Questar Corporation Q3 2008 Earnings Call Transcript

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Questar Corporation (NYSE:STR) Q3 2008 Earnings Call October 30, 2008 9:00 AM ET

Executives

Stephen E. Parks – Chief Financial Officer & Senior Vice President

Keith O. Rattie – Chairman of the Board, President & Chief Executive Officer

Charles B. Stanley – Chief Operating Officer, Executive Vice President & Director

R. Allan Bradley – Senior Vice President; President, Chief Executive Officer & Chief Operating Officer Questar Pipeline, Co.

Ronald W. Jibson – Senior Vice President; Executive Vice President of Questar Gas

Analysts

Faisel Khan – Citigroup

Adam Wise – John Hancock Financial

Samuel Brothwell – Wachovia Securities

[Winfred Fruhab – WB Fruhab Consulting]

Carl Kirst – BMO Capital Markets

Holly Stewart – Howard Weil, Inc.

Rebecca Followill – Tudor Pickering & Co. Securities

Brian Singer – Goldman Sachs

Analyst for Samuel Brothwell – Wachovia Securities

[Shanere Garshuny]

Operator

My name is Andrew and I will be your conference operator today. At this time I would like to welcome everyone to the Questar Corporation third quarter 2008 earnings release conference call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks there will be a question and answer session. (Operator Instructions) It is now my pleasure to introduce Mr. Stephen Parks, Senior Vice President and Chief Financial Officer.

Stephen E. Parks

Welcome to Questar’s third quarter 2008 conference call. I’ll briefly summarize our strong financial position and results for the third quarter 2008 and then I’ll turn the microphone over to Keith Rattie, our Chairman and CEO. Keith will provide more color on our third quarter results, update earnings and production guidance for 2008 and introduce initial guidance for 2009. After Keith we’ll invite your questions.

Other members of Questar’s management team are here today to answer your questions including Chuck Stanley, President and CEO of Questar Market Resources, Allan Bradley, President and CEO of Questar Pipeline and Ron Jibson, President and CEO of Questar Gas. Our remarks this morning will contain forward-looking statements about future operations and our expectation of Questar Corporation.

We make these statements in good faith. We believe they are reasonable representations of the company’s expected performance at this time but actual results of course, may vary significantly from our current expectations and projections due to a variety of factors that are described in our Form 10K filings with the SEC. Let’s start with our strong financial position. Questar’s combined short and long term debt was 40% of total capital at September 30, 2008. The company has $365 million of short term lines of credit available to support our commercial paper program.

We have $79 million in commercial paper outstanding this morning. In addition market resources currently has unused capacity of $475 million under a long term revolving credit facility. We believe we have sufficient liquidity to support our operating and capital investment plans through the end of 2009. Now, here’s a short summary of our third quarter 2008 results. Questar’s third quarter 2008 results exceeded expectations with net income of $204.2 million or $1.16 per diluted share. That’s up 80% over a year ago.

Net income a year ago was $113.3 million or $0.64 per share. We now expect 2008 net income to range from $3.70 to $3.80 per diluted share. Please remember that our guidance excludes asset sales and mark-to-market gains and losses from hedges. Questar’s third quarter results include before tax net gains from assets sales of $59 million compared to a loss of $200,000 a year ago. Questar E&P sold non-core producing assets for $92.2 million in the 2008 quarter resulting in a pre-tax gain of $58.7 million and a net after tax gain of $36.5 million.

Net mark-to-market losses on basis only swaps decreased net income $14 million in the 2008 quarter compared to a gain of $5.6 million in the year earlier period. Our market resources subsidiary once again led the way growing net income 82% to $197.6 million in third quarter 2008. All four market resources business units: Questar E&P; Wexpro; Gas Management; and Energy Trading delivered double digit net income growth.

Questar E&P grew net income 92% to $146.8 million with production increasing 34% to 45.3 BCFE. Realized prices for natural gas, crude oil and NGL increased 23% more than offsetting an increase in average production costs. Wexpro grew net income 38% driving by a 32% increase in investment base for the past 12 months. Gas Management grew net income 84% driven by higher gathering and processing margins. Net income for Energy Trading increased 40% to $5.9 million as a result of increased marketing margins.

Questar Pipeline, our interstate pipeline and storage business earned $15.4 million in third quarter 2008, up 28% from 2007. The increase was driven by high transportation revenues from expansion projects completed in fourth quarter 2007. Questar Gas, our retail gas distribution utility reported a seasonal third quarter of 2008 net loss of $.8 million compared to a loss of $8.5 million a year ago. A higher gross margin was driven by new customer additions but was offset by higher operating, maintenance and interest expenses in the quarter.

Questar Gas now services 808,100 homes and businesses, up 2.2% from the year ago. For more details on third quarter 2008 results you can find our earnings release and the latest version of our investor relations presentation on the Questar website at www.Questar.com. Now, I’ll turn the microphone over to Keith Rattie, Questar Chairman and CEO.

Keith O. Rattie

We’ve got of ground to cover this morning. First, to say it’s been a tough quarter for Questar shareholders would be an understatement. Our stock as you know, is down 45% year-to-date. Let me try to put this in to historical context, Questar’s stock recently traded at levels we haven’t seen since 2004 even though Questar’s net income has tripled so far. Questar E&P production today is about 65% higher than it was back in ’04. Questar E&P proved reserves are about 50% higher today than at year-end ’04.

Wexpro net income is double, Gas Management’s net income is nearly quadrupled, Questar Pipeline’s net income has more than doubled and our balance sheet is stronger than it was back in 2004. Yes, natural gas and oil prices have fallen substantially over the last several months and costs are up but the forward curves for natural gas and oil today are higher than they were back in ’04. What’s more, roughly 40% of our forecast 2009 net income and cash flow comes from businesses that are not materially sensitive to falling natural gas prices and about 70% of forecast 2009 Questar E&P production is hedged at prices well above current levels.

So, when you do the arithmetic only about 20% of our forecast 2009 cash flow from operations is exposed to possible further declines in the price of natural gas. So, what’s wrong with the picture? Obviously, it’s not too look backwards but what lies ahead that matters to investors so I’ll keep my comments this morning on our third quarter results brief and focus instead on how we’re adjusting and how we intend to manage our business through what could be a tough year for the US economy and the natural gas industry.

We did, as Steve has summarized, have by far the best third quarter in Questar history. As he noted despite natural gas prices in the Rockies, we grew net income 80% compared to a year ago. Questar E&P grew natural gas and oil equivalent production 34% in the quarter. Please note we produced a record 45.3 billion cubic feet equivalent in the quarter, that’s just below 500 million cubic feet a day. In fact, Questar E&P daily production has since topped the 500 million cubic feet equivalent per day net level for the first time.

We grew a midcontinent production 42%. The midcontinent now contributes about 40% of Questar E&P production. Questar E&P controllable production costs, that includes production taxes that of course are tied to product prices, our controllable production cost declined from $3.42 per MCF equivalent in the second quarter to $3.17 per MCFE in the third quarter and that’s a trend we of course we hope will continue. Steve noted Wexpro, our second E&P company grew net income 38% from a year ago.

Wexpro produced a record 12.2 billion cubic feet equivalent in the quarter on behalf of the utility Questar Gas. Our gathering and processing company Gas Management grew net income 84% from a year ago. That was driven by higher processing and gathering margins and Questar pipeline kicked in, our pipeline team grew net income 28% in the quarter driven by the expansions we completed last year.

Today with over 80% of Questar E&P’s fourth quarter gas and oil equivalent production hedge, as Steve noted, we now expect Questar consolidated net income to range from $3.70 to $3.80 per diluted share. In 2009 that compares to our prior guidance of $3.50 to $3.60 per diluted share. Also note that earlier this week our board approved an increase in our dividend from $0.49 to $0.50 per share per year. So, let me turn now to 2009, as we announced in our October 15th release we’re responding to lower commodity prices and tight credit markets by reducing capital spending next year to a level that’s consistent with cash flow from operations plus available capacity on our existing credit facilities.

Earlier this week the Questar board of directors approved our 2009 plan, let me give you the highlights. First, we plan to reduce cap ex from $2.6 billion in 2008 to about $1.6 billion in ’09. Please note our ’08 capital program included E&P property acquisitions totaling about $700 million. If you exclude those we’re reducing 2009 cap ex by about $300 million.

We’re going to allocate that $1.6 billion capital program as follows: to Questar E&P $1.05 billion that’s down from the $1.9 billion with the acquisitions this year; Wexpro $140 million next year, that’s up from $135 million in ’08; Gas Management $200 million next year, that’s down from $400 million in ’08; Questar Pipeline $107 million flat with ’08; and Questar Gas $90 million, that’s down from $136 million this year.

Despite, and please note despite lower capital expenditures next year we expect Questar E&P production to grow by 10% to 15% from 167 BCFE to 169 BCFE in 2008 to 185 BCFE to 193 BCFE net year. As Steve noted we estimate that Questar 2009 EPS may range from $3.05 to $3.25 per share. That’s down about 15% from 2008 and it excludes the one-time items. Please note that this guidance assumes realized prices on unhedged production that may be more conservative than many of the analysts who follow our industry are modeling for next year.

Also, we’re modeling a flower Frac spread and thus lower earnings in our processing business. Please see the table in our release for the key assumptions. Again, I’ll repeat about 70% of Questar E&P forecast 2009 production is hedged at prices well above the current forward strip. In fact, to quantify that the mark-to-market on our hedge book today is about $400 million. That’s up about $900 million since the end of the second quarter. Now, historically investors have thought of Questar E&P as primarily a Rockies producer but our ’09 plan showcases the flexibility that we now have with our multi basin E&P asset base.

Because we’re expecting Rockies basis to remain wide for the next couple of summers, we’re going to shift capital from the Rockies to the midcontinent. Next dale Pinedale will cut back from 12 to nine rigs. With nine rigs in year round drilling under the current BLM record of decision, we still expect to complete 93 to 95 wells at Pinedale next year. That’s up from 78 to 80 wells in 2008. As you all know, Pinedale is the lowest cost per MCF equivalent play in the Rockies. In fact, it may be the only major play in the Rockies with acceptable returns at current forward prices and current costs.

Even with the slower ramp up at Pinedale, we still expect solid production growth from our Pinedale play next year. I’d also like to remind you that Pinedale is a triple play for us. Questar E&P, Wexpro and Gas Management all participate. Questar E&P will invest about $360 million next year at Pinedale, Wexpro will invest about $70 million at Pinedale next year. As you know Wexpro returns in cash flow are not sensitive to commodity prices and you also know that under the Wexpro agreement Wexpro earns a 19% to 20% after tax unlevered return on its net investment base.

Over the next five years we now plan to invest about $800 million in Wexpro and about 60% of that will be at Pinedale. Wexpro’s net investment base and therefore net income could double by 2013. Also, 100% of Questar operated production is dedicated to our gathering and processing business at Pinedale. Pinedale is an investment trifecta for Questar shareholders. Now, please note in 2009 we plan to suspend all gas directed drilling in both our Unita basin and legacy divisions.

Now, this is a tough decision for us because our technical team has done its job and our deep gas play in the Unita basin is working. Over the past few months we’ve turned several deep wells to sales with initial rates above 500 million cubic feet a day. But, given margins and returns at current Rockies prices and given our focus on returns, we’ve got better places to put capital to work in our diversified portfolio as we cut back to live within our cash flow.

We’ll get back out to the Unita deep play once we get better visibility on the timing of proposed new Rockies export pipelines, something I’ll comment on in a little bit. But, we will allocate capital for oil directed drilling in the Unita basin next year. We plan to drill at least 15 horizontal wells in the Green River formation. You may want to ask Chuck to explain that when we get to Q&A. Also in the Rockies, we’re going to shift our focus from gas to oil in our legacy division specifically to our 63,000 net acre leasehold in our North Dakota Bakken play.

Some good news this morning, we’ve spud our first Bakken well. We plan to drill at least six Questar operated Bakken wells next year. In total in 2009 we’re planning to reduce cap ex in the Unita and legacy divisions by 70% from 2008. We’re going to move capital from the midcontinent. We plan to drill our participate in at least 30 wells in the emerging Haynesville shale play in northwest Louisiana next year. Assuming we get the results we expect, we plan to ramp up from the three rigs we’re currently operating in this play to at least five rigs next year.

As you know, we have over 30,000 net acres in the Haynesville play and based on early well results reported by other operators, much of our acreage may be in the sweet spot of the play though we’re going to need to confirm this with both the drill bit and more production history on all the wells in the play. We currently have two Questar operated Haynesville horizontal wells drilled, cased and waiting on completion with frac dates scheduled in early November.

We’re also drilling ahead on our third and fourth Questar operated Haynesville wells and just a reminder, we’ve participated in one outside operated well that was completed and turned to sales in early August at an IP of over 20 million cubic feet a day. We also have interest in two additional outside operated wells, one waiting on completion and one drilling ahead. Also in northwest Louisiana we plan to drill about 80 Cotton Valley Hosston wells.

In the western midcontinent we plan to drill or participate in about 20 gross horizontal Woodford wells next year. So, let me just quickly summarize our capital plan for Questar E&P. We’re going to move capital in Questar E&P to where the margins and returns remain attractive at current forward prices. We’re shutting down all gas directed drilling in the Rockies except at Pinedale. At Pinedale we’ll cut back from 12 to nine rigs and we’ll allocate capital for oil directed drilling in the Unita basin and the Bakken.

We’re going to allocate more capital to our Haynesville and Cotton Valley Hosston plays in northwest Louisiana and our Woodford shale play in western Oklahoma. Please note that with these shifts in capital we forecast that over 75% of Questar E&P 2009 production will come from high margin properties in the midcontinent and Pinedale.

Let me turn to our gathering and processing business as record 2008 earnings show Gas Management’s processing business tends to be a natural hedge against low Rockies natural gas prices. Next year we’ll allocate capital to expand our [blacksporic] hub in anticipation of growing Pinedale volumes. We’ll also allocate capital to expand our Stagecoach processing plant in the Unita basin. This later project is underwritten by a long term contract with an unaffiliated producer.

Turning quickly to Questar Pipeline, our pipeline team’s role in our corporate strategy as you’ve heard us describe is to protect returns on capital in our Rockies E&P business and specifically to do that by identifying and eliminating pipeline bottlenecks. Today, that role matters more than ever. Northern Rockies production has grown from about 5.3 BCF a day back in 2003 to about 9 BCF a day today. That’s an average increase of over 500 million cubic feet per day per year.

Over the last five years three major Rockies export pipelines have been built and our pipeline team has played a role in all three by expanding our upstream pipelines to increase deliveries in to the new pipes. But by August this past summer all of those new pipes and all of the existing Rockies export pipes were essentially full. Simply put, Rockies production can’t continue to grow at anywhere near its historic rate until new export pipelines get built.

Now, the final leg of REX, to eastern Ohio will help. It will add about 300 million cubic feet a day of capacity about a year from now. The proposed Kern River expansion will help, it could add about 500 million cubic feet a day of export capacity in 2010 or 11. Trans Canada’s Bison project could add about 400 million cubic feet a day of capacity in late 2010 and El Paso’s proposed Ruby pipeline project could add over 1 BCF a day of capacity in 2011.

But, when we do the arithmetic even if all of these pipelines get built, our models show that Pinedale volume growth alone can fill them all. Even if all the other plays in the Rockies stay flat. In short, we need another major Rockies export by 2012. Based on our pipeline team’s discussions with Rockies producers, we’re convinced we need a 42 inch bullet from Wyoming to Chicago.

So, between now and the end of the year Questar Pipeline and our partner alliance will conduct a new open season on a revamped Rockies Alliance Pipeline Project or RAPP which will run from Wamsutter to the big and highly liquid [Joliette] hub near Chicago. In the open season we’re hoping to confirm or reconfirm the initial 500 million cubic feet a day of shippers support we received in the open season we held last May. We’re going to need another 800 million cubic feet a day of new shipper commitments to move forward with this project.

We also hope to finalize an agreement to bring another major pipeline company in to the project before we go out with that open season. Now, to underscore Questar’s commitment to this project, Questar E&P intends to make a significant capacity commitment during the open season. So, our message to other Rockies producers today is this, let’s fix the basis problem, help us get a new pipeline built to Chicago by 2012.

Finally, in 2009 we’ll allocate about $90 million to our utility Questar Gas to continue to serve customers safely and reliably and meet our obligations to connect new customers. That’s down from about $136 million in 2008. In summary, our 2009 plan highlights what we think is a strong suit for this company. We have the people, the assets, the flexibility and the discipline to move capital to where we get the highest risk adjusted returns. In Questar E&P that means allocating more capital to gas directed drilling at high margin properties including our Pinedale play and our midcontinent assets and to oil directed drilling in the Bakken and Green River formations.

It also means continued investment in our four other businesses: Wexpro; Gas Management; Questar Pipeline; and Questar Gas, all of which generate cash flow and earnings that are not materially sensitive to falling natural gas prices. I want to thank everybody for dialing in this morning and now we’ll open it for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from Faisel Khan – Citigroup.

Faisel Khan – Citigroup

A question on cap ex for next year, if we run the math on the cap ex for next year and your operating cash flows and you commodity price deck and you guys have said that you would probably tap some of your revolving credit capacity. In this market given the credit markets does it make sense to be that aggressive on the cap ex front? I guess, how much flexibility do you guys have on that front if you had to ramp it down?

Keith O. Rattie

Faisel, we think we have a lot of flexibility and we tend to manage this very carefully. Obviously, if prices fall further from current levels and it looks like our cash flow from operations is going to be less than what we expect, we clearly will adjust capital spending further. I want to make a couple of points though, we as I mentioned in the call, only about 20% from our cash flow from operations is really exposed to a falling natural gas drip, number one.

Number two, in the 2009 plan particularly in the E&P business Chuck and his team have assumed that cost remain flat with what we’ve seen and what in retrospect looks like an overheated market this year. I have a lot of confidence in the operational capability of our asset managers to find ways to cut our costs and we’re always seeing as a trend in the third quarter signal a downward movement in all the costs that ultimately aggregate up to well costs.

But, we’re going to manage this very carefully. We think we have sufficient liquidity to operate under this plan. The board and I and the management team focused extensively on that question in the board meetings we held earlier this week but as you’ve heard we do have the ability to adjust either downwards or upwards as market conditions dictate.

Faisel Khan – Citigroup

Then just on the Rockies export pipelines, if for whatever reason your proposal did not become the front runner for a new export pipeline to move gas east would you submit some of your E&P volumes to whatever the export pipeline was to move gas east?

Stephen E. Parks

Well, we think the right market for the east bound pipeline is straight to Chicago and we do think we are the front runner Faisel. We had over 500 million cubic feet a day of initial subscription in the open season but you’ll recall the original RAPP project was routed basically northeast out of the Rockies to interconnects on northern border and alliance pipeline. We heard from Rockies producers in the open season that they didn’t want to go to an intermediary delivery point, they wanted to go to a large liquid market, i.e. the [Joliette] hub in Chicago which delivers in to multiple pipelines that take gas into Canada and on to big markets in the upper Midwest.

The other project Trans Canada’s Pathfinder project has the same issue. It doesn’t take gas to a large market, you have multiple hauls and multiple large pipes to get to the markets. We think the best way to solve the Rockies basis problem is to build a bullet straight to Chicago and we’re getting positive feedback in early discussions we’re having in the marketplace.

Operator

Our next question comes from Adam Wise – John Hancock Financial.

Adam Wise – John Hancock Financial

I just wanted to ask a couple of quick questions, first the natural price deck you’re using currently in your budgeting, what is that?

Keith O. Rattie

We’re using a NYMEX strip of $6.50 to $7.50 next year but with adjusted for basis and there’s a table in our earnings release on page 4 that I’ll draw your attention to and this is important, we’re assuming that Rockies from $2.00 to $3.50 next year. That is the current Rockies basis is about $2.30 so it’s at the low end of that range.

We’re assuming that midcontinent basis, NYMEX to midcontinent basis differential ranges from $1.00 to $2.00 next year and I would point out that that’s roughly the current basis in the midcontinent is at the lower end of that range. So, in my prepared remarks I stressed that we think our guidance next year is based on realized prices when you adjust NYMEX for the basis of the regional pipes that we actually produce and deliver the gas in to, you come up with a net to the well price that is probably going to be quite a bit lower than what most of the analysts who are following our industry are currently assuming today.

Adam Wise – John Hancock Financial

Then using that $1.6 billion ’09 kind of estimate with that budget, what do you see as the amount outside of your operating cash flow would be that you’d need to finance that plan?

Keith O. Rattie


The plan shows a modest amount of incremental financing, Steve why don’t you give those numbers just quickly.

Stephen E. Parks

If our ability to predict actually comes to a resembled reality then we would expect that we’d need to borrow about $20 million is all net-net for the year. So, it’s essentially breakeven.

Operator

Our next question comes from Samuel Brothwell – Wachovia Securities.

Samuel Brothwell – Wachovia Securities

A couple of questions on the Rockies alliance pipeline, I think you alluded to possibly bringing in another pipeline operator as a partner. Did I hear you correctly on that?

Keith O. Rattie

Yes, we’d like to.

Samuel Brothwell – Wachovia Securities

This is going to be all virgin pipe straight to [Joliette], you’re not going to interconnect with anything else as you’ve got it planned now?

Keith O. Rattie

Why don’t I let Allan Bradley just give you a very quick overview of what the project configuration is going to be.

R. Allan Bradley

As you know it’s about 1,100 miles from Wamsutter to Chicago. When we say Chicago, we’re going to tie in just downstream from the [Oxsable] plant on Alliance and they have a very flexible header system that basically ties in to multiple interconnects in the Chicago area that can move gas both to LDCs in the midcontinent and also to other interstate pipelines that can take the gas east perhaps as far as Don’s storage. There’s a liquid market there and producers in the Rockies really like that. We will interconnect with existing pipelines as interest develops along that corridor.

So, we parallel REX to Cheyenne, we build straight across a new route over to basically Harper and then we sort of parallel the NPG line in to Chicago. If you kind of look at the synergies of that corridor its initial capacity as Keith said, 1.3 BCF a day, it’s expandable up to 1.7. We feel we have a very competitive rate now and when we look at that rate we want to make sure we minimize the variable component so we really capture the lowest possible fuel rate and try to build the most flexible line we can with that in mine, minimizing the variable costs.

Producers have given us a lot of encouragement to stay the course in this environment and that’s exactly what we intend to do.

Samuel Brothwell – Wachovia Securities

Do you think they’ll step up with either a longer term contractual commitment or capital or both? The producers I mean?

R. Allan Bradley

Right now if we expand the development team I think we have the initial momentum to carry the development in to a higher spend rate for ’09. That will depend on the results of the open season which we hope to target mid December and we’ll run it probably through the end of January. As Keith said, we’d like to sort out the participation prior to going out with that follow on open season.

We’re pretty optimistic, the message we’re getting is that [pionce] producers have basically anchored REX. They’re not going to be in for a major role, it’s going to be driven by the greater Green and Pinedale Jonah producers and obviously Keith’s comment about QEP making a major commitment I think signals to other producers in that basin that this is a solid project, one that they need to take a serious look at. We’re hoping that they’ll match QEP’s commitment on this pipe.

Operator

Our next question comes from [Winfred Fruhab – WB Fruhab Consulting].

[Winfred Fruhab – WB Fruhab Consulting]

I have a question on Kinder Morgan’s proposed bullet line to Chicago. How does RAPP compare to that proposed line?

Stephen E. Parks

Well, they’re competing projects Winfred.

R. Allan Bradley

When we look at the projects basically you’re looking at almost an identical route. Our route is a little shorter in that the Chex project as it’s referred, Chicago Express follows more the Rockies Express pipeline corridor. But, when you get in to the Chicago are you’re basically following NPGL’s line in to Chicago. We feel that one of the benefits of the RAPP project is the ability to tie in to a very flexible downstream header that Alliance has built just east of [Oxsable] and [Joliette] and there’s a lot of delivery flexibility there that we don’t have to replicate.

Right now as Keith says it’s a competition. We feel like there are a lot of similarities between the two projects and at the moment we feel like we’re in a pretty good position based on the results of our initial open season and the producer feedback we’ve gotten on our new reroute.

[Winfred Fruhab – WB Fruhab Consulting]

What happened to your venture with Enterprise that you announced about I think of May of last year?

Stephen E. Parks

That project is moving along nicely. Thank you for asking that Winfred, it’s called our White River hub project. It consists of about a six mile, 30 inch pipeline that connects the Greasewood and Meeker hubs. We’ve just finished hydrostatically testing the line. Everything looks good, we’re finishing up interconnects both to REX, GIG, [WIC]. We’re also working on one with Northwest. That’s going to be a very liquid point and right now it looks like we’ll have that new system in service by about November 20th, 21st.

Because it’s a new system in the area we have customers coming in for some training, how to nominate early November. We’re pretty excited by this initiative and hope it incentivizes additional volume and expansions to that hub as we move forward.

Operator

Our next question comes from Carl Kirst – BMO Capital Markets.

Carl Kirst – BMO Capital Markets

A couple of micro and then a macro question, maybe staying on RAPP Allan, if my recollection serves, we’re looking at roughly a $5 billion proposal around $1.50 negotiated rate. As you guys look to go in to this next open season are we basically staying around those perimeters or has the retrenchment in steel perhaps made that even more attractive?

R. Allan Bradley

We’re looking at that right now. Clearly, steel prices have to climb from when we put this estimate together and at the end of the day as we bring in new partners and they look at their due diligence I think it will also give us some additional comfort that another eyes has looked that investment. But, we’re fairly confident we can build it at that price if not lower with commodity prices, labor rates changing dramatically from where they were just a quarter ago this is probably on the high side if I had to guess right now.

Carl Kirst – BMO Capital Markets

Chuck, kind of turning to the Haynesville for a second, obviously 30 wells being budgeted here for next year, obviously everyone kind of interested in these next well results. How should we expect timing of information disclosure on these? Is this something where the two wells that are currently waiting to be completed that you might have at the November 12th analyst meeting or is this something where you might wait to kind of disclose sort of the grouping of four wells until you have all the data on those four? How should we expect that?

Charles B. Stanley

That’s a good question. I hadn’t really thought about timing on when we come out. I’d like to see at least two or three weeks of stabilized production because I think it’s really the average over the first 30 days is meaningful. Frankly, we’re going to complete these wells sequentially so we’ll have one maybe fraced before the analyst meeting in the middle of being fraced so we won’t have any meaningful production information by the analyst meeting. It will certainly be about year end.

What I would hope is that we’d issue an operational update maybe toward the end of the year that would give you some additional color on these wells. Obviously, we’re guardedly optimistic about the sweet spot as Keith described it that we seem to be in. we’re basically surrounded to the south, to the north and to the northwest by very good well results and [Canua] has reported at least one horizontal well to the southeast of us, sort of due south of our [Waterville] acreage.

To the north we are participants in several Petrohawk wells which the results that have been announced and of course Petrohawk has already disclosed performance on a couple of other wells that they recently completed that indicate that the acreage that we operate seems to be in an area of high initial rates and from extrapolation from other sales encouraging EURs. Obviously as Keith mentioned, it’s too early to talk in great detail about our view on this area other than we are very encouraged by the other operators’ results that have been reported today.

Carl Kirst – BMO Capital Markets

Keith, kind of more a macro question and obviously you opened with sort of the stock price performance and where it is and certainly unfortunately even below the X&G XOP, even before accounting for your utility operations. Now, obviously we’re in a crazy market but does something like what’s recently happened with kind of almost the excess beta that’s in your stock, does that get you thinking more about restructuring or does the kind of craziness in the market at this point make you think less about restructuring, let’s keep it together for the foreseeable future and once markets settle if there is restructuring to do we’ll address it at that time? How should we be thinking about that right now?

Keith O. Rattie

Restructuring in the kind of environment that we’re in probably doesn’t make a lot of sense to our shareholders. But, longer term we still think it does. We think maybe not – I would shift the emphasis of your question just a bit. We think about what do we have to do to maximize value for our owners and one of the options obviously is a restructuring. Separation of market resources from the rest of the company, separation of just the E&P company, other things that we can do to use our regulated business more to highlight the value that those businesses have.

We’ve talked about all of the different alternatives in the past Carl. In the current environment we think the appropriate thing to do for our loyal long term shareholders is focus on executing the plan that the board just approved and if we do that we believe that ultimately the market will reflect in our stock price the fundamental value of this mix of businesses.

Operator

Our next question comes from Holly Stewart – Howard Weil, Inc.

Holly Stewart – Howard Weil, Inc.

Just a couple of ones real quick, can you give us an idea of current production volume shut in, in the Pinedale and kind of thoughts going in to 4Q?

Charles B. Stanley

We don’t have any production shut in other than minor amounts as we do tie ins and new wells. We’ve just completed the tie in operations on both ends of the new 30 inch rendezvous line that we just completed hydro testing on. We’re purging and packing that line. We were down for five days or so as we conducted the tie in operations on both ends earlier – well, actually we came back online last Friday afternoon, Friday evening so we were down most of last week. Other than that no shut ins currently.

Holly Stewart – Howard Weil, Inc.

Then Chuck can you give us an idea of how we should be thinking about 4Q volumes just using your actual for 3Q it looks like you could kind of come in above the high end of that range. So, give us an idea of have you already stopped drilling gas wells out in the Rockies, moving rigs out, etc.? Just thinking about 4Q?

Charles B. Stanley

Well, as Keith mentioned, we are deliberately shifting capital from the Rockies to the midcontinent region and that will result in a reduced amount of gas production coming out of some of the areas that you expected to see growth in and a bit of a delay as we move rigs and people and get back in to the drilling mode in these new plays. You’ve seen our production guidance, we’re comfortable within that range, we think we’ll come in at the high end of that range and beyond that I can’t give you much more color.

Holly Stewart – Howard Weil, Inc.

Then can you just make a comment or two on the Unita oil play that Keith is referring to in his prepared remarks?

Charles B. Stanley

The Unita basin properties, the big large contiguous block of 120,000 acres was originally developed back in the late 50s as an oil play. The Green River formation contains multiple stacked reservoirs that have been developed over the years by Gulf and Chevron and then more recently by us. Over 600 million barrels of oil in place just in the Red Wash field alone and less than 15% of that, in fact less than 12% of that has been recovered to date.

Lots of attempts to water flood the fields with varying degrees of success. We had a quite but fairly continuous program of drilling horizontal wells to both tap unswept oil that has been banked as a result of imperfect water flooding that was done but we’ve also identified some thinner reservoirs that were never actually perforated and produced and we’ve been targeting those reservoirs with horizontal drilling.

We’ve recently completed a dual lateral horizontal well in a reservoir in the Green River that’s only about eight feet thick or less and that well came on at close to 400 barrels a day. We think these individual single laterals will recover about 80,000 to 90,000 barrels of oil. They’re very economic even at much lower forward oil prices than we see today and we think it’s a good way to continue development. We have tie ins to the pipeline that brings the oil directly to the Salt Lake refining complex, very high net [inaudible] NYMEX on this crude oil stream

Operator

Our next question comes from Rebecca Followill – Tudor Pickering & Co. Securities.

Rebecca Followill – Tudor Pickering & Co. Securities

Can you provide, and it may take a second, cap ex ’08 and ’09 for Rockies all together and then continent so we can get a feel for in total how cap ex is changing and being reallocated to those areas? While you’re pulling that, two other questions, one on the credit watch on S&P, them recently putting you guys on credit watch negative, does it take in to account the lower cap ex budget for 2009 relative to 2008?

Then the last one is there’s been a lot of reallocation of capital from Rockies in to the midcontinent area and Haynesville. Do you guys have firm transportation capacity out of Haynesville in north Louisiana?

Charles B. Stanley

I’ll take the first and last question and I’ll let Keith and Steve handle the S&P question. ’08 Rockies cap ex estimates for the year is about $670 million. We’ll be down to about $480 million in ’09 if we continue along the plan that we showed the board. That’s about a 28% decrease year-over-year. The midcon together will go from let’s see here, let me make sure I’ve got the right numbers here, about $1.2 billion and of course that includes the acquisition, that’s what was throwing me off. $1.2 billion, you have to subtract about $700 million for the property acquisition, $658 million for the property acquisition in the midcon down to about $566 million in ’09.

Rebecca Followill – Tudor Pickering & Co. Securities

The other one is the Haynesville.

Charles B. Stanley

In regards to the transportation, we do have transport over to Perryville on the center point system that allows us to get in to a liquid hub there and we are committed on some additional projects that have been proposed and that are in progress. Not as concerned about near term takeaway but as you know with growing production volumes in northwest Louisiana there’s going to need to be additional takeaway capacity not only locally from the producing area to the market hubs but also we’re going to need additional takeaway capacity out of the market hubs to eastern markets or southeastern markets in order to move that gas away from the producing region and in to the consuming regions.

The S&P question?

Keith O. Rattie

Rebecca I’ll just give you a quick perspective on the S&P question and then invite Steve to add any additional color. The short answer to your question is that S&P issued their announcement that they were going to review Questar and several other companies before they had the benefit of our 2009 plan. You should also be aware that on September 10th of this year S&P affirmed the ratings of each of the Questar entities with a stable outlook.

So, sometime between September 10th and the middle part of October S&P’s perspective on businesses like Questar which have a growing E&P element to our overall corporate strategy, sometime during that period their perspective changed. We have since provided S&P with a very detailed look at not just 2009 but looking out several years.

The essence of what we have shown them is that we contend to live within our means over the next few years. That if we execute the plan we will continue to delever on a consolidated basis and in particular at the market resources level over the next five years.

Operator

Our next question comes from Brian Singer – Goldman Sachs.

Brian Singer – Goldman Sachs

Two questions, first as you shift capital in to the midcontinent from the Rockies are there any people or expertise issues that come up in terms of getting the right people with the right know how in the midcontinent versus the Rockies?

Charles B. Stanley

I think we have the right people and the right know how and it’s simply a matter of changing the focus. The team that has delivered superb results at Pinedale over the past five or six years has now a core group of people in the field on the drilling rigs in the form of well site supervision that know their job inside and out and so the amount of what I would describe as office and front line supervision attention that we need to place on that asset is much less than it was three or four years ago.

But, we can take that same core group of people and the same techniques, technology and culture that we developed at Pinedale and transfer it to our other core operating areas and that’s exactly what we’re doing. In fact, we’ll take some of the most experienced supervision that’s learned from the experiences of Pinedale and use them in places like the Haynesville play to implicate that organization with the same techniques and culture.

Brian Singer – Goldman Sachs

When you think about reducing, and perhaps you said this already in which case I apologize, but the reduction in the Unita basin and the ex Pinedale Rockies, are you thinking about this as capital markets related in which case we could see some drilling come back if capital markets improved? Or, Rockies gas price related in which case perhaps we may not see any additional drilling or resumption of drilling until 2011?

Charles B. Stanley

It’s price and cost and returns. Even if we had unlimited capital I think you would see us do exactly the same thing and that is we’re going to chase the highest returns in our portfolio and today it’s not in any of the Rockies properties outside of Pinedale. Pinedale as you know, is the lowest cost [unconventional] gas play in the Rockies. It makes sense that prices we see today on the forward curve and even at lower prices than today.

But, a lot of the other properties do not generate acceptable returns at today’s price or the forward curve. But, more importantly, we’ve got other places in the midcontinent, oil directed drilling, etc. that generate much better returns so we’re going to focus on those. There’s another factor that drives the current view and that is although we see very strong anecdotal evidence of a softening in the services and the inputs in to the drilling side of the business, steel costs, etc. as Allan Bradley [inaudible] with respect to his pipeline project.

Those haven’t flowed through the system yet and until those do we have the double whammy of low forward prices and industry costs which are still reflective of commodity prices of six to eight months ago. So, as is always the case, the drilling completion service industry costs tend to lag the forward curve and we expect those to come down. But, as Keith said, today we run economics on our current experience not on what we hope or think might happen in the future and as we get more tangible data on the response of the cost side we’ll make economic decisions based on that.

I think for the near term, for the next six or 12 months we’re not likely to change significantly the current capital allocation. If there’s a dramatic rise in NYMEX prices and basis does not wide as much as we fear then we’ll look at it again. We’re running a very dynamic business and we’ll continue to look at capital allocation decisions on a daily basis to decide whether or not we made the right decision today and whether it’s sustainable.

Keith O. Rattie

Brian, just one added comment, over the last several years it has been our strategic intent to diversify away from our concentration in the Rockies. Chuck and his team have executed well particularly with a series of transactions over the last couple of years combined with superb efforts on the part of the people in our divisions so we now have the opportunity to put capital in to the Bakken, in to the Haynesville, in the Cotton Valley Hosston and Woodford shale in Canadian County Oklahoma and the Granite Wash Atoka in the Texas Panhandle in addition to Pinedale.

We continue to see this as an exercise in managing a portfolio of assets to achieve the highest returns.

Brian Singer – Goldman Sachs

Lastly, on the gas distribution front are you seeing or can you comment on just the demand trends that you’re seeing on maybe a weather normal basis and your expectations going in to winter?

Keith O. Rattie

I’m going to let Ron Jibson handle that. As many of you know Ron replaced [Allan Alright] who retired on the first of September. Ron is now running our utility.

Ronald W. Jibson

Brian, we still see growth in Utah being about 2.6%, economic development is strong in the state with prices down it’s a positive model right now for us. We feel confident that we can meet that growth and do it with a live within our means budget this year.

Brian Singer – Goldman Sachs

And you’re not seeing any initial impact of lower economic growth nationwide, etc. on gas demand?

Ronald W. Jibson

We are down like most places in the country but we’re not down as far as most places. We seem to be weathering through that right now. We have certainly the housing market is being impacted but our growth we anticipate for ’09 will be done as far as new customers. But, we also anticipate from all the models that we’ve seen and analysts that we’ll be rebounding quite quickly in ‘010 and ‘011. So, we anticipate ’09 our growth being down potentially another 30% or so from this year.

Keith O. Rattie

Brian as you know just with respect to natural gas demand across the country in a weakening economy we would expect that gas demand for electric power generation will be soft. It tends to move in the same direction as GDP growth which of course is going to be down at least for the next couple of four quarters. Demand in the residential sectors are a function of weather and you tell me what kind of weather we’re going to have this winter and I’ll tell you whether gas demand in that sector is going to be up or down.

One of the intriguing things this past year is we have seen some growth in demand for gas in the industrial market that in part reflects the fact that US natural gas prices are among the lowest in the world certainly lower than Europe or Asia so in industries where natural gas is an important factor of production, US industry now has a competitive advantage at least against companies operating in those regions. I would expect with the economic conditions that we’re going to see industrial demand soften.

So, we as an industry are going to have to adjust and that means that the kind of supply growth that we saw in the first half that was of course a consequence of high prices and increased capital spending, that growth is going to have to slow to balance this market.

Ronald W. Jibson

Then Brian we do have a weather tracker, a weatherization tracker in our rate structure which helps to stabilize that weather impact.

Operator

Our next question comes from Analyst Samuel Brothwell – Wachovia Securities.

Analyst for Samuel Brothwell – Wachovia Securities

Just a couple of quick ones, in the Bakken can you give us an idea of what type of oil price you would need in order to achieve your hurdle rate of 15%?

Charles B. Stanley

The Bakken wells, using our sort of estimated pipe curve having not drilled on in our block of acreage the 62,000 acre block, we think that the sort of 15% hurdle rate is achieved with a half a million barrel well at mid 40s well hit prices.

Analyst for Samuel Brothwell – Wachovia Securities

In the Haynesville, how many wells, I know you guys gave a number out there but how many wells do you need to drill between the end of ’08 and 2009 in order to hold the rest of your leases there?

Charles B. Stanley

Not that many. About a half of dozen I think is the count. You’ll recall I think we visited on this topic before. The Haynesville is spaced, or the drilling blocks is 640 acre, one section drilling blocks drilling a well on one section holds the entire section even though you would only be developing a portion of it. A lot of our acreage is held by production, about a little over half of it is held by production and the rest of the lease expiries are not real need.

Several of the wells that we’re doing right now are obviously in response to near term lease expiries but half a dozen wells or so. So, the rest of them are basically focused on developing subsurface control and as Keith mentioned in his prepared remarks not only do we need initial rates and production but the real open question that we need is longer term production history on these wells. We need to get the data gathered and start to put wells on production and get some longer term data.

Analyst for Samuel Brothwell – Wachovia Securities

Just finally, in Pinedale, jumping back up there I see you’re cutting back the number of rigs from nine to 12 and it looks like the number of wells you’re calling for look a little light. We kind of expected after the record of decision that you could probably double what you’re doing this year but yet you’re only cutting back the rigs by 75%. It looks like your number there on number of wells is a lot less than that. Can you give us an idea of what’s driving that?

Charles B. Stanley

We’ve assumed fairly conservative drilling completion times and cycle times on the rigs. We hope we can do better than that. But, keep in mind that unlike the other operators at Pinedale we’ve been basically operating as if we’d have the SCIS for the past several years. We’ve been spending most of our times with rigs on pads, pad drillings, skidding and just continuing to drill without moving rigs off and so we’ve already driven a lot of the efficiency in to our operation already.

We’re really looking at a 2009 program that’s not substantially changed from 2008 as far as total rig count. We had seven rigs working through the winter last winter and we’ll have nine through this winter so it’s not a big shift in the amount of activity year-over-year.

Keith O. Rattie

Just one other point John, Chuck and his team continue to focus on productivity. They’ve driven it down very substantially over the last few years. To put that in to perspective, in 2007 average time to drill a well from spud to TD was about 34, 35 days, at Pinedale it’s in the upper 20s, actually 27 in 2008. Also, keep in mind that we’re drilling direction wells with major depths down to around 14,300 feet.

When we put a plan together we don’t assume we can achieve that kind of productivity improvement so there’s obviously an opportunity to do better. If you go back a year ago and look at what we were guiding for this year and what we were actually doing this year would give you a feel for what we’ve done in the past.

Analyst for Samuel Brothwell – Wachovia Securities

It sounds like conservatism?

Charles B. Stanley

John, at some point we will hit the wall. I keep lowering the bar for these guys, I know they can’t go to zero days to drill a well but I’ve got it just above zero and we’ll see what they can do.

Keith O. Rattie

We have to assume that they’ve run all the efficiency out of this.

Charles B. Stanley

That’s just a challenge.

Operator

Our next question comes from [Shanere Garshuny].

[Shanere Garshuny]

I just had a couple of quick questions, most of my question have actually been answered. I guess I just wanted to focus on the Haynesville for a second here. I know we’ve been here a couple of times but it doesn’t sound like you’re classifying it as ready for commercial development just yet. What kind of milestones are you looking for to be able to say that this is ready to go for full scale commercial development?

Charles B. Stanley

I would say doing 30 wells in ’09 indicates a fairly high confidence level that the play is commercial. One of the challenges for us is just ramping up prudently without sort of overrunning our ability to complete the wells, gather them and move the gas and also these wells are expensive, they’re complicated and we want to make sure that we embed the learning curve as quickly as possible in our operation down there so we start focusing on driving down costs. That’s why you see a bit of what might appear to be some conservatism.

30 wells from basically none this year is a pretty big jump especially given the nature of these wells.

Keith O. Rattie

And given the environment we’re in and the difficult decisions we have to make about where to allocate capital, I think you can surmise from the plan that we have in place that we’ve got quite a bit of confidence in our team’s ability to produce the results that we’re modeling.

Charles B. Stanley

Just to give you a little more sense, we’re carrying these wells with economics forecasting about a 4.7 BCF EUR and initial rates of about 8 million cubic feet a day or IP of 8 million cubic feet a day. Those numbers we feel are easily supportable by the rock properties that we’ve seen and the cores that we’ve collected, the open hole logs we’ve collected in the first couple of wells that we’ve drilled. We have to see what the actual production is.

The offset results would tell you that these numbers may be very conservative but that’s where we are in our own learning curve and that’s what’s being carried. At those IPs and those EURs these wells are economic even at today’s costs and what we hope to be able to do is drive the cost down obviously.

[Shanere Garshuny]

I’m kind of happy you guys mentioned that, I was hoping that would be the case. I guess this sort of backs on to what Carl was asking before, this is something where we can see a revision in kind of a 2P, 3P number kind of more of an ’09 event I guess as you get some more of these wells drilled. Is that kind of the way to think about it?

Charles B. Stanley

If you look at our IR presentation, I don’t have it in front of me but there’s a summary page that has a map of the US and shows our multi basin portfolio. If you look in the northwest Louisiana area I think you’ll see there’s no problem possible reserves allocated to the Haynesville, it’s all in the resource potential and I think we showed about [inaudible] BCF. Obviously, we’ve got bookable proved undeveloped well locations surrounding the Petrohawk producing wells that we could book right now.

So, not only will you see it migrate in to probable and possible you’ll also see it migrate in to fruit. We obviously can book our PDP interest in the first producing Petrohawk well that we have an interest in.

[Shanere Garshuny]

When we think about Unita, kind of the same question but in reverse, should we still just think of this as a commercial development play but we’re just waiting for gas prices to come back? And I guess at the same time, you had some right of way issues with gathering, maybe you can update us there as well too? Kind of how that’s going to look within the reserve profile?

Charles B. Stanley

As Keith mentioned the most recent well results have been very encouraging. We’ve turned a couple of wells to sales this past week or so at five to six million a day. We were seeing the results of a lot of focus and effort on driving down drill times. It use to take us 70 to 80 days to drill one of those wells, the last one we drilled to TD in about 42 days as I recall. So, we’re seeing the Pinedale mantra on focus on cycle times and on drill times be born out in the Unita basin.

Unfortunately, we also were drilling these wells at the peak of service costs and of steel costs, etc. and it made a recipe where we had high costs and a dramatically weaker forward curve and looking at those two together we made the deliberate decision not to spend any more capital after we finished up the wells we’re drilling on right now until we see a rebalancing of costs and commodity prices. I think that will come.

But, I do think as Keith had mentioned in his prepared remarks, we’re going to see some tough times for Rockies gas prices especially during the summertime when local demand is not going to be sufficient to soak up the deliverability here in the Rockies. So, we’re focused on investing capital in to plays that generate acceptable returns at lower basis adjusted netbacks than the forward curve.

The gathering system issues we’ve been able to solve the bottlenecks on the western part of our acreage and you’ve seen that in the production response in the third quarter. We’re still waiting on a permit on a critical gathering line in what we call the southeast bread Red Wash area which is in the extreme southeastern corner of our big block of acreage. We are not seeing that right of way pop out of the BLM permitting process yet. I think it will probably be towards the end of the year early next year before we get it.

There’s some pent up production in that area that will give us a production response without drilling any more wells if we can just get the gathering system pressure down. But, next year we’re not planning on drilling any deep wells in the play just because of the ability to invest capital at much higher returns in other parts of our portfolio.

[Shanere Garshuny]

Maybe one last question for either Chuck or Keith, with respect to your guidance, what are you view as the risks to your upside of natural gas prices yourself? In the past you have managed to beat your well counts and you did talk about how much more productivity you can get but you are shifting capital to other areas. Are there opportunities there for well counts to be above your expectations and how do you feel about the conservatism that you’re using with respect to basis differential?

Charles B. Stanley

I’ll give you the operational side of it and let Keith talk to you a little bit about pricing. When we put together a plan to present to the board, we always use unrisked capital and risk production results. We know we’re in a risky business. None of the wells we drill turn out exactly like we think they’re going to turn out, some turn out better, some turn out worse so there’s a technical risk that goes in, a geological risk that goes in to the evaluation of each well we drill and the forecasting and production.

There are also another component of timing risk and that is just when the wells get drilled, the sequence they get drilled in and when they get turned to sales. So, we tend to err on the side of conservatism in forecasting production based on that philosophy and I think it’s served us well and we tend to always come in at or above the range of production guidance.

That said, we’re stepping in to a couple of new plays that we don’t have any experience in, I don’t know how repeatable results are going to be and so there is a bit of concern in our shop about moving away from very repeatable plays like Pinedale in to new plays like the Haynesville, the Bakken and some of our other plays, the Woodford shale play where there’s just a handful of well results upon which to base a forecast.

So, as I mentioned when I was answering John’s question on the Haynesville, we’re prognosticating an 8 million a day IP while there are wells immediately adjacent to some of our locations that we’ll drill next year that have will have 15 million, 16 million, 20 million a day initial rates. Hopefully, we’ve been appropriately conservative and we’ll do better. The final comment that I’ll make from an operational standpoint is a real wild card and that is every year, especially in the midcontinent we see a substantial number of outside operated wells proposed to us that we elect to participate in and we have no way at this point of being able to predict with any high degree of confidence the level of activity and the specific areas that we have outside operating interests in. That’s a real wild card.

We try to make a guess on it and every year it’s a guess but this year is particularly difficult given the capital market environment and pricing environment in some of these plays.

Keith O. Rattie

On the price part of your question, just to put this in to context, our guidance next year as we summarized in the release is based on NYMEX of $6.50 to $7.50. Yesterday the 12 month 2009 NYMEX drip was at $7.34. You’ll also see in our guidance that we assume Rockies basis ranging from $2.00 to $3.50 next year. On average the current quoted basis is about $2.32. So, NYMEX is currently at the upper end of our range, Rockies basis is currently at the lower end of our range.

The only other thing I would add to Chuck’s response is that there’s an intense focus across all of our E&P division on brining cost down and as I mentioned earlier our costs assumptions for next year assume that we’re going to see cost comparable to what we’ve seen recently. Hopefully, that’s going to turn out, a year from now we’ll talk about lower costs and better results as a consequence.

Operator

Our next question comes from Carl Kirst – BMO Capital Markets.

Carl Kirst – BMO Capital Markets

Just a couple of very quick follow ups, Keith, Chuck with respect to the netbacks that we have modeled, that you guys have modeled within your guidance, can you remind us of what your returns would be in the Pinedale and sort of projected in the midcontinent or the Haynesville I guess more specifically. I’d like to just go back to Wexpro then given the great returns there and I’m just wondering from a capital budget standpoint is Wexpro effectively maxed out with what we can spend for next year?

Keith O. Rattie

With respect to the first question, Pinedale netbacks are well above 15% on the current forecasted forward pricing. I can’t give you the exact number because I haven’t calculated it but well above 15%. The Haynesville similarly well above 15%. All of the plays to which we are allocating capital generate 15% or greater returns on the guidance number range that we’ve given you otherwise we wouldn’t be funding it.

With respect to Wexpro, we are prudently managing our investment in Wexpro. Again, we have certain limitations on the ability of the utility to take gas during the summer months without shutting in Wexpro production. Typically the utility pulls from the existing producing wells from Wexpro in the winter to provide a significant portion of the utilities demand. In the summer, when the demand in the utility is slacked because as you know this is mostly a heating market, the utility injects Wexpro production in to their storage capacity at Clay basin so that they can call on it for peak day deliveries in the winter.

There’s natural tension or natural limitation in the ability of us to drive investment in Wexpro to basically prudently manage the development and not drive the cost of service of the Wexpro supply up above the utilities other source of gas which is the open market. So, we manage our investments in Wexpro to make sure that there’s adequate supply for the utility but while at the same time not driving that cost up.

The other caution that we have is as I remarked earlier we have current service costs and well costs that reflect peak commodity prices and a forward curve that’s dramatically below that. We think that’s going to come down and that’s one of the other reasons that we don’t want to overdrive investment in Wexpro. A big chunk of Wexpro’s investment next year and in future years is at Pinedale. As our development at Pinedale goes so does the investment in Wexpro but I would hasten to say that Wexpro has a substantial inventory of development opportunities outside of Pinedale in some of their historic producing areas in western Wyoming.

Operator

There are no more questions.

Stephen E. Parks

Well, we want to thank everyone for dialing in this morning. A replay of this call will be on our website probably later today. Also, hope to see some of you on our next trip through Boston and New York. We’ll be in Boston on the 11th of November, New York on the 12th and we’ll have more color and more detail on our plan at that time. Once again folks, thanks for listening in, thanks for your interest in Questar.

Operator

This concludes today’s presentation. You may now disconnect your lines.

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