Questar Corporation. Q1 2008 Earnings Call Transcript

Questar Corporation (STR)

Q1 2008 Earnings Call

April 29, 2008 9:30 am ET

Executives

Stephen Parks - Senior Vice President and CFO

Keith Rattie - Chairman and CEO

Chuck Stanley - President and CEO of Questar Market Resources

Allan Allred - President and CEO of Questar Gas

Analysts

Brian Singer - Goldman Sachs

Faisel Khan - Citigroup

Mike Time - [Southwest] Investment

Annie Tsao - AllianceBernstein

Joe Magner - Tristone Capital

Rebecca Followill - Tudor Pickering

Sam Brothwell - Wachovia

Dan McSpirit - BMO Capital Markets

David Hemron - Wachovia

Holly Stewart - Howard Weil

Presentation

Operator

Good morning. My name is [Lucy] and I will be your conference operator today. At this time, I would like to welcome everyone to the First 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).

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

Stephen Parks - Senior Vice President and CFO

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

Other members of Questar management team are on the call today to answer your questions, including Chuck Stanley, President and CEO of Questar Market Resources and Alan Allred, President and CEO of Questar Gas.

Our remarks this morning will contain forward-looking statements about the future operations and expectations of Questar Corporation. We’ll make these statements in good faith. We believe they are reasonable representations of the company’s expected performance at this time. The actual results, of course, may vary significantly from our current expectations due to a variety of factors that are described in our Form 10-K filing with the Securities and Exchange Commission.

Now, here’s a quick summary of our first quarter results. Questar grew net income 23% in first quarter 2008 to 185.8 million or $1.05 per diluted share, compared with 151.1 million or $0.86 per diluted share a year ago. We now expect 2008 net income to range from $3.25 to $3.40 per diluted share compared with prior guidance of $3.05 to $3.20.

Our Market Resources subsidiaries led the way growing net income 27% to 139.3 million in the first quarter of 2008. All four Market Resources segments: Questar E&P, Wexpro, Gas Management, and Energy Trading, delivered double-digit net income growth.

Questar E&P grew net income 25% to $96.5 million with production increasing 13% to 39.5 Bcfe. Realized prices for natural gas, crude oil, and NGL increased 16%, more than offsetting an increase in average production cost.

Wexpro grew net income 17% driven by a 19% increase in investment base over the past 12 months.

Gas Management grew net income 49% driven by higher gathering and processing margin.

Energy Trading grew net income 35% driven by higher trading and storage margins related to volatile natural gas prices in the Rockies.

Questar Pipeline, our interstate pipeline and storage business, earned 15.9 million in the first quarter 2008, up 42% from 2007. The increase was driven by higher transportation revenues from expansion projects completed in fourth quarter 2007.

Questar Gas, our retail gas distribution utility, reported first quarter 2008 an income of 30.6 million, 5% higher than a year ago. Questar Gas now serves 881,900 homes and businesses, up 2.4% from a year ago.

For more details on the first quarter 2008 results, you can get a copy of our earnings release and the latest version of our investor relations presentation on our website at www.questar.com.

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

Keith Rattie – Chairman and CEO

Good morning everyone. We’ve got a lot of ground to cover this morning. As Steve has noted, we are off to a pretty good start in ’08.

Our Questar business units posted record first quarter net income. Questar E&P as you note grew natural gas and oil equivalent production 13% from a year ago and 10% sequentially from the fourth quarter of 2007. Note that all four Questar E&P producing regions grew production by 9% or more. We grew Pinedale production 10% year-on-year and that was up 7% from the fourth quarter and that of course is despite the fact that the BLM won’t let us complete wells for mid-November until May.

Note the 12% growth in Uinta Basin production, our deep play and our core Red Wash, Wonsits Valley acreage and a couple of strong wells in our emerging Flat Rock play more than offset decline from our now mature Wasatch shallow gas play. And note that our Midcontinent team grew production 19% from a year ago. We closed the Louisiana acquisition on March 1. These new properties added 1.1 billion cubic feet equivalent net to Questar E&P production in March. If you strip that out, our Midcontinent teams grew production 10% from a year ago and that was driven by our core Elm Grove play in Northwest Louisiana and our new granite wash play in the Texas, Panhandle.

Our other E&P business, Wexpro is also off to a good start. We grew the investment base 19% from a year ago from 5% from year-end ’07. We plan to invest at least $130 million this year in Wexpro and at least 700 million over the next five years and about half of that at Pinedale. Recall that under the 1981 Wexpro agreement, Wexpro earns 19 to 20% aftertax unlevered return on its net investment and development wells on a defined set of properties in the Rockies.

We hope that you notice that our field services business Questar Gas Management grew net income 49% in the first quarter compared to a year ago and that’s on the heels of 30% net income growth in 2007. Bottom line here our Rockies hub strategy is pay off for Questar owners. Note also that our marketing team, Questar Energy Trading had another record quarter.

Both of our regulated businesses posted solid results in the first quarter. Questar Pipeline grew net income 42% from a year ago. As Steve noted that was driven by higher revenues as we put the Overthrust in Southern System expansions into service in the fourth quarter of last year.

The Utility Questar Gas also had a good quarter. Net income was up 5%. Our Utility team connected 21,000 new customers over the past year, but more importantly our employees continue to serve customers well and they continue to hold the line on costs for SG&A cost for customer decline from a year ago.

The first quarter is now on the books so we now have better visibility on the rest of this year and therefore we have raised our net income introduction guidance. As Steve noted, we now expect ’08 net income to range from 3.25 to 3.40 per diluted share compared to previous guidance of 3.05 to 3.20 per diluted share. Production growth is what’s driving this income growth.

We now Questar E&P 2008 production to range from 166 to 169 billion cubic feet equivalent that’s up from prior guidance of 160 to 163 Bcfe and it’s driven not just by Pinedale but the strong start in all four Questar E&P producing regions.

We put a table on our release summarizing the key assumptions in our new guidance. Also note there is a table at the end of our release. We have taken advantage of the recent surge in commodity prices to add hedges on Questar E&P natural gas production through 2011. We have now hedged about 80% of Questar E&P’s forecast 2008 production and that takes commodity price mostly out of the equation for Questar shareholders in 2008. To put that into context, we estimate that $1 per million BTU change and the average NYMEX prop month price natural gas move our EPS by only about $0.01 per share.

As those who follow this over the years know our hedging discipline reflects our focus on returns and margins. In essence, we hedge to extract an attractive margin when market prices are at or above levels where US independent producers with higher cost structures are struggling to earn cost of capital returns.

This process should lock in returns well above our cost of capital; of course that’s provided that we maintain a low cost structure and our cost structure is one of the lowest in the industry. You will note that Questar E&P’s margin for MCF equivalent increased in the first quarter despite a 17% increase in our production cost structure. Note that over a half of that increase in the first quarter was due to higher production taxes, which of course, are related to sales prices and higher allocated interest related to the first quarter debt financing of the utility of the Louisiana acquisitions.

Let me turn now to operations, starting with Pinedale, note that we now expect to complete 70 to 75 gross wells this year at Pinedale and that’s up from prior guidance of 60 to 65. We’ve operated seven rigs through the winter, six on BLM lands, one on state section 16. We are going to come out of the restricted winter drilling season with 40 wells drilled, cased, and ready to complete, with another five wells drilling below 12,000 feet and two more just below intermediate casing point.

During the past week, we turned four winter wells on state section 16 to sales. Our Pinedale team continues the relentless drive for performance improvement. When we say Pinedale team, we are including our contractors. We’ve averaged less than 30 days from spud to TD on wells drilled at Pinedale this winter; that compares to an average of 35 days during the winter of 2006 and 2007. And just a reminder, we are drilling directional wells to measure depths of about 14,300 feet. If we stay on this track, our average cost to drill, complete and connect Pinedale wells this year could trend below $5.5 million. I remind you that we have about 1,600 gross wells yet to drill on Questar operated acreage of Pinedale for this productivity performance matters.

Now please note that this summer we are going to drill several 5-acre offset wells on the crest of the Anticline in the Stuart Point area adjacent to some of our highest rate, highest EUR wells drilled by anyone on the Pinedale Anticline to-date. Now what we are doing here is we are deliberately looking for depletion on 5-acre locations where you would expect to see it. Our current reservoir models invest our current reserve estimates indicate that we would recover less than 45% of the original gas-in-place with 10-acre density. We now think that 5-acre density will be economic across most of our acreage, but we are going to need to confirm this now because under the proposed SEIS, where we require to drill to the ultimate density in each concentrated development area as we move from south to north across our acreage.

We don’t have much new to report on the BLM SEIS. We continue to expect that the BLM will issue the final SEIS and record of decision sometime this summer.

Now, let me turn to the Uinta Basin. We completed and turned 12 new wells to sales in the first quarter with completions in a Mancos Shale and/or Dakota formations.

Uinta Basin deep play bottom line here is that the play appears to be working. Well performance remains consistent with our expectation that will ultimately recover between 3 and 6 Bcf equivalent from completions in the Wasatch, Mesa Verde, Blackhawk, Mancos and Dakota formation.

We currently have five rigs drilling on our Uinta Basin deep play. We plan to drill at least 33 gross wells this year. We are also moving ahead with our plan to shoot 3D seismic across our core 120,000 net acre block, which we hope will improve our execution in this play. The Uinta Basin deep play I should note has the highest F&D cost of our major play, so we are very focused on driving down well costs. We have assigned several key people from our Pinedale team to work with our Uinta Basin team to help make that happen.

One of the key areas of focus will be the deepest target, the Dakota. In some wells, the Dakota section can be highly productive. For example, our latest Dakota completion [ITed] at a rate of nearly 5 million cubic feet per day.

Turning to the Midcontinent, let me start with our core Cotton Valley/Hosston play, Northwest Louisiana and draw your attention to slide 20 in our latest IR presentation, which you can of course find at our website questar.com. With the acquisitions and some additional leases we have acquired over the past couple of months, we now have over 35,000 net acres in this play with up to 1,600 potential Cotton Valley/Hosston vertical well locations yet to drill on Questar acreage and that’s acreage with an average Questar working interest of 65%.

We now have six Questar operated rigs working in Northwest Louisiana. We plan to ramp up to 10 rigs by the end of this year. Our Tulsa team is off to a good start with a new Woodardville and Thorn Lake properties. We have completed and turned three vertical wells to sales since we took custody of these assets on March 1. We expect to grow vertical wells in this play at an average of less than 15 days from spud to TD and 30 days or less from spud to sales.

Over the past month, our primary focus has been on staffing, permitting, and building locations ahead of the arrival of the drilling rigs. We are also seeing potential upside with horizontal drilling on part of our acreage. You probably know that other operators in the area are reporting pretty impressive results with horizontal drilling. We are planning to spud our first horizontal well in the Lower Cotton Valley this summer. And yes, we do have deep rights to the Haynesville shale over a significant portion of our 35,000 net acres in this play.

Let move to the Texas Panhandle, our Oklahoma City team has least their way into a significant acreage position in the Granite Wash Atoka tight gas play in the Texas Panhandle. I draw your attention to the new disclosure on slide 19 of our latest IR presentation. Please note that we now have 25,000 net acres in this play. We’re planning to drill 48 gross wells this year with six rigs, three of which will be operated. We estimate that we could have over 235 locations yet to drill. Average well cost and EURs are summarized on the slide with risk F&D cost nominally in the $3 per Mcf equivalent range. This is a higher cost play than what we have targeted in the past but the economics work here with average and rehab flat prices above 725 per Mcf equivalent.

Let me also draw your attention to a potential new opportunity per Questar E&P in the Bakken shale oil play in North Dakota and as summarized on our new slides 17 in our IR presentation. Let me give you some background. Last summer Questar E&P participated with a 25% NRI in a horizontal well in the Bakken shale in the Parshall field in North Dakota that ITed at a rate of about 1,800 barrels of oil per day. That well focused our technical team’s attention on the fact that we had scattered interest in the area and we decided we wanted more exposure to this rapidly expanding oil play, so we since acquired about 60,000 net leasehold acres. Our block is roughly 12 miles southwest of Parshall and 10 miles northeast of the Bailey field. It’s on a fourth berthed Indian reservation mostly on the flanks and underneath Lake Sakakawea. We plan to spud our first horizontal well later this year. Chuck can give you more details when we get to Q&A.

Let me turn to Gas Management. Rockies gathering and processing team has a big job to do on behalf of our owners over the next several months. Questar and third party Pinedale volumes could surge later this year, so we’re going to need to complete that 106 mile 30 inch loop of the gathering trunk line that moves gas from Pinedale to a processing complex at BlacksFork and we have to complete it before winter.

Next year we’re going to need to add processing capacity at our BlacksFork hub. In the Uinta Basin we will soon commission our new 150 million cubic foot per day stage coach processing plant south of Red Wash. We’re also going to need to get to work on another expansion at this plant over the next 12 to 18 months to handle growing volumes for both Questar E&P and third party operators in the basin.

Let me turn to our Questar Pipeline, our interstate pipeline teams role and our corporate strategy as we discussed is to help protect returns on invested capital in our Rockies E&P business. And that means that they need to help expedite the next major Rockies export pipeline after Rockies Express. Now towards that objective, Questar Pipeline as we announced in March has entered into a MoU with Alliance Pipeline to develop the Rockies Alliance Pipeline, RAP to propose 42-inch pipeline from the Eastern Terminus of our Overthrust Pipeline at Wamsutter expansion, northeast to an interconnect with Alliance and other long haul pipes that historically have moved gas from western Canada to the US upper Midwest and northeast.

RAP will conduct an open season at May to determine if there is market support for this project. In the wake of our announcement, TransCanada has announced a competing project more or less targeting the same markets. Obviously only one of these pipelines is going to get built that will be the one that’s the first to secure long-term contracts.

Let me summarize. Questar is off to a good start in 2008. All four Questar E&P producing regions reported solid year-on-year growth in the first quarter. We operate in several of the largest unconventional natural gas resource plays in the US onshore today. Pinedale of course remains our growth driver where we have an average working interest of about 65% and over 1,600 wells yet to be drilled on Questar operated acreage on the Anticline, but there is a lot more to the Questar E&P story than just Pinedale.

Our Uinta Basin deep play is working. We have arrested decline and we are on track to grow Uinta Basin production by more than 10% this year. Our Midcontinent team grew production 19% in the first quarter. The Cotton Valley/Hosston play, northwest Louisiana is hot and we are one of the largest operators in the play. As I noted, it was roughly 1,600 low risk vertical development well locations yet to drill with upside from horizontal drilling and potentially deeper Haynesville.

After that, the Granite Wash Atoka play and the Texas Panhandle and we have the potential to grow Midcontinent production to over 100 billion cubic feet equivalent over the next four to five years. As I mentioned, we are hoping to add the North Dakota Bakken shale play to our story. We are going to aggressively evaluate our 60,000 net acreage in this expanding oil play over the next couple of years.

Our other E&P company, Wexpro has the visible inventory to potentially double net income over the next five years and the same is true of our midstream field services company, Gas Management which I noticed the largest gatherer on the Pinedale Anticline and one of the largest in the Uinta Basin. Questar pipeline turned in by far the best quarter in the company’s history. Our pipeline team is now working to make the next Rockies export pipeline happen.

I want to thank everyone for listening this morning and now we will be glad to open it up for questions.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from Brian Singer of Goldman Sachs.

Brian Singer

Thank you. Good morning.

Keith Rattie

Good morning, Brian.

Brian Singer

I had a couple of questions on costs. First can you talk about what seems to be a little bit uptick in LOE, this quarter obviously is still quite low, but was there anything specific to that and how do you see that going forward throughout the year?

Keith Rattie

Brian, I’m going to pitch that over to Chuck Stanley.

Chuck Stanley

Good morning Brian. Couple of components, one obviously a lot of their production is in the Rockies. We always experienced higher LOE in the winter months than we do in the summer. In addition, as we are seeing an uptick in operating volumes from our newly acquired properties in Northwest Louisiana, we are going to be experiencing a higher LOE especially during the early stage as we incorporate new liquids particularly produced water gathering and handling facilities and injection facilities which will not chop LOE initially but we would expect it to flatten and go down over time.

Brian Singer

Great.

Keith Rattie

Brian, just quickly put that into context as you may know, in all of 2007 Questar E&P’s total cost structure of 347 ranked second lowest amongst nearly 40 independent E&P companies in the industry. The industry average was somewhere in the 530 per Mcf equivalent range, so we are still one of the two or three lower cost companies and we’re very focused on our cost structure.

Brian Singer

Absolutely. Kind of along those lines, you mentioned a higher cost of the Granite Wash play. You historically focused on some of these lower F&D and operating cost opportunities, can you talk a little bit more how you think about allocating capital to higher cost plays like the Granite Wash versus spending more capital on various opportunities in the Rockies and East Texas?

Chuck Stanley

Well Brian, it’s Chuck again. I think we focus on two things obviously cost matter, cost structure is very important, but we also look at margins and I think you did a piece earlier this year that focused on effective margins and of course that’s what drives profitability. So when we look at our portfolio of opportunities across the various basins in which we operate, we are also mindful of the realized prices that we receive.

And obviously in the Midcontinent region, we see higher average prices and higher net backs. The Granite Wash also has a fairly rich gas stream that contains long liquids, which current oil prices and NGL prices boost returns there. We haven’t changed our discipline. We still look at allocating capital based on our perception of risk returns and we run our economics and at a planning price below the current forward strip and allocate capital accordingly. We will take a little bit lower return or conversely we will expect a little higher price in our Midcontinent properties than we do in our Rockies properties.

Brian Singer

Alright. Given you have expanded into the Bakken, East Texas, Granite Wash, should we expect more of this when we look out a year from now, should we expect Questar -- should we be surprised to see Questar in a few additional new plays?

Chuck Stanley

Well, I think we have fleet that’s pretty full at current time, Brian. Obviously early in the evaluation of some of these plays, the Northwest Louisiana play is something that we know well. We obviously pay a substantial amount for these new properties and we are committed to rapidly developing and so we will focus on that. We also evaluate as Keith mentioned in his remarks, the deeper potential and also evaluate horizontal drilling. The Bakken is in my mind exploratory play, we will drill a well early in -- hopefully sometime in the third quarter and see what that well tells us. There has been some recent results nearby that first wash liquid encouraging and obviously after that first well, we’ll a make a decision on development.

The Granite Wash play is in development. We are obviously drilling wells on that acreage and what I would call outpost locations, which have very little well control nearby and the results of a couple of key wells would drive future development in that play. At this time, I think that we have an adequate inventory of organic growth without going out looking for additional plays. Obviously, we will continue to look for opportunities to add to our existing positions to bolster the inventory in the core plays that we are already present in.

Brian Singer

Thank you.

Operator

Your next question comes from Faisel Khan from Citigroup.

Faisel Khan

Good morning.

Keith Rattie

Hi Faisel.

Faisel Khan

Just a couple of questions on Pinedale. You say, you have completed 40 wells already coming out of this winter and could you just give us a breakdown of the production forecast you have for ’08 that will be Pinedale and what that growth in the year-over-year ’08 versus ’07?

Keith Rattie

Just a quick correction, Faisel. We drilled in case 40 wells, so we are not allowed to complete wells on BLM acreage during the winter month, so we have got to build up inventory wells that were going to get after, get over the next couple of months turn them to sale, complete them and turn them to sales.

Faisel Khan

Okay.

Chuck Stanley

And Faisel, Chuck, let me add to that. We have raised our guidance. We always start out in the winner in the first quarter pretty conservatively because we are not sure which rigs are going to where until we actually settle in for the winter and then we have seen obviously as Keith mentioned continued improvement in the drilling efficiency of each of these rigs. There will be a hiatus of the drilling while we move these rigs off and move them on for pads for the summer. As Keith mentioned some of these rigs are going to move, at least one is going to move into a five acre plan up on the north end of our acreage around the Stuart Point area to delineate a high EUR with five acre well so that we can launch those wells and see how much interference if any we see between wells and any depletion from wells that are recovered in excess of 8 Bcf of gas already.

The question of production forecast, we don’t give guidance on a property-by-property basis. We will be up 15 plus percent at Pinedale year-over-year as part of our ongoing development out there. Obviously the key for Pinedale on a go-forward basis is going to be the approval of the Supplemental Environmental Impact Statement decision that we are anticipating sometime this summer, which will allow us to add rigs starting this fall and obviously the big impact comes in ‘09 and beyond.

Faisel Khan

Are there any significant hurdles in gaining that record of decision this summer?

Chuck Stanley

None that we are aware of Faisel. Everything seems to be on track. We are in a period right now that the BLM is working on drafting the final SEIS draft and will issue that hopefully some time in this summer and then soon after that a record of decision, which is the real operative document.

Faisel Khan

Okay. And then these five acre offsets you guys are looking at, you said these are highest EUR sort of occasion. When you say the highest EUR, what kind of magnitude of ultimate recovery are you looking at?

Chuck Stanley

Well, the wells that we are offsetting to my knowledge is the highest we have booked it I think at about 15 Bcf, maybe more and I think some other interest on it may have booked a little higher than that. The well has been online now for six or seven years, so it has a good production history and it’s already produced roughly half of the EURs attributed to it. So intuitively, we would expect if we are going to see depletion around that well at five acres that we would see dramatic depletion in some of the sands. You will recall that we have drilled some five acre pilot wells in State Section 16 and we have talked about those in previous calls. We were actually very encouraged and in fact surprised at the low level of depletion that we detected around lower EUR wells on the flank of the structure and we made the point at the time that we think that five acre density is appropriate at least for the rocks on the flanks of the structure and keep in mind the rocks there are deeper and slightly less permeable, slightly less porous. So it left open the question as to whether or not five acre density was appropriate on the crest of the structure where the wells are higher EUR, where the rock quality is slightly better because it’s slightly shallower. So now we’re going to step right into the highest EUR area of the entire Pinedale field and drill some five acre pilot wells to see whether or not we see the same depletion patterns.

Clearly, there is two things that impact depletion. One is just the rock quality. If the rock is very low permeability and porosity then two wells drilled into the same reservoir will have a difficult time depleting the gas from the reservoir even if there are in communication. Now the other thing is the architecture or the size of individual sand bodies and we know from the five acre wells we have drilled down in State Section 16 that the average size of these sands, the average individual sand body is less than 10 acres. So that bodes well for increased recovery from drilling on five acre density. The question is how much increase recovery in all five acre wells economic across the whole structure only on the flanks.

Faisel Khan

Okay, understood. And one last question. On the number of wells that you have now updated guidance on for Pinedale 70 to 75, can we make a linear extrapolation in terms of what you could do under an unconstrained environment and year around drilling? Could you do up to 140 to 150 wells a year?

Chuck Stanley

Faisel that assumed that we could leave the drilling rigs in one place and let them drill continuously uninterrupted without moving and obviously that’s not the case. There is a finite number of wells that you can drill with the rigs without actually rigging them down and physically moving them. Certainly, we are becoming more comfortable with 120 to 130 wells a year including rig moves as we see the dramatic improvements that our Pinedale teams has been able to deliver on number of days from spud to TD. We are seeing as Keith mentioned below 30 day average now from spud to TD, even some wells at less than 25 days and a couple in the low 20s and one in fact in 19 days and change. Obviously, if we can push that kind of efficiency through the entire drilling calendar then it makes a dramatic difference. At this point, I think 120, 130 wells a year incorporating moves and making sure that we can deliver on that’s a good place to start and obviously, as time goes on we will get better visibility on that.

Faisel Khan

Okay, great. Thanks for the time guys.

Chuck Stanley

Thanks Faisel.

Operator

Your next question comes from Mike Time from [Southwest] Investment.

Mike Time

Good morning. A question on assumed differentials. As I look at the numbers and look for much larger then what we get on the current prices, should we take that as you are going to see the situation getting all that worse or is that just being conservative on your part?

Stephen Parks

Mike, I am not sure of what differentials you are referring to, is the current forward curve?

Mike Time

I am looking at Rockies differential, it’s more in about $1.80 level, much less than the $2.50 to $3 in the assumptions?

Chuck Stanley

Yeah, we think there is continued risk in Rockies bases just to look at where we are today, yesterday, Rockies bases for remainder of calendar year 2008; it was about 2.70. It jumps a bit to 3.20 per Btu in 2009 and it’s still about $3 in 2010 before falling off in 2011. What the collective wisdom of the market is telling us is that where Rockies Express West, REX West is not going to solve the problem. We are going to need REX East in service. The sponsors on that project have publicly indicated that there is some delay. As we look over the course of this year, the bases could be wider in the latter part of the summer months, early parts of fall. Once regional storage here in the Rockies principally Clay basin, sale was up and absent either weather or weather related incidents that impact supply. Another big unknown this year of course is the level of LNG imports with oil prices where they are, LNG imports thus far this year have been far less than what most expected. We do expect that there will be more freed up LNG floating supply this summer and some of that could end up in the United States. Bottom line is we are cautious about Rockies bases over the next couple of years, one of the reasons why the pipeline is focused on trying to getting another project going. I would however point out that we’ve pretty much taken that risk out of the equation for Questar this year. I noted in my earlier remarks that $1 change in the average NYNEX price and that could be a $1 change in the basis, moves EPS by only a penny a share.

Mike Time

Okay. Also I noticed on the balance sheet that now you have some minority interest lifted and then dropped in the investment and unconsolidated affiliates. What’s changing that?

Stephen Parks

Mike, this is the part -- it’s just an accounting thing. Our investment in Rogersville partnership services the Pinedale and Jonah area up to Southcoast Wyoming, there has been a 50/50 partnership, we now have slightly more the investment of our partner so, the accounting rules have is consolidated, which you said. It gives the same net information.

Mike Time

Okay. And finally any update when we may see an update on the non-crude reserves?

Keith Rattie

Chuck, I’ll let Chuck Stanley handle that, the update in our estimates of probable and possible reserves.

Chuck Stanley

Mike, we are planning on doing it sometime this summer. We are working with our outside reserve evaluation engineer Rider Scott and our technical teams to finalize it and I can’t promise the time but sometime this summer.

Mike Time

Okay, thank you.

Operator

Your next question comes from Annie Tsao from AllianceBernstein.

Annie Tsao

Good morning guys.

Keith Rattie

Good morning, Annie.

Annie Tsao

Hi. Most of the questions have been asked. I just have a very, one question on the Energy Trading. Can you guys give me a little bit more color on that? And how should I think about it for the rest of the year and especially in your guidance, how much do you embedded in that? And as you grow your business should I think about this piece of business will be grow well?

Chuck Stanley

Annie, it’s Chuck. Energy Trading is a marketing shop, its primary responsibility is to market our equity gas and oil production from Questar E&P. It also owns and operates a small underground storage facility called Clear Creek in Western Wyoming and it holds some capacity in another gas storage field also in the Rockies. The majority of its earnings are tied to just simply to fees that it charges its affiliate for marketing, its volume. It makes additional profits by injecting natural gas during periods of low prices and then obviously withdrawing and selling it during periods of high prices and that was something last year that was because of the volatility Rockies basis and in Rockies prices was a very profitable business. And this year the volatility is a lot less but the company has still done quite well because it’s enjoying obviously the benefit of injecting gas into the storage booked last year at low prices and then withdrawing this year at higher prices. We don’t give guidance on individual business units and I am not going to start doing it here, but I would point to the lower volatility that exists in the current gas markets compared to a year ago to give you some sense for where we think the trading shop will end up the year.

Annie Tsao

Thank you.

Keith Rattie

Annie, just one added comment. Most E&P companies just pull their energy marketing activities into the E&P business results and quite frankly that’s probably the way investors should look at Energy Trading in the Questar portfolio.

Annie Tsao

Thank you. Okay.

Operator

Your next question comes from Joe Magner from Tristone Capital.

Joe Magner

Good morning. Just a question and it’s nice to see the increase in production guidance and sound performance in the Pinedale. I guess in the light of the comments about the deteriorating basis situation, concerned about transportation and lack of storage later this year, I guess shut-in production we saw last year in the third and fourth quarter, how do we think about your position with respect to firm transportation, ability to get gas out of the area if things do deteriorate and how or when or what sort of situation could, I guess develop that would see us see in shut-in production again from you or other producers in the regions, kind of how do we resolve some of those conflicts?

Chuck Stanley

Joe, we don’t have a magic model that predicts everybody else’s production, our production, we are obviously watching the production growth from our own properties and from the forecast from our competitors in the region and obviously it doesn’t take a genius to add up all of the forecast and realize that we’re going to have a transportation bottleneck if not this year then in a couple of years and that’s why our interstate pipeline affiliate, Questar Pipeline, has been tasked with trying to develop a new project to take gas out of the Rockies region and into markets in the northeast. And the key here is, we hedge to protect against this basis volatility. As Keith mentioned we have less than a penny per share of EPS sensitivity to a dollar change in either basis or NYMEX prices. And the reality is that that’s a derivative transaction, revenues flow from those derivatives regardless of whether we produce gas or not and we will not give our gas away and as we did last summer and fall when basis was dramatically wider than it is today, we will shut-in our physical production, buy gas to fulfill our hedges, and enjoy the benefit of other people’s production who are not hedged.

Joe Magner

Okay. So if that is really the requirement from transport is just because the plants or swaps or derivatives will cover the revenue?

Keith Rattie

We do have some firm transport on Kern River pipeline. We also hold firm capacity, storage capacity in Rockies and we in addition to the fixed price swaps, we also we have a table in our – the numbers in our table. W e also do a modest amount of basis hedging. So the potential volumes that are exposed to a wider than expected basis this summer, are not significant. We haven’t included a significant amount of curtailment in our production guidance and frankly we think that once REX comes into service this year, there should be enough capacity, pipeline capacity out of the Rockies to avoid a repeat of last year.

Joe Magner

Okay, fair enough. And just one point of clarification, the five acre pilot and I understand whether that’s going to work, that’s something we need to know before you get the final SEIS record of decision or is it something that you need to know before you begin to drill in a specific area?

Chuck Stanley

I guess they are one and the same Joe. When we get the record of decision, there will be a little bit of bigger room for some additional delineation drilling, but we will be required to drill up the field on whatever density we deem to be appropriate right out of the box and our concentrated development area will start in the south part of our acreage and move north and we are fully anticipating that we’ll go through the field one time and drill all the wells necessary to deplete the reserves in the field through one motion and not return. And that’s important for two reasons, one obviously it minimizes the disturbance, but the second is that from a PV perspective we know that wells drilled on 5 acre, 10 acre, 20 acre, 40 acre density behave identically during the early part of their life for the first X years.

We are not sure how many years it will take before 5 acre wells will start to interfere with each other, but certainly they won’t interfere initially. So for the several years, you enjoy the same production rate whether you are drilling on the first well and a 40 acre spacing unit or the fifth well inside that same 40 acre spacing unit i.e. a five acre of spaced well. So knowing that and knowing that if we waited to come back years later then we could potentially encounter some partial depletion, which could introduce drilling problems, we could get stuck in depleted sands, it’s compelling to develop the field on the optimum density right out of the box, get the flush production from wells drilled on increased density without interference and therefore enjoy the higher present value. And so that’s our focus and obviously, we don’t want to overdevelop or overdrill the field, so we need to know the answer right now before we start the development process full scale.

Joe Magner

Okay. Thanks for comment. That’s all.

Chuck Stanley

Thanks.

Operator

Your next question comes from Rebecca Followill from Tudor Pickering.

Rebecca Followill

One, with all you have on your plate, any change to CapEx guidance at this point?

Stephen Parks

Rebecca, our CapEx guidance remains the same as summarized on slide in our IR presentation just that give everybody that those numbers including the capital related to acquisition Louisiana. Our 2008 capital program is about $2.3 million, 1.5 million of that is allocated to Questar E&P, 130 million to Wexpro, 390 million to Gas Management, a big chunk of that’s for that 106 miles 30 inch pipeline from Pinedale to BlacksFork that I commented about earlier and a vast amounts of capital in the pipeline business and the utility business. We are going to wait until we get the record of decision at Pinedale and get further into our 2008 vast programs specifically the evaluation of the plays we talked about in our prepared remarks before we take a step back and take a look at capital. Sufficed to say that this company has a very large inventory of low risk development locations to drilled on its existing assets. Given the favorable price environment, we may have an opportunity to grow faster than that capital program suggests.

Rebecca Followill

Thanks. The other question is on North Louisiana, when you made the acquisition, I believe you are putting your guidance 12 Bcfe of production, first quarter was 1.1 for the month of March and you ramped upon rig significantly, is that being a little conservative at this point?

Stephen Parks

Chuck?

Chuck Stanley

Are you accusing me of being conservative, Rebecca?

Rebecca Followill

Never, never Chuck, never.

Chuck Stanley

On the acquired asset, we call that when we acquired the properties, we announced that we think we would close at the end of February, we did in fact. There hadn’t been any drilling activity on either properties during the whole of 2008 and most of the activity shut down in sometime during the fourth quarter of last year. So, properties have been on decline since late last year and as you know that there were five rigs working on a Woodardville property prior to the end of year. So with the high decline rates of individual wells drilled out there, we were fighting fairly steep initial decline. It will take a while to arrest that decline and turn it around. We are running 1.5 million or so cubic feet a day equivalent ahead of our initial estimate of where we would be right now, but not substantially ahead of where we think will be. So we are still pretty comfortable with the 12 Bcf from the property. I hope we can do better than that, but right now that’s I think a reasonable expectation for results this year.

Keith Rattie

Rebecca, it follows that a substantial portion of the increase in our production guidance for this year relates to the increased number of wells we expect to drill at Pinedale and the solid results we are getting from the other plays.

Rebecca Followill

Alright, thank you.

Chuck Stanley

Thanks.

Operator

Your next question comes from Sam Brothwell from Wachovia.

Sam Brothwell

Hi guys. It’s Sam Brothwell.

Keith Rattie

Hi Sam.

Sam Brothwell

I think you hit most of them, but just shifting gears to the pipeline in midstream operations, you are posting still some pretty impressive year-over-year growth in those businesses. How should we think about that a little bit longer term going forward. It seems kind of hard to imagine that you could need to sustain 50% year-over-year growth, but can you give us a little bit more data in terms of how we should think about that going forward?

Keith Rattie

We will try Sam. Starting with the pipeline business, as you well know pipeline companies grow when they invest capital and capital investment tends to be pretty lumpy. We have the big jump in net income in our pipeline business this year was related to the two major projects we put in service last year. As you recall we had a record capital year for our pipeline company. This year capital spending is going to be back down not far above the maintenance level we have a number of projects that we’ll complete this year. But they are relatively small from net income impact standpoint. The pipeline company’s growth will be a function of our ability to secure long term contracts to underwrite expansion projects. And we should be giving the investment community a pretty clear indication of what those projects are, maybe a little bit of indication of what the impact will be as we get those contracts.

The utility business is going to grow about as fast as it can grow its customer base provided that we are allowed to earn returns that are competitive with other well run utilities in the US are allowed to earn. But the bottom line is that even with better than average growth for utility and even with what we consider to be reasonable returns given the utility’s performance. The utility share contribution to total corporate net income was 7% last year, it’s trending towards 6% this year, and it will trend towards 5% not too far down the road. It’s becoming less material that’s not to say that our employees in this business don’t do a superb job, delivering gas safely and reliably to our growing customer base.

Chuck Stanley

And on the midstream business on the gathering processing business, a couple of key points. First in our Green River hub and we basically refer to these as hubs because we think that aggregating gas to a complex of gas processing plants and then offering producers including our ability to Questar E&P, the chance or opportunity to sell into multiple markets. So, for instance, for Pinedale producers including Questar E&P, access to all the major interstate pipelines leaving the Rockies region and to the local markets as well as to the storage fields of Clay Basin and a Clear Creek, gives optionality. And for the Western and Green River hub we have, what now the US EIA states is that the second largest gas field in the United States connected and dedicated the Northern third of that acreage, all of the acreage is dedicated to our midstream field services company. So, we have the second largest gas field in the United States very early in its productive life, dedicated for life of leases to that facility and to that business, so a very important growth driver. So when you see growth in Questar E&P drilling activity and production, you are going to see corresponding growth in EBITDA from our midstream business.

In the Uinta Basin, all of Questar E&P’s acreage is dedicated for life term midstream field services business and that’s a substantial chunk of acreage we have already talked about our plans to drill a large number of deep wells, 33 this year and we think we are just off out of the starting blocks on development of that property. So, another growth driver and in addition to that we have a substantial third party business and it’s growing in both of these areas as we basically leverage off of our initial investment to add additional customers and grow third party volumes and revenues on the existing systems. If we execute on the identified projects in our gathering and processing business, we will double the size of this business in five years. It will be $100 million plus net income business in five years and we feel pretty confident that based on the identified projects in the areas that I have mentioned.

Sam Brothwell

Okay. And Chuck, if I could just shift gears one more time and go back to Pinedale. Have you reconsidered fracking the no-pay sands at Pinedale similar to what Ultra is doing?

Chuck Stanley

Sam, we are innovators in a lot of ways, but we are also really good at copying people. If we can convince ourselves that somebody is got a better solution than one we are not, that we are not currently doing, we will be the first to copy them and of course Ultra is partners with us and all of our wells with the exception of a handful of wells in State Section 16. So, we are looking at their data and talking to them and if we are convinced ourselves that the completion of these intervals makes sense, we will do it.

Sam Brothwell

Okay. Thanks for the time guys.

Chuck Stanley

Thank you.

Operator

Your next question comes from Dan McSpirit from BMO Capital Markets.

Dan McSpirit

Good morning. If we could revisit your Bakken shale opportunity for a minute here. One, could you speak to the permitting process on a reservation with respect to dealing with Indian fares up there and really the pace of approval? And then secondly, I see on slide 17, that you have outlined some or illustrated some summary well economics, could you speak to your own internal estimates on potential cumes, as well as estimated cost on the first handful of wells?

Chuck Stanley

Dan, Chuck here. As for the permitting process as Keith mentioned this entire property package is on the [full throttled] reservation and there have been no significant activity on this reservation for years. A handful of wells drilled in there historically, but really no recent activity. So the Tribe and the BIA are gearing up to handle obviously the anticipated activity out here not only from us, but from other operators. We are encouraged, they are making progress and we don't think long-term that will be an issue. It's going to take them a while to get there, their infrastructure in place to process APD's. We are used to the drilling on Indian lands, we have a very active program in eastern Utah on the northern Ute Tribal properties and we are very used to dealing with BIA in in addition to BLM. So from permitting prospective, we are not too concerned.

On the question of EUR’s it’s too early to doing, the other than just speculate with you, based on results that we have seen north and south of us. We think likely that these wells if the middle Bakken for us is developed to recover on average a half a million barrels per well perhaps more. We also anticipate that at least right out of the box, our well cost will not be the same as those of other operators, who have been drilling out here for sometime. So we’ve estimated high, we hope on low cost at $5.5 to 6 million for the first one and then we would hope overtime that we would see those well cost come down into the low $5 million range for drills complete in equipped well.

Dan McSpirit

Got it, perfect. Thank you.

Chuck Stanley

Thanks.

Operator

Your next question comes from Rick Gross of Lehman Brothers.

Rick Gross

Unbelievable. Good morning all. I've got just a couple of things on the margin that have touched down earlier. One, is your third party volumes in the gathering of processing area jumped materially faster than your affiliate volumes. And I was curious as to who those parties were that were driving those volumes and where they were coming from?

Chuck Stanley

I won't disclose our good customer's names, but it's a large independent and most of it is coming from the Uinta Basin.

Rick Gross

Yeah, okay. The other thing is, one of the things that jumped in the cost structure was production taxes and it wasn't just kind of a function of volumes, it appeared to be a step up in the percentage of revenues adjusted for the hedges. And I kind of looked at the mix and I was little bit puzzled as to why we jump a couple of percentage points.

Chuck Stanley

You may recall Rick that last year Rockies base was were starting to widen pretty significantly that’s certainly a factor. We are also seeing in a wider basis in the Midcontinent, I suspect those two factors follow the account for certain….

Stephen Parks

Let me amplify a little bit Rick. First of all we pay production taxes on the sales price not on the realized price. Of course the sales price…….

Rick Gross

I adjusted, I adjusted for them.

Stephen Parks

Certainly, if you back out the hedges and then the second thing is, this year as opposed to last year, our mix of production has changed Midcontinent to Rockies. So you are looking at a different slate of percentages of production and number one taxes with the larger compound that coming from Louisiana then last year. I haven’t -- I don’t have the numbers in front of me, and enough granularity to walk you through, but we would be happy to do so, if you want to holler at me, later in the week.

Rick Gross

That’s fine. Its just sounds like it’s a mix change then.

Stephen Parks

I think that’s the primary thing along with what Keith mentioned, which is a dramatically higher sales price this year then last year in some areas.

Rick Gross

From a standpoint of -- although looking at the Unita area, we had a change of about 7 million cubic feet a day, I mean it was a double-digit change, but it was about 7 million a day. When you talked about the flat Rock area and some of the productivity of the wells there and we talked about how well the deep programs is doing. Can you give you me a feel for, we call it the total mix change here, we’ve got probably flat Rock growing, we’ve got deep program going, but we’ve got the base level of production eroding?

Chuck Stanley

That’s an accurate observation. You will recall that in 2001 we bought the Uinta properties with the acquisition of Shenandoah Energy. We were focused on the Wasatch, primarily Wasatch and then later on we started drilling Wasatch Mesa Verde wells, but we have pretty much exhausted that inventory of shallow development. We drilled over 600 total wells out here targeting the shallow sands that’s a big wedge of declining production that we have to replace and then grow upon.

Rick Gross

Okay. Of the 75 million or so what percentage is that, will call that old production?

Chuck Stanley

That old production is probably around 75% or so of the current production.

Rick Gross

Okay.

Chuck Stanley

And its still declining. Keep in mind, we drilled hundreds of wells out here and some of them are still in their first two or three years of life. So they're still declining quite rapidly.

Rick Gross

Okay. Thank you.

Operator

Your next question comes from David Hemron from Wachovia.

David Hemron

Hi, good morning everyone. Quick question for you, I don’t know, if this is Keith, its Chuck question. But can you guys talk a little bit about environmental regulations ie a little, our fine feather friends, the sage-grouse and any impact that might have on your operations going forward?

Keith Rattie

I think that's a Chuck question.

Chuck Stanley

Thanks, Keith. As you know, the sage-grouse a couple of years ago was considered for listing under the endangered species act and the Fish and Wildlife Service after studying it decided that there wasn't evidence to support listing. A while ago, now about six months or so ago, a Judge in Idaho , Judge Windmill reviewed that decision and found that Fish and Wildlife had not fully conducted the appraisal and basically punted back to Fish and Wildlife to conduct another round of evaluation. The data gathering for that evaluation is ongoing. Each of the State Rocky Mountain State Game and Fish Departments, as well as all of the companies involved in the area that have various programs going on to improve habitat, protect existing habitat, etc, are participating in a data gathering exercise. And that exercise we think will show that there are good programs in place, that there's a lot of money being spent by industry and by the various states to protect and enhance sage-grouse habitat and to justify the original decision not to list the bird as a threaten and endangered species. Obviously if it did happen, we would be back to the discussion that we've had several years ago about the impacts. They would be significant not only on us and on the E&P sector in general. But across a broad variety of industries from ranching, grazing to hunting and fishing, sporting activities because endangered species listing on the critter would basically put all of the public lands in the West off limits to everybody. And a substantial portion of public lands, not all of them. But again, we think that the [inaudible] decision was an error and that the data exists that shows that there's been a lot of work done and ongoing work being undertaken by various game and fish agencies throughout the West and by the private sector to protect the critters and that they are not deserving listing.

David Hemron

Alright, thanks.

Chuck Stanley

Thank you.

Operator

(Operator instructions). Your next question from Holly Stewart from Howard Weil.

Holly Stewart

Hi, guys, good morning. Just two quick ones here. I notice there is a nice up tick quarter-over-quarter in Rockies legacy production after a couple quarters of decline anything to point out here, that’s the first one. And then the second one, just on the Pinedale you've talked about this five acre offset program on the crest of the structure here. Any thoughts here around kind of 2P reserve update and then getting results from this first?

Chuck Stanley

Holly, the first question largely the up tick is related to bringing back on production that we had shut in last summer and fall due to low Rockies gas prices. The ongoing drilling activity at Wamsutter and some of our other legacy properties have obviously contributing to the volumes as well. The question on five acre density is, it's a good one. We have some data. We'll continue to gather data. The initial drilling up here at Stuart Point that we talked about earlier will collect pressure data in the wells that are offsetting these high EUR wells that I mentioned. That will be some initial indication on relative depletion, but then it will take several years of production as we watch these wells to confirm our reservoir model with respect to when these wells start to interfere, et cetera. So I don't think that the results from the five acre density are necessary to update the 2P, 3P thing completely, but it will obviously refine those estimates as we go forward. And as always, we'll tend to be relatively conservative on our view on five acre density and on the ultimate recovery of five acre wells until we have good hard evidence to support it.

Holly Stewart

Perfect, thanks.

Chuck Stanley

Thanks.

Operator

And at this time there are no other questions.

Keith Rattie

I will wrap up by thanking everyone again for listening in on our call. You know how to get a hold of us and you know, how to get access to our slide presentation. There will be a pre-recorded version of this call on our website posted later this week. Again, thanks for listening and thanks for your interest in Questar.

Operator

Thank you for participating in today’s Questar Conference Call. This call will be available for replay beginning at 10:30 AM Eastern standard time today till Thursday, May 1, 2008. The conference ID number for the replay is 30562318. Again the conference ID number for the replay is 30562318. The number to dial for the replay is 1-800-642-1687 or 7066459291. You may disconnect at this time.

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