a well and not performance on individual wells.

So a couple of other data points that are going on in the background at the well level which on a normal well you would never see but because these wells are high rate, it does make a difference in gross production and net production.

Finally on the Rockies express hydro testing, as a producer, we're aware of the hydro testing that's going to occur in September. There is information posting out on Rex's website that talks about the anticipated duration. Obviously it's going to take a bunch of capacity off line, and will cause problems similar to the problems we saw last year during several unscheduled pipeline outages that impacted rig and some of the other pipes that's in the region.

We have obviously, a large portion of our Rockies production hedged, so we have the ability to receive revenues on those volumes from the hedge positions. In addition, we've got some firm transport on other pipelines that leave the region which will help cushion some of the volumes. And we sell a lot of our daily or our physical gas into first of the month markets to buyers that hold firm capacity on other pipes that are leaving the regions to the Northwest and to the West.

So that coupled with our storage positions at Clear Creek and Clay Basin, we're not overly concerned although obviously when you take that much take away capacity out of the market, it is going to have an impact on spot prices at Ocala and the other sales points in the region.

Sam Brothwell - Wachovia

Okay. Do you anticipate at this point shutting anything in?

Chuck Stanley

Sam, we will behave rationally from an economic standpoint. If we can shut in our equity production and buy gas as we have in the past to fill our monthly commitments and to inject into storage at pennies on the dollar of course we'll do that.

Sam Brothwell - Wachovia

Okay. Well thanks very much, Chuck.

Chuck Stanley

Sure.

Operator

Your next question comes from the line of [Joe Almond] with JPMorgan.

Nick Pope - JPMorgan

It is actually Nick Pope, good morning.

Chuck Stanley

Good morning.

Nick Pope - JPMorgan

A couple quick questions here. I was hoping you could expand a little more. You talked about steel costs, we're seeing going up. I was curious what the availability looks like, what kind of lead times I guess you all are seeing with steel for drilling?

Keith Rattie

We're looking at the typical sort of lead times for OCTG. We're ordering pipe for next summer and scheduling deliveries. We've been doing that now for a couple of months so and we're a year out on our pipe orders. Our supply side, for certain diameters and certain wall thicknesses, yes. Are we having trouble, no, we have not had trouble to-date. I think it takes a while for the Mills to react to demand and to roll supply. The key is keeping ahead of it.

Nick Pope - JPMorgan

I guess continuing on that, with the thoughts on the build out I guess needed in the Uinta basin with some of these gathering systems, do you have any concern there or is that all working in conjunction with getting the steel, getting the equipment and getting the BLM to approve right away?

Chuck Stanley

First comes the right away. Until we have the right away, we can't contract with a construction company to install the pipe. The availability of line pipe and the size is that we need for this gathering system have not been a problem to date, but we have to have a right of way before we can commence any contracting.

Nick Pope - JPMorgan

So what do you think like in terms of just timing once you have BLM approval like to really start to see a ramp up in that big capacity in the Uinta?

Chuck Stanley

These are relatively short. When I say short, I am talking about five or six-mile lines. Interestingly in the Uinta basin, we're discouraged from burying the lines, so they're just welded up and laid on the surface. Their lays immediately adjacent to existing lines, so we know where we want to put them, we've modeled the system. So the physical installation is not that difficult. It is just the timing of identifying a contractor and getting that contractor mobilized.

Most of these folks as you can imagine are already engaged in projects so we have to work for a window in one of these construction company's schedules to mobilize them, so it is hard to guess. After we have a permit in hand it may take another 60 or 90 days to find a contractor.

Nick Pope - JPMorgan

Okay. I will get off the steel for now. I guess real quick, in Haynesville, have you all actually drilled into the Hayesville any of the wells that you have in North Louisiana at this point? Do you have data at this point?

Chuck Stanley

Yes and no. A deep well was drilled on the Woodardville acreage. If you look on our IR slides, on the Haynesville slide, it actually shows the deep control. You can see, I can't remember what color dots we have, thumbing through it to try to find it here. The deep well control is shown in kind of a chocolate brown color, and if you look on the Woodardville acreage block which is in township 15 North, Range 9 West, you will see a brown dot there. That well was drilled by the predecessor company that owned that acreage about two years or two-and-a-half years ago.

So we've got a very recent set of logs. Unfortunately, they didn't core the Haynesville because at that time it wasn't a horizon that had been identified as being interesting. More recently Petrohawk completed a well up in township 16 North, Range 11 West. That well IPed at about 16.8 million cubic feet a day, it was a horizontal lateral. And as I've mentioned earlier in response to one of other questions, our acreage surrounds that well on three sides.

So we have a direct offset to that horizontal well. So a very close by data point up in our Elm Grove area. In addition to that there is a number of vertical wells and a handful of horizontal wells to the west of our acreage, primarily operated by (inaudible). And then due south of Woodardville, several vertical wells drilled by EnCana and one recent horizontal well with some limited production data available.

Nick Pope - JPMorgan

Okay. Do you know what the royalty is on an average on this acreage in Haynesville?

Chuck Stanley

We think that on average and this is inclusive both our legacy stuff that goes back pre-Haynesville boom, and then our more recently acquired acreage, our average NRI is about 78% on a 100% working interest basis.

Nick Pope - JPMorgan

Got it.

Chuck Stanley

Our quarter royalty on the new stuff got better than quarter, less than a quarter royalty on the older stuff.

Nick Pope - JPMorgan

That is all I had. Thanks, guys.

Chuck Stanley

Thanks.

Operator

Your next question comes from the line of Carl Kirst with BMO capital.

Carl Kirst - BMO Capital

Hey good morning, everybody. Most of my questions have been hit but just a couple of follow-ups if I could.. Chuck, just on the Uinta, say if we actually just went full stock, just trying to get an idea of what the decline rates are on the shallow part of the Uinta, what would be the year-over-year decline if, say for instance, we stopped the deep drilling?

Chuck Stanley

In the order, I can't tell you that number right off the top of my head, an exact number but my guess is 25%.

Carl Kirst - BMO Capital

Okay, okay.

Chuck Stanley

I can't tell you the exact number but over 800 shallow producing wells out there including our oil production. So it's a large number of low rate wells, a lot of them are older so they piped out', they are in the exponential part of the decline curve. So those old wells have 8% sort of average decline rate, but there are a large number of wells that have been drilled in the past three or four years that are still in the hyperbolic part of their decline, and those wells are driving a steep first-year decline if we shut-off all the drilling out there, 25% is probably a good number.

Carl Kirst - BMO Capital

Okay. Just trying to get a rough ZIP code', that's helpful. If we got to a decision point where because we aren't growing bottom-line production, where could possibly one or two of those rigs be relocated to?

Chuck Stanley

That's a perfect softball. Thank you for throwing that to me. If something I failed to mention in one of the earlier comments, ironically, if we were to sit down and design a rig, the same rig that we would design to drill a Pinedale also drills deep wells in the Uinta. It also drills horizontal wells in the Bakken; it drills horizontal wells in the Haynesville and in the Cotton Valley section. It drills horizontal wells in the Woodward shale and it drills deep Morrow, Granite Wash Atoka wells in the Texas Panhandle.

So fortuitously, we have in our control contractually, a number of rigs that we can move around to seek the highest returns, the highest cash margins and the highest book margins and portfolio of drilling opportunities that are not just limited to the Rockies and not just limed to natural gas but also include oil and include a substantial inventory of Midcontinent drilling locations. So the mobility of our drilling rigs and the ability to chase returns and chase margin is fortuitous but very fortunate.

Carl Kirst - BMO Capital

And I guess with the delays of the BLM, presumably, we'll probably be making decision then on mobilizing sooner rather than later then?

Chuck Stanley

I think what you heard Keith saying is that, we're going to allocate capital to places that generate the highest margins.

Carl Kirst - BMO Capital

Perfect.

Chuck Stanley

The good news is, we have the ultimate inflexibility just fortuitously because of the sort of universal size of the rigs that we control.

Carl Kirst - BMO Capital

Right. Let me ask, just from a 30,000 foot standpoint as we look at the Midcontinent, the acquisition going from 50 million a day to maybe 35 million a day in the second quarter and now that's kind of starting to turn back, we had some Haynesville on top. It seems like we're going to be getting a lot more growth out of the Midcontinent, hopefully. As you look to support the total production for the year, the 166 Bcf to 169 Bcf, can you run us through what you think a potential exit rate by segment would be?

Chuck Stanley

I don't have that data with me, and frankly it takes us to a level of granularity I am not sure I am ready to go to, but we made obviously certain assumptions on reallocation of capital, and we've given you some color. I think we said in conjunction with the acquisition in Northwest, Louisiana, we anticipated about 12 Bcf equivalent of production and remember there is a stub period in there basically that's from the 29th of February forward.

We are also cognizant of what's going on in the Rockies with respect to take away capacity and pricing and are obviously continually looking at our cash margins and book margins in each of these plays, and we're going to allocate accordingly.

I don't feel comfortable giving you area by area exit rates at this point, but I think you can see what's happened in the second quarter with the profound shift in our production volumes toward the Midcontinent, and I think we have the ability to continue to drive that shift and outside of Pinedale the margins in our Midcontinent properties are more attractive than those in the remainder of our Rockies portfolio.

Carl Kirst - BMO Capital

Fair enough. And last question, I will just kind of throw this out to the group. It is more of a mid-stream question here, Keith, you had made comments certainly about possible expansion in Pinedale, etcetera. Do you feel comfortable throwing out on sort of a growth basis the dollar range of opportunities that perhaps we're assessing, just from a pure evaluation standpoint? And then two, very strong processing margins, here recently, embedded into your 3.50, 3.60 EPS forecast, I am curious what you're assuming for processing spreads for the second half of this year? Thank you.

Keith Rattie

I will pitch that over to Chuck since his guys are the ones that are looking at these projects, and we haven't run them through our internal investment review process yet, but I'll let Chuck answer both of those.

Chuck Stanley

Carl, a lot of the mid-stream investment opportunities are being driven by growth in the Pinedale production volume, so this summer we're constructing a 30 inch gathering line which will bring gas from Pinedale down to our gas processing facilities with the ramp up in production volumes from Pinedale, which by the way, that's a $180 million capital project.

The important thing to remember there is that we have the Northern third of the Pinedale Anticline which is second largest gas field in the US dedicated for life for the business. So, a very clear connection between growth in Pinedale and growth in volumes and therefore revenues in our mid-stream business from Pinedale.

Obviously as production volumes grow we will out strip our existing processing capacity to handle the raw gas volumes coming out of Pinedale which will necessitate construction of 600 million or 700 million cubic feet a day additional gas processing capacity in our Blacks Fork complex or near our Blacks Fork complex. That's a late 2010 early 2011 project. We're still looking at processing economics to determine whether or not we want to build a deep cut Cryo facility which will remove the [ethane] from the gas stream or whether we want to do basically build a what I would call a trim plant to basically remove enough NGLs from the gas to meet pipeline due point specs.

That decision is driven largely by your view of forward frac spreads and gets to your second question which is what are we using in guidance for frac spreads we tend to not use the forward strip but rather to use sort of an historic five-year frac spread look when we're giving guidance, and that's what we've done on our guidance that we gave with the update.

The forward frac spread is obviously being dramatically impacted by the basis widening that we've seen here in the Rockies and events like the hydro testing of fracs will have an immediate impact on at least a partial month's volume of gas that's being shut in or that's going to have a widening impact on frac spread economics.

Let me just back up for a minute. There is a gas processing plant opportunity that would be a fairly substantial capital investment. We're right now doing engineering on the two plant alternatives for the expansion at Blacks Fork anywhere from 150 million to over 300 million of gross capital required in the range of plant designs.

In addition in the Uinta basin we have ongoing demands from ourselves and from third parties for additional processing capacities. We're starting up our stage coach processing plant should be online early next month. The customers for that plant are all third parties, and they're already clamoring for more processing capacity. This time they want deep processing, it's a fee-based deal, they will pay a fee which will generate an acceptable return on invested capital, and keep the liquids that are extracted from the gas on so there are several projects like that on the books with commercial negotiations under way and engineering under way to expand our processing capacity in the Uinta basin.

Beyond that, again we see continued growth in our core gathering and processing areas that should help propel. Every time I stand up and I say, well, we can't promise the 40 plus percent growth that we've seen out of our midstream business and they keep delivering on that year-over-year, but I think you should look long-term at organic production growth coming out of the Rockies in the regions that we operate midstream gathering and processing services and use that as a more realistic projection for future investment and future production and processing gathering revenue growth.

Carl Kirst - BMO Capital

Great. Well, thank you, guys very much for your time.

Keith Rattie

Thanks, Carl.

Operator

Your next question comes from the line of [Winfred Ruha] with Ruha Consulting Limited.

Winfred Ruha - Ruha Consulting Limited.

My question has been answered.

Keith Rattie

Thanks, Winfred.

Winfred Ruha - Ruha Consulting Limited.

Thank you.

Operator

Your next question is from Becka Followill with Tudor Pickering.

Becka Followill - Tudor Pickering

Hi. Just going back to the Haynesville, how much did your acreage expires or is not held by production in '08 and '09?

Chuck Stanley

Becka, I don't have a schedule with me. About two-thirds of our acreage is held by production and third is term lease, very small percentage of it expires this year, and obviously that's where we're focused on drilling today, and then there is not a lot that expires in 2009. The majority of it expires in 2010 and 2011, and I am going to guess that that number is 80% and 2010, 2011, 20% in '08 and '09.

Becka Followill - Tudor Pickering

Okay. And then on pipeline capacity, did you guys have firm capacity out of the Haynesville, North Louisiana area, pipeline capacity?

Chuck Stanley

We do, although long-term the key is going to be more long haul capacity out of the greater Northwest Louisiana region either to interconnect with markets in the southeastern US or enhanced capacity going north out of Perryville into the eastern sea board and Northeastern markets because ultimately in the production volumes grow as some predict they will, there is a fundamental lack of capacity in that region, especially when you factor in the amount of gas that's migrating from North Texas over into the Northwest Louisiana region from the ongoing Barnett Shale development.

Becka Followill - Tudor Pickering

How much firm capacity do you guys have?

Chuck Stanley

I would rather not talk about the exact numbers.

Becka Followill - Tudor Pickering

Okay and then on the Uinta, have you guys filed to build that new pipeline from the gathering line?

Chuck Stanley

We've had permits into the BLM for quite a while.

Becka Followill - Tudor Pickering

Like more than six months?

Chuck Stanley

Some of them yes. Some of those have been in the hopper for at least six months. Some of the more recent permits have only been in for a month or two.

Becka Followill - Tudor Pickering

Okay. And then finally on the cost side, I know it is across the board that we're seeing increased steel costs, diesel costs, but what about other services? Are you guys starting to see cost pressure there after them easing off a little bit in '07?

Chuck Stanley

The answer is yes. Obviously with the introduction of a couple of new plays, the Haynesville, the Bakken, and ramp up in activity there being driven apart by lease expiry response, there is a grab for rigs which has resulted in a shift in pricing pressure back to the drilling contractors. In addition, we anticipate the future although we haven't seen it yet increased pressure on pressure pumping services and products as you know these horizontal wells are stimulation friendly, multiple frac stages, a lots of profit and lots of pumping service.

Becka Followill - Tudor Pickering

Are you guys changing your CapEx budgets at this point for '08? Any change?

Chuck Stanley

There may be some minor changes but nothing dramatic and we've anticipated the sort of increased well costs in our current capital forecast, the changes that would come in capital budget would be as a result of drilling more wells or additional interest in existing wells that we forecasted to drill.

Becka Followill - Tudor Pickering

Thank you, guys.

Keith Rattie

Thanks, Becka.

Operator

Your next question is from the line of Faisel Khan with Citigroup.

Faisel Khan - Citigroup

Quick question. In your press release you talked about higher LOE related to increased water disposal costs and increased well work over activity. Is that something we should continue to see going forward on those latter two points?

Chuck Stanley

Faisel, that's a good question. This is Chuck. The fundamental change is that we added roughly 50 million a day production in Northwest, Louisiana and any place that we add production outside of Pinedale will have an increase in LOE because Pinedale LOE is one of the lowest in the country. So added production in Northwest Louisiana where we do deal with a lot of produced water and the original operators there had a limited water disposal system in place which resulted in a spike up instantaneously in LOE. Over time we'll work on building a water gathering and water disposal infrastructure which will help reduce that LOE, but in general we'll see a higher LOE as we shift to higher production mix from Midcontinent on a go-forward basis.

Faisel Khan - Citigroup

Okay. Great. Thanks for the time, guys.

Operator

Your next question is a follow-up from Robert Christanson with Buckingham Research.

Robert Christanson - Buckingham Research

It wasn't too long ago, I think about a year ago that you all shut in some natural gas with oil and gas prices deteriorating pretty quickly here as of late. Any consideration of that? Your costs have risen, I know we're still a couple bucks above where we were a year ago, but your costs have risen too, so is there any consideration of that happening?

Chuck Stanley

Bob, this is Chuck. Gas prices today, I don't have a quote this morning.

Robert Christanson - Buckingham Research

They are up $0.20

Chuck Stanley

$6 higher than they were when we shut in gas last year. We shut in gas last year in certain days we saw Rockies prices near zero when you factored in gathering. As I said in response to an earlier question we will behave in an economically rational sense. We won't give our gas away. In a situation where we have first of the month firm commitments, if we can shut in our equity production and buy gas for a few pennies and deliver it and even sell it for a couple of dollars, we'll take the cash margin and take the additional revenues from our hedge positions. The other thing that we have that is unique compared to other producers is in storage capacity in both Clear Creek and our Clay Basin the storage fields in the region which will allow us to part gas temporarily in storage.

Keith Rattie

Bob, when you added all up, roughly 80% of our production hedged for the second half, firm transport on current river and other pipes, firm storage rights in two facilities, Clay Basin inventory is below its five-year average today. We've got some flexibility, but we will curtail if prices fall to a level that make it inappropriate to sell our gas.

Robert Christanson - Buckingham Research

What level is that? Here we said it's a $7.

Chuck Stanley

Actually $6 for the remainder of the year was the quote we got yesterday, current forward strip for the next five months.

Robert Christanson - Buckingham Research

So it's pretty low?

Keith Rattie

$6, we make lots of money at, $6.

Chuck Stanley

We make money at $6, that's in the Rockies.

Robert Christanson - Buckingham Research

Okay.

Chuck Stanley

Rockies' margins are still solid at $6.

Robert Christanson - Buckingham Research

Okay. Thank you

Operator

Your next question is from the line of David Hemron with Wachovia.

David Hemron - Wachovia

Good morning everyone. Two part question. I don't know who wants to take this but maybe Chuck. What level do you shut in and what level of gas prices do you start reducing your CapEx? Maybe that's a better way to put it and likewise what do you think the marginal cost of supply is for the industry as a whole?

Chuck Stanley

Those are interesting questions. One, on the first one, it is an area by area basis. So if we look at our highest cost producing area, it is Uinta Basin. Typically the Uinta Basin has the lowest well head netbacks just because of its geographic position with respect to the interstate pipeline network and then regionally, it's about as far as you can get from the collective national burner tip, so tends to have the lowest netbacks. So, when you see the highest costs coupled with the lowest netbacks that would be the area that we would first look at reallocating capital. I think we've already talked about that extensively, so I won't re-gorge to take that logic.

More recently in the Rockies we'll be looking at fundamental macro information, pipeline receipts, and our marketing folks can feel the tightness in the market on the day market as capacity gets tight, and we'll start to look at moving rigs and allocating capital to other parts of our portfolio where we don't have those problems, the Midcontinent or the focus toward the Bakken oil development.

So we have in our portfolio the ability to respond in real-time to pricing signals that are directly related to tightness in transportation, and move dollars around from one area to another. So, I wouldn't say we'll stop drilling across the company, we'll just reallocate to higher margins and higher netback areas, and we're fortunate we have a portfolio that allows us to do that. And as I mentioned, just as a matter of coincidence, a fleet of rigs which fit very well across other opportunities that allow us to keep deploying capital and generating acceptable returns.

Keith Rattie

Just to put some numbers on that current quote for second half, gas delivered into Center Point, which of course is relevant to our Northwest Louisiana activities about $8. You can look on our release, our average cash costs of production in the last quarter was about 2.30 in Mcf equivalent, of course that number moves up and down as price moves up and down because of the production tax component.

So, partly respond to the previous question from Bob, those are still very strong cash margins in the Midcontinent. Now in the Rockies, Pinedale is our lowest cost field and as volumes declined over the first half, they're going to kick-in in the second half. We brought 36 winter wells online so far, we've got another dozen or so waiting on completion. Pinedale cash operating costs are quite low and cash margins are quite good even at the current forward strip of about $6.

David Hemron - Wachovia

Okay. So, I am going to have hard time pinning you down on gas price, and I have a question and want to volunteer one, and if you want to volunteer one, that's great. And the second part is, any take on or any quick opinion on what the overall industry natural gas price level is before you start seeing a reduction in CapEx?

Keith Rattie

Our official view of prices is the current forward curve. We obviously have an internal view, but it would be inappropriate for to us publicly state what that view is. Let me just say that from a fundamental point of view, as we look at the current costs of development in each of the major resource plays in the US, it certainly appears that the typical producer today needs a price at the Henry Hub close to $9 to be able to earn a cost of capital type return. Now that's an average, early entrance into these plays obviously have threshold that are lower than that, late entrance probably have thresholds that are higher than that. What does all that mean with prices where they are today? Most producers are still likely to drill ahead but any further weakness in prices, and I think we're going to see as slight response.

David Hemron - Wachovia

Okay, I'd appreciate it. Thanks.

Operator

And your final question comes from the line of Rick Gross with Lehman.

Rick Gross - Lehman Brothers

Finally, made it, good morning. I've got just a couple of quick questions on cost, and that is with costs escalating. Is this escalation similar in each of the areas or are there pockets where it's escalating faster in some areas where it's materially slower?

Chuck Stanley

That's a good question, I'm not sure I can answer it accurately. I think Rick, that in general the cost escalation is pretty uniform on a percentage of well cost basis because the inputs are what I would call sort of national level or international level commodity input, diesel, steel, cement, profit, all of those things tend to translate into our uniform percentage increase in costs across our entire drilling inventory.

Are there localized phenomenon such as the Haynesville brush? Yeah, it is certainly tightening the rig market and tightening the services in that area and it will take a while for the service industry to respond, but that tightening in the local rig market is having a broad macro impact on the entire US billing fleet of similarly sized rigs, so 1,500 horsepower rigs across the universe of the drilling fleet are feeling that demand input in Northwest Louisiana.

Rick Gross - Lehman Brothers

Okay. In the Uinta, we're going to shoot a seismic grid to see if you could better discern targets in the Dakota.

Chuck Stanley

Right.

Rick Gross - Lehman Brothers

Where are you in the collection in interpretation of that data, and then as you indicated you have some potential, we'll call it, drilling restriction of high productivity wells until you get your gathering in place. Is there anything about where you surmise some of these better targets may be off the original, off the data you're seeing that could delay this or are you going to be able to just go ahead and if you find these anomalies, high grade your projects and kind of go after them?

Chuck Stanley

The answer to the first question is we haven't initiated acquisition. We're waiting on permitting from the BLM. Part of this will be, we will now push the acquisition processing interpretation of the part of survey into next year because we won't get it all acquired before the winter given the delays in permitting. The first segment that we acquire will be over in the western part of our large block of acreage, and it is deliberately targeted there because that's the area where we've seen the very attractive production rates from the Dakota.

But it will be early next year before we had any data available that would allow to us hi-grade Dakota locations. In the meantime we're going to be working on getting this gathering system resolved so that when we do get the data interpreted it won't gathering system model next will not be an issue any more.

Rick Gross - Lehman Brothers

Okay. And then one last not related question which is, if you are successful in one of these big inch pipes, in pipeline area, is it possible you could do some off balance sheet project financing directly related to that to keep it separate from coming on the balance sheet in a period of time where you're spending on drilling and gathering and etcetera?

Keith Rattie

The answer is yes, Rick. We're not going to cannibalize our opportunity to invest in what we still consider to be a very attractive and growing inventory of development opportunities in our E&P business. But a good project supported by long-term projects contracts consistent with the strategy, we described opens up a number of financing opportunities including the possibility as we discussed in the past we might drop over thrust into an MLP and use the proceeds from that to help fund our equity investment in the major project.

Rick Gross - Lehman Brothers

Okay. Great. Thank you.

Keith Rattie

I think the point I will stress is we will not undermine our ability to allocate capital to our E&P business. We continue to believe that our best risk adjusted returns will come from reinvestment in our market resources group and that includes not just Questar E&P but Wexpro and gas management.

Operator

And there are no further questions at this time.

Keith Rattie

Well, thank you all, for your participation in our call today. We'll have all of this information posted on our website at questar.com, and you have information on that website to how to get a hold of us if you have any other follow-up questions.

Operator

Thank you for participating in today's second quarter 2008 earnings release conference call. This call will be available for replay beginning at 10:30 am Eastern Standard Time today through 11:59 pm Eastern Standard Time on Thursday July 31st, 2008. The conference ID number for the replay is 30563544. And the number to dial for the replay is 1-800-642-1687 or 1706-645-9291.

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